co2 joint study full

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Opportunities for CO2

Storage

around Scotland an integrated strategic

research study

www.erp.ac.uk/sccs


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University of Edinburgh, April 2009.

A collaborative study published by the Scottish Centre for Carbon Storage

Printed in Scotland by Scotprint, Haddington, East Lothian.

Text and cover are printed on Revive 50/50 which is FSC Cover is laminated with cellogreen gloss

and book can be recycled and is biodegradable.All parts are chlorine free, acid free, recyclable and bio-degradable.


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ForewordRapid man-made climate change is the greatest environmental challenge acing us today. The principal

human inuence on our climate is emission o greenhouse gases, including CO2, rom our use o ossil uels.

The Scottish Climate Change Bill will introduce ambitious legislation to reduce these greenhouse

gas emissions by 80 per cent by 2050. This will highlight many challenges or Scotland, particularly in

terms o addressing our uture energy needs and in generating energy efciently and sustainably in

environmentally neutral ways. We will thereore have to adopt new thinking, new solutions, and new

technologies, and this presents the opportunity to put Scotland at the oreront o building a sustainable

low carbon economy.

A major contribution could be made by the capture and transport o CO2

rom power stations and

large industrial sites, to storage in underground reservoirs oshore thus demonstrating that this

technology can play a key part in our sustainable energy uture.

The Scottish Centre or Carbon Storage has brought together the expertise o a number o our leading

scientists, engineers and technologists rom a range o disciplines and organisations to address the

potential or, and challenges associated with, carbon capture and storage in Scotland.

A key conclusion o the report is that Scotland has not only the storage capacity but also the

geographical context and know-how to become a major hub or CO2

transport and storage in Europe.

Scotland is thereore uniquely placed to beneft rom being an early adopter and, through its world

class science and technology, to be amongst the leading nations involved in the study o carbon capture

and storage, exporting skills and knowledge globally into what could become one o the worlds largestenergy markets.

This is the most comprehensive study o its type undertaken in the UK and I hope that the report

will stimulate urther debate on the way orward or Scotland, in terms o carbon capture and storage

technologies.

Proessor Anne Glover, Chie Scientic Adviser or Scotland.April 2009.


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Scottish Centre or Carbon Storage www.erp.ac.uk/sccs

Contents

Executive summary

The way forward

1 Introduction 14

2 CO2

sources 58

3 CO2

storage sites 916

4 CO2- Enhanced Oil Recovery 1722

5 CO2

injection modelling

within saline aquifers 2324

6 CO2

transport optionsbetween sources and storage sites 2530

7 Economic modelling of potentialCCS schemes in Scotland 3134

8 Business risks faced by earlyCCS projects 3536

9 Business models 3738

10 Funding mechanisms 3941

11 Comparison with other carbonabatement options 42

Concluding remarks 43


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Scottish Renewable Energy Zone (Designation o Area) (Scottish Ministers) Order 2005

area o study


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Executive summaryCarbon Capture and Storage (CCS) is one o the critical technologies worldwide which will enable reduction o

carbon dioxide (CO2) emissions arising rom large industrial sites. CCS allows the continued use o a diverse mix

o energy sources, including ossil uels, which improves the security o cost-eective electricity supply. Scotland

has the opportunity and responsibility to reduce CO2

emissions arising rom burning o ossil uels and their

impact on climate change.

The EU plans to have 12 CCS plants operating by 2015. In February 2009, the UK Secretary o State or Energy

and Climate Change stated an aspiration or the UK to have more than one demonstration project in operation

enabled by government unding. However, these targets cannot be delivered without the underpinning knowledge

rom studies such as this.

Commitment to large-scale investment in CO2

capture plant will require proven storage capability.

This study

presents the frst high-level screening o CO2

storage sites available to Scotland

evaluates the means by which CO2

can be transported rom power plants and other industrial activities to

storage sites, and

investigates the costs and business constraints.

This is the most comprehensive and ully integrated study perormed in the UK, and was achieved by a

collaborative partnership o Scottish Government, research universities and institutes, and a broad base o

support rom industry and business.

The conclusions show that Scotland has an extremely large CO2

storage resource. This is overwhelmingly in

oshore saline aquiers (deeply buried porous sandstones flled with salt water) together with a ew specifc

depleted hydrocarbon felds. The resource can easily accommodate the industrial CO2 emissions rom Scotlandor the next 200 years. There is very likely to be sufcient storage to allow import o CO

2rom NE England,

this equating to over 25% o uture UK large industry and power CO2

output. Preliminary indications are

that Scotlands oshore CO2

storage capacity is very important on a European scale, comparable with that o

oshore Norway, and greater than Netherlands, Denmark and Germany combined.

CO2

storage in oil felds may be easible in conjunction with CO2-Enhanced Oil Recovery (CO

2-EOR). I oshore

pipelines reliably delivering CO2

could be developed through demonstration projects, then an increased number

o oilfelds could become economic or EOR providing other critical actors such as oil price, additional oil

recovery and inrastructure suitability are also avourable. Additional benefts include delayed decommissioning

costs and extended beneft to the economy through development o technology and expertise in oshore CO2-

EOR. However, contrary to many expectations, this study has shown that most oilfelds in the northern North

Sea cannot easily be used solely or CO2

storage because sea water injection, commonly used to maintain feld

pressure during oil production, signifcantly reduces the amount o storage capacity or CO2.

Pipelines are the best option or the secure and continuous transport o millions o tonnes o CO2

rom dierent

CO2

sources to collection hubs onshore and then to oshore storage hubs or local distribution to diverse

storage sites. Several routing options exist and, importantly, can include the connection o pipelines carrying CO2

originating rom England or continental Europe. Capital and operational costs or CCS projects are similar to

those o the hydrocarbon industry.

Electricity generated in Scotland rom power plant ftted with CCS is shown by this study to be comparable in

price to that generated rom other low-carbon technologies. The cost o abatement per tonne o CO2

is cheaper

on coal plants than on gas, because coal produces larger amounts o CO2

per unit o electricity. However, the

cost per unit o low-carbon electricity rom coal and gas CCS is approximately the same.


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The key conclusions o the study are:

1. The amount o CO2

produced rom industrial sources within Scotland is about a tenth o that o

the UK as a whole. Without CCS, Scotland is likely to produce between 300 and 700 million tonnes o CO2

rom 2010 to 2050 that is, on average, between 8 and 18 million tonnes per year (Mt/year) depending on the

proportions and types o power generation. In 2006, CO2

output rom major industrial sources in NE England

amounted to over 50 Mt/year.

2. Geological reservoirs suitable or storage o CO2

are classifed according to whether they contain

(or have contained) oil, gas, or saline water. Saline aquiers have the largest storage potential but with

uncertainties regarding storage capacity o individual sites. From a resource o more than 80 saline aquiers

studied, ten have been identifed with a total potential CO2

capacity in the range 4,600 to 46,000 million tonnes

a capability to store more than 200 years o Scotlands CO2

output rom its major fxed industrial sources.

3. Initial costs o assessing potential saline aquier stores are likely to be considerably higher than or

oil and gas felds which have previously been ully evaluated during many years o both exploration and

production operations. Only detailed appraisal studies that include drilling o boreholes are likely to provide

sufcient confdence to initiate a commercial-scale CCS project. Thus, pilot CO2

capture projects will be an

essential element o developing any new CO2

storage site.

4. From a resource o more than 200 hydrocarbon felds, 29 have been identifed as clearly having

potential or CO2

storage. Four gas condensate felds and one gas feld oer signifcant potential or CO2

storage. However, most o the oil felds can only be used as CO2stores in conjunction with CO

2-EOR technology.

5. CO2-EOR may act as a stimulus or CCS especially i developers come to expect that the price

o oil will remain over US$100 per barrel or the period o their investment. Development o a CCS

inrastructure in Scotland could lead to application o CO2-EOR (and, thereore, additional oil production and

revenue) in certain felds.

6. Storage hubs are proposed to give multiple storage options within a geographical area to reduce

costs and risks to CCS inrastructure. A pipeline network would be used to transport 20 million tonnes/

year o CO2

rom sources to distribution hubs oshore. Capital costs are 0.7 to 1.67 billion, depending on hub

location. The hubs are proposed to give multiple storage options within a geographical area to minimise costs

and risks to CCS inrastructure. The preerred route is through an onshore pipeline rom the Firth o Forth to

St Fergus, then onwards to an oshore storage hub, while an oshore pipeline route rom the Firth o Forth

should also be considered. Transport o additional CO2

rom NE England is best served by a pipeline direct to an

oshore storage hub. Ship transport is possible as an interim solution, ideally discharged at the oshore hub.

7. A phased approach is appropriate to support the development o CCS technology. Direct

Government unding will be required in the short term or R&D and pilot projects. In the medium term, CCSdemonstration projects required under the UK Government and EU programmes, will need income support.

Other low-carbon technologies, such as renewable power generation, currently receive incentives which are

envisaged to continue or the medium term. In the long term, low-carbon generation projects are capable

o being supported by the price o carbon alone. However, the volatility o the carbon market will place an

additional fnancial risk on such projects.

8. The long term carbon abatement cost o CCS coal and CCS gas appear comparable with other

available low-carbon power generation technologies and CCS has the potential to materially contribute to

carbon abatement in Scotland.


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The way forwardScotland has the potential to become a signifcant player in the CCS industry both in its practical application,

using its signifcant oshore resource, and in the development o exportable technology and skills. However,

having examined

the levels o unding required

the levels o risk

the regulatory structures

and potential business models

the study has concluded that CCS will not commence without signifcant Government support and initial unding,

similar to that required to develop low carbon wind and marine technologies. This strategic study has identifed key

initiatives that need to be acted upon to move CCS orward in Scotland.

1. There is a need or more detailed evaluation o Scotlands oshore storage sites. Saline aquiers

represent the major CO2

storage opportunity. For these to be the basis o viable CCS projects there is a

need or detailed mapping and evaluation o specifc saline aquiers, akin to that undertaken by the oil industry

assessing hydrocarbon prospects prior to exploratory drilling. Early assessment will greatly speed-up the

development o viable CCS projects.

2. I CCS projects are to make progress in the short term, there is a need or direct Government

assistance to support R&D activity, which can prove the availability o storage in oshore saline aquiers and

gas felds. I sufcient storage capacity oshore Scotland is proven, then EU-sized transport and storage industries

can develop. In the medium term, income support estimated at 100 M/year is required per project to construct

and operate the number o large projects envisaged in the UK and the EU. This will reduce i the carbon market

price reaches stability at a commercially attractive level, and make CCS a long-term proftable option.

3. New alliances o businesses are needed to deliver CCS as early demonstration projects will ace

uncertainties o cost, technical operation and income. These frst demonstrator projects are essential to start a

process o learning, improvement, and cost reduction. No UK CCS will develop until these demonstrators are

implemented and evaluated.

4. At high oil prices CO2-EOR may lower the overall level o support required or early CCS

demonstration projects, provide incentives or industry development and add volume to Scotlands

hydrocarbon reserves. Projects to assess the viability o CO2-EOR in specifc oil felds or clusters o oil felds

could thereore be important.

5. A CCS transport inrastructure is essential to connect sources with stores. Subject to suitability,existing pipeline networks may be exploited to varying degrees within the context o early pilot operations

through to industrial scale demonstration projects.

6. Political and public support is crucial or progressing CCS. Public investment is likely to be required,

initially at least, to ensure that the inrastructures are established and the private sector receives sufcient

incentive to establish demonstration projects and to develop the technologies. To reduce the fnancial uncertainty

to acceptable levels, additional monetary support is needed, as is given to renewable power generation.

7. The successul development o CCS in Scotland requires an assessment o the existing diverse

skills base to identiy where we need to build expertise. Academia and industry, working with the Scottish

Government, can then address these issues.

8. Initiate an environmental assessment that will engage the relevant agencies and allow early considerationo the environmental issues associated with the deployment o CCS.


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Aerial view o Longannet Power Station. Courtesy o ScottishPower.


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Scottish Centre or Carbon Storage www.erp.ac.uk/sccs1

1| IntroductionThis document reports the results and recommendations o a study o the key issues bearing on the

development and deployment o Carbon Capture and Storage (CCS) technology in Scotland. It was

unded by the Scottish Government and industry, and was conducted by the Scottish Centre or

Carbon Storage in cooperation with key industry participants.

The key issues are:

identiying and assessing potential carbon storage sites in Scotland

appraising Scottish inrastructure and the costs o developing it to enable CCS projects

understanding the regulatory environment or CCS

understanding the economics o CCS projects.

This study has:

identifed the principal sources o carbon dioxide (CO2) that could be captured and stored (that

is, power generation and major fxed industrial plants) throughout Scotland and NE England and

modelled their likely uture emissions

screened potential CO2

storage sites to identiy those that are likely to be sae and commercially and

technically viable

examined the economics and practicality o enhanced oil recovery using CO2 in North Sea oil felds

developed a high-level model or a transport network capable o taking CO2

rom these sources to

oshore CO2

storage sites

examined current and uture regulations that may aect CCS

identifed gaps between the current commercial/fscal conditions and those required to make CCS

commercially viable

created the evidence base and economic models required to support inormed decisions regarding

the early development o CCS inrastructure in Scotland

established the urther steps necessary to make large scale CCS in Scotland a reality.

The results o this strategic study have been derived rom scientifc literature, data rom a variety o

governmental organisations, and calculations and conclusions generated within the study itsel.

It is now established that man-made emissions o carbon dioxide (CO2) are a major contributor to

climate change. Carbon Capture and Storage (CCS) has the potential to enable very large reductions in

CO2

emissions arising rom major industrial sources such as the generation o electricity. CCS is one o

several possible options or reducing the rate o build-up o CO 2 in the atmosphere and should be seenas orming part o an overall CO2

mitigation strategy.


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Adapted from IEA. World EnergyOutlook 2007. Fig 5.12

World CO2emissions

Figure 1

Wedge diagram illustrating proportions o dierent init iativesrequired to reduce CO

2concentration in the atmosphere.

Adapted rom IEA. World EnergyOutlook 2007. Fig 5.12

World CO2emissions

CCS comprises a set o technologies that together enable CO2

to be captured rom industrial point

sources, be processed, transported via pipelines (or ships in certain cases) and injected into deep rock

ormations at 1000 to 2500 m below the Earths surace (Figure 2). At present, a small number o CCS

projects have been initiated within the UK and the EU but as yet there are none within UK waters

o the North Sea. For instance, there are two projects operating within Norwegian waters, one at

the Sleipner Field in the Norwegian sector o the northern North Sea, the other at the Snhvit Field

oshore northern Norway which transports CO2

via a 150 km pipeline to a subsea injection location.

There is also a small scale injection test being undertaken at the K12B Gas feld oshore Netherlands.

This can be illustrated using stabilisation wedges where each wedge represents a strategy to reduce

CO2

emissions (Figure 1). The thickening o each wedge reects take up o the particular CO2

reducing

initiative.


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CO captured at the power plant2

Oil field EnhancedOil Recovery (EOR)Gas field

Saline aquifer

Caprock

Caprock

CO is piped offshore2

CO injection at a rig2

CO is injected underpressure via a well intothe storage site

2

Compression

Oil

CO2

Increasing temperatureand pressure

BritishGeologicalSurvey

Figure 2

Schematic showing elements o CCS inrastructure and

relationship with geological structure.

Although a gas at the Earths surace, carbon dioxide takes a very dierent physical orm under only

slightly changed conditions. Most people are amiliar with the cold, solid orm known as 'dry ice' that

CO2

takes when rozen. By contrast, when placed under moderate pressure (73.7 bar or greater),

and warmed (to greater than 31.1C), it becomes a dense uid with properties o both a liquid

(density) and a gas (viscosity). In this orm, CO2

occupies one hundredth o the volume it does as a

gas. Nevertheless, liquid CO2

(density 0.7 g/cm3) is less dense than water (1.0 g/cm3) and like oil will

oat upon water. Thus some orm o physical containment is needed to prevent upward migration and

leakage in a subsurace store, and the physics o liquid CO2

thereore place depth and temperature, as

well as geological, constraints on any potential storage reservoir (Figure 2). In this dense state, CO2

is

readily and efciently transported by pipeline, as it ows like gas.

Choice o study area

The extent o the study area is shown by the limits o the Scottish Renewable Energy Zone which

spans onshore Scotland and extends to oshore areas and is defned in The Renewable Energy Zone

(Designation of Area) (Scottish Ministers) Order 2005, ISBN 0110736176 (see map acing Contents

page). Although this limit excludes a large number o potential carbon dioxide storage sites it defnes

an area covered by Scottish environmental statutes and as such lies within a legally defned area.

Competition and/or co-operation with other potential carbon dioxide storage sites outwith the area

defned in this study is possible but was not considered in detail in this study. The study ocussed on the

oshore area to the east o Scotland as this is closest to the major Scottish and northern English CO2

sources. The geological ormations with the greatest potential or storage o CO2

are located oshore

and include a large number o hydrocarbon felds and saline aquiers and the data to enable meaningul

assessment.


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Part o the Sleipner Field CCS inrastructure, oshore Norway. Courtesy o StatoilHydro.


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S c o t l a n dS c o t l a n d

E n g l a n dE n g l a n d

N o r t h e r n I r e l a n dN o r t h e r n I r e l a n d

0 25 50 75 100

Kilometers

Longannet

U l s t e r U l s t e r

L e i n s t e r L e i n s t e r

I s l e o f M a nI s l e o f M a n

W a l e sW a l e s

Cockenzie

Peterhead

Greystones

Drax

Eggborough

SaltendFerrybridge

Teeside

Scunthorpe

St Fergus

Stirling

Grangemouth

Mossmorran

Legend

2006 CO2 Emissions (Mt)

0 - 2

2 - 4

4 - 6

6 - 8

8 - 10

10 - 22

The Scottish Renewable Energy Zone

Steel Works

Power Station

Industrial Site

Hunterston

Figure 3

Relative proportions o CO2

emitted by source in 2006 in the UK.

Domestic 14.3%

Commercial and

public services 3.9%

Agriculture and

orestry uel use 0.8%

Transport 23.5%

Power stations 33%

Other energy

industry 5.7%

Other industrial 17.3%

Other sectors 1.5%

Figure 4

Location o industrial sources o CO2

emissions in

Scotland and NE England that emitted more than100, 000 tonnes per year in 2006.

2| CO2

sourcesIn this section, the principal

industrial sources o CO2

(power generation and

industrial plant) in Scotland

and NE England are identifed,

and the levels o output or

sources in Scotland during

2006 are quantifed. Likely

levels o CO2

output are then

estimated or 2020, 2030 and

2040 by considering various

energy generation mixes. This

inormation is used to quantiy

CO2

storage and transport

requirements and to plan a

network inrastructure that will

respond to these requirements.

Scotlands total CO2

emissions in

2006 were estimated to be 44 Mt,

around 8% o the total UK emissions

o approximately 557 Mt. The majority

o the large fxed sources o CO2 arepower generation plants, which give

rise to 33% (~184 Mt) o the UK total;

integrated steel plants and the larger

oil refnery/petrochemical complexes

are urther signifcant sources. O the

remaining sources o emissions, the

largest single contribution was rom

transport (23.5%) (Figure 3).

All the major energy generators andindustrial point sources o CO

2in

England, Wales and Scotland that emit

more than 10, 000 tonnes o CO2

per

year report this output to the National

Atmospheric Emissions Inventory

(NAEI) and the Scottish Environmental

Protection Agency (SEPA) (Figure 4).


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Figure 6

CO2

output at 2020 or

11 Scottish scenarios.

Figure 5

Top ten CO2

sources in Scotland

and northern

England in 2006. Drax Power station 22.4 Mt

Longannet Power station 9.6 Mt

Ferrybridge C Power station 8.9 Mt

Eggborough Power station 7.6 Mt

Scunthorpe steelworks 3.9 Mt

Saltend CCHP 3.1 Mt

Peterhead Power station 3.1 Mt Teeside steel works 3 Mt

Cockenzie Power station 5 Mt

Greystones Power station 4.9 Mt

In 2006, approximately 18 Mt o CO2

(around 41% o Scotlands total carbon emissions) was produced

by Scotlands three largest power stations. The output o Longannet alone is approximately 10 Mt.

A combined total o 71 Mt o CO2

(~24% o total UK fxed industrial) was produced by the top ten

sites in Scotland and NE England (Figures 4 and 5).

For Scotland, the amount o CO2

produced in the uture will largely depend upon the method o energy

generation and the relative proportions o types o energy supplied. Likely levels o CO2

production

were considered or 2010, 2020, 2030 and 2040. For 2010, it was assumed there would be little

change in output rom fgures provided or 2006 (Figure 5). A range o scenarios or CO2

production

in 2020, 2030 and 2040 is summarised below (Figures 6, 7 and 8). For each o these years, dierentenergy mixes were analysed, with no judgement as to which scenario was more likely, and a range

o possibilities presented. (Tables 1, 2 and 3). The scenarios yield high, medium or low CO2

output

reecting the dierent energy mixes. The examples shown in Figures 6, 7 and 8 assume that carbon

capture technology is not installed. Note that i carbon capture equipment were installed, gross (prior

to capture and storage) CO2

output would be higher, by between approximately 12% (CCS mature)

and 25% (CCS immature) reecting the additional energy required to extract the CO2

and puriy it.

However, the extra CO2

produced by the carbon capture process will, by defnition, be captured as

part o this process and should not result in additional CO2

being released into the atmosphere.


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Energy mix Renewables % Nuclear % Coal % Gas % CO2

output Mt

1 30 15 45 10 23.6

2 30 0 35 35 23.3

3 40 0 30 30 19.9

4 50 0 35 15 19.7

5 30 15 27.5 27.5 18.3

6 40 15 22.5 22.5 15.1

7 50 15 17.5 17.5 11.7

8 30 35 0 35 6.4

9 40 35 0 25 4.7

10 65 15 0 20 3.8

11 50 35 0 15 2.8


output Mt

1 40 0 30 30 15.1

2 50 0 35 15 14.1

3 40 15 22.5 22.5 11.5

4 50 15 17.5 17.5 8.9

5 30 35 17.5 17.5 8.9

6 40 35 0 25 4.6

Table 1

Proportions o dierent

energy generation methods

or each o the 11 scenarios

possible or 2020.

Figure 7

CO2

output at 2030 or 6 Scottish scenarios.

Table 2


energy generationmethods or each

o the 6 scenarios

possible or 2030.

For 2030, CO2

production

was calculated on the basis

o electricity demand as at

present. Calculations assuming

a year on year 1% increase o

electricity demand rom 2020

to 2030 were also carried out

but did not change the ranking

o energy mix scenarios.


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output Mt

1 40 0 55 5 18.6

2 40 0 40 20 16.5

3 50 0 35 15 14.1

4 40 0 20 40 13.7

5 50 0 20 30 11.9

6 40 15 20 25 11

7 60 0 20 20 10.1

8 50 15 17.5 17.5 8.8

9 40 35 0 25 4.6

10 60 15 0 25 4.6

11 50 35 0 15 2.8

12 60 25 0 15 2.8

Figure 8

CO2

output at 2040 or 12 Scottish scenarios.

Table 3


energy generation

methods or each

o the 12 scenarios

possible or 2040.

For 2040, CO2

production

was calculated on the basis

o electricity demand as at

present. Calculations assuming

a year on year 1% increase in

electricity demand rom 2030 to

2040 were also carried out but

did not change the ranking o

energy mix scenarios.

CO2

Sourceskey conclusions

For Scotland over a 40-year period rom 2010 to 2050, total output rom electricity generation alone

will produce CO2

outputs o:

~ 700 Mt or 17.5 Mt/year under a high CO2-output scenario;

~ 320 Mt or 8 Mt/year under a low CO2-output scenario assuming no nuclear power.

Additional major sources in NE England produced ~50 Mt CO2

in 2006. Thus, i outputs rom both

regions are included, over the period to 2050, up to 3000 Mt CO2

is potentially available or capture

and storage. This is equivalent to 75 Mt CO2 per year taking this high-case scenario.


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3| CO2

storage sitesTo establish whether the Scottish oshore area has the potential or storing the amounts o CO

2

captured, the study identifed and assessed potential CO2

storage sites in the oshore area in terms o

their relative storage capacities and geotechnical criteria.

Potential CO2

storage sites in the oshore area are:

saline aquiers and;

hydrocarbon felds.

Hydrocarbon felds have, by defnition, the proven ability to trap migrating gas and oil in suitable

reservoir rock or many millions o years. Hydrocarbon felds that may be suitable or CO2

storage are

those that either have ceased production, or will do so within the period covered by the study, or

those that are suitable or enhanced oil recovery using CO2

(CO2-EOR).

Only a relatively small proportion o reservoirs contain hydrocarbon accumulations; the vast majority

o potential reservoir rocks (typically sandstone in the North Sea) are flled with saline water, and these

are known as saline aquiers.

Common to all types o storage site, the key metrics or assessing a potential site are:

location;

data availability;

storage capacity;

geotechnical characteristics o the storage site;

timing o storage site availability.

3.1 Location

The area defned by the Scottish Renewable Energy Zone oshore has been examined (see map

acing Contents page). It contains approximately 204 hydrocarbon felds (comprising 163 oil, 30 gas

condensate and 11 gas felds) and 80 saline aquiers that might be suitable or the storage o CO 2. These

numbers may increase in uture as urther hydrocarbon felds or saline aquiers may yet be discovered.

3.2 Data availability

Eighty (40%) o the known hydrocarbon felds and twenty-one (26%) o known saline aquiers were

not screened and assessed because o various issues such as lack o readily available data, confdentiality,

time or budget (Figures 11 and 12). Many o these sites could be suitable or CO2

storage.

Nevertheless, the storage sites remaining are considered to be representative o the whole area and

include a large proportion o the potentially available capacity. Additional data rom companies and

government may well augment this list o potential storage sites as well as improve our understanding

o those already identifed.


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British Geological Survey

Figure 9

Cartoon illustrating porosity and permeability within the reservoir volume.

3.3 Storage capacity and suitability

The CO2

storage capacity o a

hydrocarbon feld or saline aquier

depends upon several actors. The

total volume o the storage

reservoir is relatively straightorward

to determine, provided appropriate

data is available. At a microscopic

scale, reservoir rocks (or example,

sandstones) contain spaces (between

sand grains) within which uids can

be stored, or through which uids

can pass (Figure 9). The proportion

o the total volume available or uids

is its 'porosity', and the ease with

which uids can pass through rock is

described by its 'permeability'.

These spaces are flled with either hydrocarbons (oil, gas or gas condensate) or saline water. These

uids are all pressurised to a certain degree and must be displaced to allow storage space or CO2.

Thus, it is important to distinguish whether a reservoir is in open pressure communication with

surrounding rocks or whether it is closed.

For oil felds not in pressure communication (closed), water is oten injected to pressurise the

reservoir and produce oil. Once production has ceased, much o the oil has been replaced by water

but the reservoir may still be under high pressure. CO2

injection will cause urther pressurisation.

This places signifcant limits on the amount o CO2

that can be stored in this type o reservoir, since

excessive pressure may ultimately cause racturing o the caprock. The capacity available or CO2

can

be increased by permitting urther uid production, either o additional oil or o the water previously

injected which would require clean-up by extracting oil to meet current environmental standards prior

to discharge to sea.

For gas and gas condensate felds the situation is dierent (even i closed) as production is usually

driven by expansion o the gas without the need or water injection to maintain pressure. Thus

pressure is likely to be very low by the time these felds become ready or CO2

storage.

For closed saline aquiers pressure will again be the signifcant limiting actor. This was confrmed by

numerical modelling carried out or this study and summarised later in this report (Section 5). Water

production may be required to control pressure increase.

CO2

injected into open reservoirs is accommodated by lateral displacement o the existing uids,

and gives rise to minimal, local changes in pressure. The storage capacity oopen saline aquiers is

limited by how well the CO2

displaces the saline water (its sweep efciency), the proportion o the

saline aquier that is structurally closed (trapping the CO2) and the amount o CO

2retained during

migration. Open reservoirs oer better potential or CO2

storage.


20/56


For the purpose o this strategic

study, storage capacity was

calculated at a basin-wide scale.

This provides a ranking o potential

storage sites but not absolute

capacities. The best estimate o

storage capacity o each reservoir

will be refned as assessment

becomes more ocused (Figure 10).

For hydrocarbon felds, this basin-

scale assessment enabled a ranking o

their storage capacity. Following this

analysis, the 95 hydrocarbon felds

o estimated capacity less than 50

Mt CO2

were considered too small

to be viable or CCS storage and so

were not examined urther (Figure

11). Note that stores with less than

50 Mt CO2

storage capacity may have

value as satellites to larger sites or

as part o a pilot or smaller scale demonstration project. Pressure-related issues urther constrain the

possibilities o using oilfeld reservoirs or CCS.

The majority o oil felds in the Scottish oshore area are closed and would require signifcant

production o uids (mainly previously injected water) to enable secure injection o signifcant

quantities o CO2. This is unlikely to be practical except in combination with enhanced oil recovery

(CO2-EOR). As part o this study, oil felds were assessed or their suitability or CO

2-EOR and this is

detailed in the next section entitled CO2ENHANCED OIL RECOVERY (Section 4).

The Brent Oil Field is a possible exception as pressure support has been withdrawn and water

produced in order to drop the pressure and release the gas contained within the remaining oil. As a

result, there may be a CO2

storage opportunity once depressurisation is complete and production has

ceased (Table 4).

For gas and gas condensate felds, ewer limitations due to pressure in the reservoir are likely to

be present. In all the gas condensate felds listed, there is minimal water replacement on production

o hydrocarbons. Consequently, a large proportion o the pore space will be available or CO2

storage.

However, three o the gas condensate felds, classifed as High Pressure High Temperature (HPHT)

felds, are likely to be too costly to develop as CO2

stores. In the Frigg Gas Field, water is used to drive

the gas and consequently a smaller proportion o the available pore space will be available or CO2

storage (Table 4).

UncertaintySt

orageVo

lume

Country/StateScale Screening

BasinScale Assessment

Site Characterisation

Site

Deployment

Prospective

Storage Cap

Contingent

Storage Capacity

Operational

Storage CapacityDecreasing

Uncertainty

and Storage

Volume

Increasing

Data and

Eort

Adapted rom CSLF 2007 Storage Pyramid

modied 2008 CO2CRC

Storage Capacity Estimation

Total Pore

Volume

Figure 10

Storage pyramid illustrating dierent stages in CO2

storage capacity assessment. This study takes the

assessment to near the top o basin-scale.


21/56


204 hydrocarbon elds identied

within area o study

80 hydrocarbon elds

excluded through lack

o data

29 hydrocarbon elds taken

orward or assessment

95 hydrocarbon elds excluded as

storage capacity less than 50 Mt

Figure 11

Numerical breakdown o the 204

Hydrocarbon elds identied within the

study area showing proportion o elds

taken orward or assessment.

Field name Verticaldepthto crest

(m)

AveragePorosity(%)

AveragePermeability(milli-Darcies)

Close oProductionyear

Averagewaterdepth(m)

EstimatedCO2 Storage(Mt)

Brae North GC 3633 15 300 2015 99 52

Franklin GC HPHT 5050 16 10 2030 93 62

Elgin GC HPHT 5300 17 25 2030 93 63

Shearwater GCHPHT

4700Not

availableNot

available2015 92 66

Brae East GC 3865 17 558 2020 116 111

Britannia GC 3597 15 60 2030 136 181

Bruce GC 3250 15 153 2020 122 197

Frigg (UK) Gas Field 1785 29 1500 2008 112 171

Brent Oil Field 2512 21 650 2015 140 456

Table 4

Hydrocarbon elds assessed as having potential or CO2

storage alone.

In summary, basin-scaleanalysis was used to identiy

29 hydrocarbon felds with

apparent potential or CO2

storage (Figure 11). O these,

our gas condensate felds (Brae

North, Brae East, Britannia and

Bruce felds), one gas feld (the

Frigg Field, UK) and one oil feld

(the Brent Field) present the most

obvious opportunities as stores (Table 4) with total CO2 storage capacities o between 300 to 1000 Mt. Therange o storage potential values reects uncertainty with regard to assumptions in the calculation o storage

capacity. The three HPHT gas condensate felds (Franklin, Elgin and Shearwater felds) are likely to be too

expensive to develop as stores in the short term (Table 4). Fourteen oil felds, including the Brent Oil Field,

have potential or CO2storage in conjunction with Enhanced Oil Recovery (see ollowing section 4). The

remaining seven oil felds oer large storage capacities but reservoir pressure issues may present obstacles

to their use or CO2storage (Figure 13).

Green parameter is technically or economically avourable

Orange parameter is technically or economically borderlineRed parameter is technically or economically unavourable

GC = Gas Condensate feld

HPHT = High Pressure High Temperature feld


22/56


Reservoir Attribute Best practice requirements Minimum technicalrequirements

Depth >1000 m and < 2500 m >800 m and 500 mD >200 mD and 20% >10% and


23/56


Saline aquier Area (km2) CO2

storage capacity (Mt CO2)

assuming 0.2% storage efciency

CO2

storage capacity (Mt CO2)

assuming 2% storage efciency

Forties 16069 886 8856

Grid 17147 785 7847

Balder 6251 347 3465

Flugga 1926 61 611

Frigg 1712 58 575

Mey 33190 1655 16549

Heimdal 11065 618 6177

Tay 2484 133 1328

Captain 3438 36 363

Mains 4601 24 241

Total CO2

storage capacity (Mt) 4603 46012

Table 6

Saline aquiers assessed as having potential or CO2

storage showing

the range o potential storage capacities calculated rom storage

eciencies derived rom regional studies and numerical modelling.

3.5 Timing o storage site availability

As a practical working assumption, unless a hydrocarbon feld is to undergo CO2-EOR storage, CO

2

storage cannot begin until production ceases. Close o production (CoP) or all hydrocarbon feldswas estimated rom past production data (Table 4). For oil felds the CoP is o limited relevance, as use

or storage without EOR is unlikely and CO2-EOR will necessarily begin prior to the estimated closure

date. It has been assumed that there are no timing restrictions governing the availability o saline

aquiers, although exploration and appraisal o saline aquiers may take a number o years. One o the

most pertinent issues or the development o a CCS transportation pipeline involving hydrocarbon

stores is the matching o timing o CO2

supply (rom onshore sources) with available injection

and storage capacity. Re-use o hydrocarbon production acilities may be an option in some cases.

Historically, close o production orecast dates have tended to be unreliable, and depend on technology

development, oil and gas prices, inrastructure lietimes, and other market actors.

Oil & gas felds are currently better characterised in terms o both capacity and integrity than are saline

aquiers so initially involve lower cost and risk. Without Enhanced Oil Recovery, oilfelds oer limited

capacity due to the past replacement o produced oil with water or pressure support. Depleted gas

and gas condensate felds oer good storage capability, although there are relatively ew in the

Scottish Renewable Energy Zone. Storage o CO2

in the oshore Scottish Renewable Energy zone is

likely to be initially in depleted gas and gas condensate felds and in the ew oil felds where pressure

conditions are avourable, whilst long-term storage and the majority o storage capacity potential is

likely to be in saline aquiers.


24/56


Inverness

Aberdeen

GlasgowEdinburgh

Figure 13

The location o all 29 hydrocarbon elds and 10 saline aquiers

identied as potential CO2

storage sites within the Scottish oshore.

Risks and uncertainties are associated with all types o subsurace CO2

storage reservoir, but

with appropriate, storage site specifc, appraisal it should be possible to reduce these to the level

appropriate or business investment in and regulatory approval o a project typical o the oil and gas

industry. It is likely that appraisal costs to reach this position will be higher or saline aquiers than or

oil and gas felds, although saline aquier capacity or storage is also likely to be correspondingly greater.

All 29 hydrocarbon felds and ten saline aquiers identifed in this study as having the potential to store

CO2, either as part o an EOR project or purely as part o a CO

2mitigation strategy are shown in

Figure 13. The ten saline aquiers are colour coded according to whether they meet minimum or best

practice geotechnical requirements (Table 5). They each have a unique size and shape, and the majority

cover areas o several thousand square km. In some places, the saline aquiers overlap each other, being

present at dierent depths at the same geographical location. The circles in Figure 13 denote their

approximate central points.


25/56


CO2

storage siteskey conclusions

Basin-scale assessment has demonstrated

From this frst assessment, ten saline aquiers have been identifed with a total CO2

storage

capacity o between approximately 4,600 and 46,000 Mt, providing a capability to store at least200 years o Scotlands CO

2output.

Further study is necessary to ully scope saline aquier storage potential.

29 hydrocarbon felds (21 oil, 7 gas condensate and one gas feld) oer signifcant urther CO2

storage potential. Amongst these:

8 Gas and gas condensate felds oer the best potential or storage;

Three high pressure high temperature gas condensate felds are unlikely to be used as

storage sites due to prohibitive costs;

Oil felds are unlikely to be employed as CO2

stores except in conjunction with Enhanced

Oil Recovery;

The one remaining gas and our remaining gas condensate felds oer total ~ 700 Mt CO2

storage potential;

Unusually, the Brent Oil Field oers an opportunity or CO2

storage o ~ 400 Mt.

The potential storage capacities as currently assessed are sufcient to provide an approximate

ranking o sites in terms o their storage potential but sites need to be evaluated individually using

more detailed models.


26/56


Figure 14

Oil elds suitable or CO2-EOR. Blue ovals show extent o detailed EOR study.

4| CO2 Enhanced Oil Recovery

The study assessed how enhanced oil recovery (EOR) by CO2

ooding (CO2-EOR) might either beneft

rom or be a beneft to CCS. It identifed oil felds within the Scottish Renewable Energy Zone, in

which CO2-EOR was technically easible, and a more detailed technical and economic assessment o a

single feld and feld cluster was carried out (an exchange rate o $1.4/ was used).

CO2-EOR oers potential o economic gain through additional oil production as well as storage o the

CO2. On average, primary and secondary oil recovery by water ood rom North Sea oilfelds accounts

or 45% to 55% o oil originally in place, although in some felds it has approached 70%. The residual

oil is trapped as by-passed droplets in the rock pores or as a flm on the rock grains and may occur

as localised signifcantly higher saturation areas. EOR processes, employed as a third phase o oil feld

development, seek to mobilise this oil and move it in a 'bank' towards the production wells. However,

CO2-EOR is one o a number o competing 'Enhanced Recovery' techniques and to date has not been

applied in the UK oshore.


27/56


Field name CO2

storagecapacity/Mt CO

2

Close oProduction date

Potentialor EOR

Projected additional oilrecovered

(million barrels)

Dunlin Oilfeld 27 2015 Good 83

Thistle Oilfeld 27 2015 Good 82

Claymore Oilfeld(Central, Main andNorthern)

47 2030 Good OK 142

Cormorant Oilfeld 52 2020 Good 157

Scott Oilfeld 31 2015 Good 95

Statjord(UK) Oilfeld

209 (UK + Norway) 2020 Good 635 (UK + Norway)

Beryl A Oilfeld 77 2020 Good 232

Ninian Oilfeld 96 2030 Good 292

Brent Oilfeld 165 2015 Good 501

Murchison(UK) Oilfeld

26 2020 OK 79

Miller Oilfeld 17 2008 OK 52

Buzzard Oilfeld 36 2025 OK 108

Piper Oilfeld 46 2030 OK 140

Forties Oilfeld 138 2015 OK 420

Table 7

Oilelds identied in a desk top review as

having potential or CO2-EOR.

The majority o CO2-EOR projects worldwide to date have been implemented onshore in North

American oilfelds since the 1970 s and it is experience rom these or which most relevant guidelines

have been drawn up. No projects have yet been undertaken in the North Sea, although the Miller

oilfeld was recently considered or CO2-EOR. Most existing North American projects have exploited

natural CO2

transported over extensive long-distance pipeline networks. Under these circumstances,

an additional recovery o 5% to 15% o oil originally in place is typically achieved. The technique may not

be as productive in North Sea oilfelds, because secondary water ood recovery techniques are more

widely applied, and wells are drilled urther apart than on land.

A high level desk-top review o all oil felds with an estimated CO2

storage capacity o >50 Mt was

carried out to identiy those felds suitable or CO2-EOR. The 14 felds are shown in Figure 14 and

their details are tabulated in Table 7.


28/56


Figure 15

Estimated CO2

injection and recycle gas injection proles or the Claymore Field.

To gain a more quantitative eel or the application o CO2-EOR in North Sea oil felds, a technical

and economic assessment o a single large feld, the Claymore Field, was carried out (highlighted

in Figure 14). Additionally, a cluster o three large felds, Claymore, Scott and Buzzard (highlighted in

Figure 14), were assessed as an integrated CO2-EOR project. In all cases CO

2-EOR was assumed to

begin in 2017 (although Buzzard will not become available until 2023).

The oil in Claymore is contained in our separate reservoirs. The total oil initially in place was

1439 million barrels. For this study two possible scenarios were considered, a less likely scenario (30%

probability) and a more likely scenario (70% probability) with the ormer yielding an optimistic and the

latter a pessimistic recovery o additional oil. Starting in 2017, CO2

would be injected at ~ 3.8 Mt/year

with produced and recycled CO2eventually negating the capacity to take new CO

2. Overall, the project

would store 49.2 Mt CO2and produce between 119 and 163 million barrels o oil (Figure 15; Table 8).

Capital costs (CAPEX) are derived rom the cost o converting existing acilities and the drilling and

reurbishment o new and existing wells. Total capital investment is estimated to be around 1.1 to

1.2 billion. Operating and monitoring costs (OPEX) are estimated to be around 90 million per year.

Using an oil price o 50 (US$70) per barrel, and assuming that the project neither receives a subsidy

nor pays or the CO2

received, the internal rate o return is 12%16% and the net present value

at a 10% discount rate is 206703 million (lower and upper values correspond to the lower and

upper values o additional oil recovered). All analysis is beore tax and any beneft rom deerral o

abandonment o the acilities is not included.


29/56


70 % probability scenario Gross Net*

Additional oil (million barrels) 164 119

CO2

Injected (million tonnes) 49.2

CO2 usage (tonne/barrel) 0.41

Recycle CO2

(million tonnes) 151.5



CO2

Injected (million tonnes) 49.2

CO2

usage (tonne/barrel) 0.30

Recycle CO2

(million tonnes) 151.5

70% probability scenario

Additional oil (million barrels) 71

CO2

Injected (million tonnes) 52

CO2


30% probability scenario

Additional oil (million barrels) 101

CO2



Table 8

Claymore Field - additional oil production and CO2

usage

or 70% and 30% probability scenarios.*amount o oil produced rom CO

2alone without

contribution rom associated waterfood.

Table 9

Scott Field additional oil production and CO2

usage

or 70% and 30% probability scenarios.

Sensitivity (to CAPEX, OPEX, oil price and CO2

price/subsidy) calculations on the discounted

cash ow analyses showed that project economics were most sensitive to oil price, then CO2

price/

subsidy, then CAPEX, and relatively insensitive to OPEX. Although oil and CO2

price are subject to

market orces, this analysis showed that project economics can be improved considerably by refning

the design and thereby reducing capital costs and risks associated with conversion o acilities and wells

to CO2

ooding.

4.1 Claymore, Scott and Buzzard cluster evaluation

An analysis o CO2-EOR as an integrated project was carried out using the Claymore, Scott and

Buzzard felds (highlighted in Figure 14).

The Scott Field has two oil reservoirs divided by aults into several isolated blocks. The feld is

signifcantly overpressured. Total oil originally in place was 946 million barrels. Note that the CO2

use

is much higher in Scott than or Claymore because o the signifcantly higher pressure in Scott and so

higher CO2

density (Table 9).

Capital costs or the Scott Field are estimated at

1.2 billion with operating costs, excluding taris, o

around 45 million per year.

Buzzard is located in the Outer Moray Firth. Fluids

are contained by a combination o structural and

stratigraphical trapping. Total oil originally in place

was 1077 million barrels, taken rom published

inormation. Forecasts have been downgraded by

40% in the economic analysis over concerns that the

CO2

may not mix with the oil in a way benefcial to

the EOR process (Table 10).


30/56




CO2





CO2


CO2


Table 10

Buzzard Field additional oil production and CO2

usage

or 70% and 30% probability scenarios.* amount o oil produced rom CO

2alone without

contribution rom associated waterfood.

The presence o acilities or dealing with hydrogen sulphide or sour gas is likely to reduce the cost

o adapting Buzzard to CO2

injection so, or the purposes o this analysis the capital cost o conversion,

is estimated at 700 million. The operating costs or Buzzard, excluding taris, are estimated at55 million per year.

Aggregated results or this cluster o large felds give an additional oil recovery o 237331 million

barrels or around 155 Mt o CO2

stored. The aggregated capital cost o the cluster redevelopment

would be around 3.1 billion with total operating costs over the project lietime o 2.6 billion.

Using a 50 (US$70) per barrel oil price, and assuming that the project neither receives a subsidy nor

pays or the CO2

received, the internal rate o return is 13%18% and the net present value at a 10%

discount rate is 4091717 million.

The economics o exploiting CO2-EOR in the northern North Sea have been examined in somedetail. The combination o high capital requirements, high operating expense and relatively limited

amounts o remaining oil gives rise to considerable sensitivity to both oil prices and the cost o CO2

used or injection. CO2-EOR may act as a stimulus or CCS especially i developers come to expect that

the price o oil will remain over US$100 per barrel or the period o their investment. Higher oil prices

would make CO2-EOR projects more commercially viable and with that, the independent development

o CCS. To date, the closest CCS has come to being realised in the UK is through a proposed CO2-

EOR project (Miller Field) but the project was ahead o the political process and the feld had to

move to decommissioning beore a government decision on policy support . However, development o

CCS could lead to the application o EOR, since this reduces costs and uncertainties related to CO2

supply.

Power stations will produce a airly constant supply o CO2

over many years. This study examined the

CO2

supply required or Enhanced Oil Recovery projects or a cluster o three large oil felds. Taking

the three felds together, the supply o CO2

required was substantial, approximately 11Mt/year or

13 years, and comparable to the output rom a power station source.


31/56


CO2-enhanced oil recoverykey conclusions

Ignoring risk premiums, and i the CO2

is not a cost to the project, CO2-EOR may be economic in

North Sea oil felds at an oil price o US $70 per barrel.

I CO2 is a cost to projects in the 2040 ($28$56) per tonne range, an oil price o US $80$110 per barrel will be required to break even.

I a subsidy is available or the CO2

stored then the project could be economic at an oil price

signifcantly lower than US $70 per barrel.

Taking risks into account, it is unlikely that CO2-EOR will be commercially viable in North Sea

felds at an oil price less than US $100 per barrel.

The redevelopment o a mature North Sea feld or CO2-EOR is a major undertaking equivalent in

complexity, scale and cost to the original development; each project will need to be the subject o

detailed engineering design and economic appraisal including a ull assessment o the risks.

CO2-EOR has never been applied oshore so early projects will carry signifcant additional

fnancial risks.

The total CO2

storage capacity o all felds to which CO2-EOR might be applied is ~1000 Mt.


32/56


5| CO2

injection modellingwithin saline aquifers

In order to better understand how the available storage volume within a saline aquier might be

aected by injection o large amounts o CO2

the Tay Sandstone saline aquier (Figure 13) was selected

or urther study. Key issues governing whether large volumes o CO2

can be saely, reliably and

securely injected into and stored within a saline aquier were investigated by modelling the injection

o CO2. The main areas o investigation were the potential o the saline aquier to store the specifed

volumes o CO2, the injectivity (including the number o wells required), the eect o orientation and

location o wells, and the migration path o CO2

away rom the injection points. Sensitivity to injection

rate, the number o wells, length, and spacing and location o wells were investigated. Two CO2

injection scenarios were investigated addressing sources rom Scotland and imported CO2:

a baseline case o 15 Mt/year

a high-use case at 60 Mt/year.

5.1 Storage capacity o the Tay saline aquier

Numerical modelling o the amount o CO2

that can be stored in the Tay saline aquier gives a wide

range o possibilities according to whether the saline aquier is considered open or closed. It is not

yet clear which is the case. For this study, the Tay saline aquier was modelled or both scenarios.

Tay saline aquier open (water naturally migrates out o the saline aquier) at an injection rate o

15 Mt/year or 25 years, the saline aquier can readily store 375 Mt CO2.

Tay saline aquier closed (water does not migrate out o the saline aquier) the saline aquier

can store 375 Mt CO2

provided water is produced at a rate o 40, 00060, 000 m3/day.

Without water production it can store only 155 Mt CO2

(0.4% o total pore volume) because o the

increase in pressure as the CO2

is injected.


33/56


5.2 Investigation o sensitivities in modelling the saline aquier

Although the total volume o CO2

injected at 15 Mt/year or 25 years injection is less than 1% o the

total volume o water in the Tay ormation, the average reservoir pressure increased 50% by the

end o the injection period. The pressure then reduced gradually as the CO2

dissolved in water.

The injectivity o the Tay saline aquier is very good, based on the reservoir properties collected

rom current oil felds.

Injection pressure varies with the porosity, permeability and the amount o reservoir rock.

To reduce pressure at the injector well, additional injectors are recommended or the 15Mt/year plan. The injection rate or one well should be less than 6 Mt/year.

Unless it is open, injection o 60 Mt/year CO2

over 25 years into the Tay saline aquier is likely to

lead to excessive pressure.

The movement o CO2

within the saline aquier can be controlled by appropriate location o

injector wells.

Injected CO2

tends to move higher within the reservoir, but when it dissolves in water it tends to

move downwards.

I producing hydrocarbon felds are connected to the saline aquier, and CO2

is injected into their

vicinity, the CO2

tends to move towards them, as they may be at a lower pressure than the saline

aquier, and are usually higher on the structure.

The presence o a relatively impermeable layer within the saline aquier did not act as a signifcant

barrier to the lateral movement o CO2.


34/56


Tier Sourcecategory

Source size (TonnesCO

2/year)

Examples

0 Large > 1 million Coal fred power station, hydrocarbon refnery, major chemicalworks

1 Medium 50,000 to 1 millionChemicals, glass, ood manuacturers, large Combined Heat & Power(CHP) & Combined Cycle Gas Turbines (CCGTs)

2 Small 1,000 to 50,000 CHP units, incinerators, small to medium industrial works

Table 11

Source categories dened as Tiers with examples.

6| CO2

transport options betweensources and storage sites

Successul implementation o CCS in Scotland will require a suitable transport network or CO2.

This study examined options or transporting CO2

between the sources and storage sites identifed.

Various onshore and oshore routes and technologies were examined. The latest UK and international

codes and standards applicable to CO2

pipelines were used.

Sources were categorised according to their output per year (Table 11). The tiers provide some

indication o the potential or applying a CCS solution at each level and are linked to emission

allowances allocated under the European Union Emissions Trading Scheme. Large (Tier 0) sourcesare recognised as the primary ocus or any CCS scheme as the cost o allowances under European

Union Emissions Trading Scheme should make it more economical to store the carbon than to pay

or or trade any excess over the emission allowance. The CO2

transportation network will be built

around these centres. Medium (Tier 1) sources may be less economically suited to a CCS solution.

Their location is likely to determine whether they are included in the network. For instance, oshore

installations (Medium (Tier 1) sources that produce in total 23.7 Mt/year o CO2) are not included in

the example network discussed below. It is unlikely to prove either practical or economic to include

most small (Tier 2) sources in a CCS scheme.

All large Scottish sources are located along the Firth o Forth except the gas-fred power station atPeterhead. Several medium sized (Tier 1) clusters could easibly be associated with the large sources.

For example, St Fergus Gas Terminal naturally links to the large Peterhead source and plants at Stirling

and Mossmorran to the large Longannet power station (Figure 4). Future projects, such as replacement

o power generation at the Hunterston Nuclear site, were not added to CO2

volumes but network

access was modelled, and replacement o existing plant was included.


35/56


6.1 Network design

A well-developed oil and gas pipeline transport inrastructure is present throughout the onshore

UK and the oshore UK Continental Shel. Parts o this inrastructure may become available or re-

use and potentially could be used to transport CO2. For example, a previous proposal demonstrated

that the pipeline rom the vicinity o Peterhead to the Miller feld is technically capable o carrying

a substantial volume o CO2. It could well orm a key element in any uture oshore CO

2pipeline

network and the potential or its use in this context should be examined in detail as a priority.

However, re-use o onshore and oshore pipelines raises major issues related to change o use in areas

o planning, capacity and saety, in addition to various technical questions. Assessing the possibility o

re-using each pipeline or CO2

transport would require a line by line analysis and is beyond the scope

o this study. However, in broad terms, and dependant upon pipelines becoming available, oshore

pipelines are more likely to be suitable or re-use, whereas onshore, the potential or re-use will be

more restricted. Importantly, sections o the onshore National Transmission System (NTS) could

be used as part o a start up or phased approach while gas ow is low. Thus, taken together, use

o existing onshore and oshore pipelines may be viable or the small volumes (~3Mt/year) o CO2

required or a demonstration project.

The design o a network or Scotlands CCS system thereore reects the location o the key large

(Tier 0) emitters, all but one clustered around the Firth o Forth, and the various CO2

storage options

in the Scottish defned oshore area. These groupings and the distances between them naturally

suggest an approach consisting osource hubs connected by a transport spine to storage hubs. The

presence o a hub near several storage sites allows a variety o storage technologies (saline aquier,

depleted hydrocarbon feld or CO2-EOR) to be pursued as opportunities permit, thereby lowering risk.

Four storage hub locations were chosen to permit examination o relative transport costs between

various areas and the eect o various assumptions about the re-use o existing inrastructure.

The storage hubs are named ater local oil felds (Captain, Dunbar, Brae and Gannet; Figure 16) and are

not necessarily optimal.

6.2 Transport options

The viability o transport by pipeline and ship were both assessed. Pipeline design is a complex issue

with many actors aecting the building o this inrastructure. A CO2

pipeline system must be able to

accommodate the ull range o conditions rom ast ramp up rates and shut-downs o power stations

and the closure o geological storage sites. It must accommodate varying ows, surges and variations in

composition o the CO2

uid itsel. Key issues unique to CCS are:

chemical and physical properties o the CO2 including any impurities within the CO2 stream;

consideration o pressures, to maintain the CO2

in the required phase throughout the network

without exceeding sae levels at other points;

legislation specifc to CO2

including UK Health and Saety requirements and international codes o

practice.

A pipeline operating pressure above 100 bar is desirable with a minimum pressure o 90 bar in order

to prevent phase change within the pipe. This maintains the CO2

well above its critical point pressure o

73.9 bar. This pressure margin also allows or a degree o contamination o the CO2 stream.


36/56


Network Option

1Peterhead to Forth (Longannet) onshore pipeline

2Forth to Peterhead onshore pipeline

3Forth (Longannet) with oshore pipeline route to Peterhead

4Full network

5Shipping rom Forth to Peterhead hub

6Tyne/Tees direct to oshore storage hubs

Table 12

Summary o possible transport options

identied through consideration o the

locations o CO2

sources and potential

storage sites.

Although elements within the National Transmission System onshore pipeline system may be available

and suitable or use within a CO2

pipeline network, this possibility was not considered within the

economic assessment discussed below.

In terms o the technical and economic viability otransporting CO2

by ship, this study ocussed on

transport o captured CO2

rom a location in the Firth o Forth to the Peterhead area (Figure 16). The

assessment was limited to vessel access, berthing and ship support services only. No account was taken

o any specialist storage tanks, pressure and cooling systems necessary or loading and discharge o the

CO2. Note that, to minimise disruption to the capture process, storage tanks should be sufcient to

allow 50% redundancy over and above the ships cargo capacity.

The model or costs o transport by ship assumes newly designed vessels o 18,000 m3 capacity, total

cargo pumping rate o 1,500 m3/hr, no waiting on tides, and that discharge occurs in Peterhead Harbour

(although discharge at an oshore location would considerably reduce overall harbour costs). A eet

o our vessels would allow in excess o 13.5 Mt o CO2

to be transported per year. Transportation

cost would be in region o 4.57 per tonne. The capital cost or the vessels, whether new build or

converted, has not been included in the cost model. In the fnal analysis, fve possible transport options,

each with the same oshore storage hubs, were identifed and costed. Options or transporting CO2

rom the Tees/Tyne area were also assessed (Table 12).

Assessment o transport options

Assessment o the fve pipeline and shipping options or transportation o CO2 shows that they arewithin the scope o costs or a major inrastructure project.

The option using ship transport, a oating pipeline, is easible and may be comparable to pipeline

options in terms o capital cost, but with up to our times higher operating expense.

A more detailed examination would be required to accurately dierentiate between the onshore and

oshore routes rom the Forth to Peterhead (options 2 and 3).

This appraisal does not consider a phasing o the construction o the network but assumes a

relatively quick build-up to ull capacity due to the small number o large sources.


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Figure 16

Summary o proposed CO2

transportation routes.

The implications oimporting CO2

rom areas outside Scotland were investigated by examining the

route rom the TeesTyne area to storage sites oshore Scotland (Option 6). Linking directly into a

pre-existing network within Scotland would be costly in terms o both capital and operating costs, not

least because pipelines are complex systems. This study suggests that multiple eeder pipelines rom

the onshore clusters to the oshore storage sites is likely to oer a more cost-eective solution with

CAPEX ranging rom 1.4 to 2.3 billion and OPEX ranging between 27.5 to 53.5 million dependingon storage hub destination. Whilst this introduces complexity into storage management, it allows or

much more exibility in phasing construction and operations.

Figures 17 & 18 show the costs o the various options. Option 2 (onshore pipeline) orms the lowest

cost option in terms o capital expense (CAPEX) or all oshore hubs and the lowest cost option in

terms o operating expense (OPEX) or all except the Gannet hub where Option 3 (oshore pipeline)

is slightly less. Captain is the lowest cost target or Option 2. The overall costs o Options 2 and 3 are

comparable. Option 3 is slightly more expensive, but constitutes a viable alternative to an extensive

onshore pipeline. Option 1 (principal pipeline rom the Forth to the oshore hubs) and Option 4 (ull

network) are more costly than either Option 2 or Option 3. The capital costs o shipping Option 5,are comparable with those o the other options, but the high operating costs and risks suggest that it is

unlikely to prove a viable long term solution.


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Figure 18

Operational expenditure or the ve CCS network options

investigated or each oshore hub (in Million per year).

Figure 17

Capital expenditure or the ve CCS network options investigated

or each oshore hub (in Billion).


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CO2

transport options between sources and storage sites key conclusions

Five network options, linking CO2

source and storage hubs have been identifed and a technical

and economic assessment undertaken.

A sixth option, importing CO2 rom NE England was also investigated. Here, multiple eederpipelines to oshore hubs are likely to orm a more appropriate means o accepting additional

CO2

rom NE England rather than attempting the technically complex option o connecting

directly into a pipeline network within Scotland.

Some re-use o acilities is possible, especially in the early stages o CCS projects.

The potential or using the Peterhead to Miller pipeline and the National Transmission System

inrastructure as a key element o a Scottish CO2

pipeline network should be examined in detail.

A pipeline network used to transport 20 million tonnes/year o CO2

rom sources to the storage

hub at CAPEX costs o 0.7 to 1.67 billion and OPEX costs o 38 to 74 million dependingon hub location and excluding the shipping option. OPEX or shipping ranges rom 148 to 171

million depending on hub location.


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No. DriverSource

Non-CCSTechnology

CCS Technology StorageHub

Primary transport required

1 Longannet2.4 GW

supercritical coal

2.4 GW supercriticalcoal with postcombustion capture

Brae

Forth hub (vicinity oLongannet) to Brae withalternatives o new and existing(Miller) pipeline

2 Longannet2.4 GW

supercritical coal


GannetForth hub to Gannet with newpipeline

3 Peterhead 1.2 GW CCGT*1.2 GW CCGT withpost combustioncapture

BraeN.E Scotland hub (vicinity oPeterhead and St Fergus) toBrae via existing Miller pipeline

4 Longannet2.4 GW

supercritical coal


Gannet

Import o CO2

rom N.E.England hub (vicinity o Blythe/Lynemouth) connected intoScottish Network using newpipelines

5 Peterhead 1.2 GW CCGT*1.2 GW CCGT withpost combustioncapture

CaptainN.E Scotland hub to Captainusing new pipeline

CCGT

*

, Combined Cycle Gas TurbineGW, Gigawatt

Table 13

CCS schemes selected or economic analysis.

7| Economic modelling of potentialCCS schemes in Scotland

Economic modelling o possible CCS projects in Scotland was carried out to compare costs

with conventional non-CCS power stations. The CCS schemes were compared to each other and

the 'without CCS' alternatives to estimate the level o subsidy that would be required to make CCS

projects economic.

Five sample schemes were selected or study as shown in Table 13. They are based on key CO2

sources

rom the power stations at Longannet and Peterhead combined with network and storage options

selected rom the options presented earlier in this study.


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Schemeno.

Scheme Abatement cost(/t CO

2)

Required subsidy( M/year)

Required subsidy(/t CO

2

captured)

Electricity cost(/M Wh)

2Longannetsupercritical coal toGannet hub

37 98 7 65

1Longannetsupercritical coal toBrae hub

39 117 9 66

4

Longannetsupercritical coalto Gannet hub withimported CO

2

40 132 10 67

5

Peterhead CCGT to

Captain hub withoutull network 64 93 30 65

3Peterhead CCGT toBrae hub

70 111 36 67

Table 14

Source to storage schemes ranked by cost o abatement (in /t CO2).

Table 14 shows these schemes ranked by cost o abatement (in /t CO2). Each project was compared

with its non-CCS alternative, shown in Table 13, to calculate the subsidy (in terms o /t CO2

captured)

required to give returns similar to those o the non-CCS alternative. On a lietime annual basis required

subsidies range between 93 M per year or Scheme 5 to 132 M or Scheme 4. The required subsidy (in

/t CO2

) is roughly equal to the abatement cost minus the assumed market price o CO2

in 2020.

The cost over the lietime o the energy generating system (levelised cost) o Scheme 3 and Scheme

2 was compared to that o conventional coal- and gas-fred generation (Figure 19). Calculations o the

required subsidy assumes a rate o return o between 9% to 11%. This shows that despite the di erence

in abatement cost, gas-and coal-fred CCS schemes have very similar levelised costs (Figure 19 and Table13). However, although the amount o fnancial support or gas-fred CCS projects is similar to that

required to support coal-fred CCS, the tonnage o CO2

abated is much higher in a coal scheme.


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Figure 19

Breakdown o levelised costs in 2020.

Figure 20

Comparison o the impact o sensitivities on

power generation by CCS Coal and CCS Gas.

Sensitivities on the assumptions The high degree o uncertainty in elements o cost and the

perormance o CCS plant in the economic modelling exercise ows through to the estimates o the

cost o electricity generation o CCS Coal and CCS Gas schemes in quite a dierent way (Figure 20).

For example, actors which have a strong impact on the power station element o the levelised costs

o the schemes such as a reduced load actor (50% instead o 85%), higher discount rates and a higher

CAPEX will have a disproportionate eect on the economics o CCS Coal because o the greater weight

o the power station costs in CCS Coal. Conversely, assumptions that have a strong impact on uel costs

such as sensitivities to commodity prices will have a stronger eect on the economics o CCS Gas.


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Impact o CO2-EOR on results CO

2-EOR may have the ability to lower the overall subsidy

required and provide an additional incentive or development o CCS. It may add value to Scotlands

hydrocarbon reserves by prolonging the lie o oil felds, delaying their closure and postpone

decommissioning costs.

Modelling o CCS Schemes key conclusions

The underlying economics o energy projects drive power industry development.

The levelised costs (in /M Wh) o CCS Gas and CCS Coal are similar.

CCS schemes are likely to be signifcantly more expensive than standard conventional Combined

Cycle Gas Turbine and pulverised coal plant.

Uncertainty in the costs and perormances o CCS schemes can considerably aect assessment o

the relative merits o coal- and gas-fred schemes.

High or low uture commodity prices will determine whether costs or CCS will be competitive

with non CCS power generation.

Although the costs o CCS schemes are similar, CCS coal-fred power generation abates more

CO2

than CCS gas.


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Business Risks

RevenuesTechnical and

OperationCosts

Financing CapexSite

Availability

Flexible

running

System

Integration

Operational

Perormance

Skill

Shortages

Electricity

Spark

Spreads

EU ETS*

Funding

PolicyOil Price Opex

Figure 21

The key areas o business risk.

8| Business risks facedby early CCS projects

The principal fnancial risks associated with anticipated revenue, costs and technical/operational aspects

o CCS projects were identifed to inorm the discussion o business models or early CCS projects.

Early CCS projects are likely to consist o dedicated transport and storage acilities matched with

each source. This study concentrated on the risks associated with projects o this nature. A more

mature CCS industry may well consist o multiple projects with a shared inrastructure many capture

projects eeding into a CO2

pipeline network which is then linked to a multitude o storage sites.

The confguration o these early projects means they are likely to ace additional business risks. Three

key areas o business risk and their mitigation were investigated: Revenue stream risks, Cost risks and

Technical and Operational risk (Figure 21).

*EU ETS is European Union

Emissions Trading Scheme


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Revenue streams the power station will be the principal source o income to any CCS project

selling low-carbon electricity to the market. Uncertainty over gas, coal and carbon prices in the long

term brings with it uncertainty regarding the gross margin or power generators. Furthermore, the

UK electricity generation mix is likely to evolve in the years to 2020 both as a result o policy and in

response to commodity prices; more nuclear and renewables capacity could result in lower usage levels

o CCS plants and thereore lower overall revenues.

Costs Capital costs (CAPEX) orm the single largest source o cost uncertainty and are likely to

dominate the character o overall schemes. The technologies o pipeline systems and storage sites are

better known than those o other elements, so their capital costs are more certain. However, these

orm a large proportion o the total capital requirement so any overrun will have a disproportionate

impact on overall project returns. Uncertainty in the thermal efciency o CCS plants will give rise to

signifcant elements o risk in the operational cost (OPEX), through uel costs. The relative novelty o

CCS technology and the risks associated with it suggest that the costs o fnancing early projects will be

higher than those o more mature technologies.

Technical and Operational risks There will be signifcant cost savings rom learning eects.

Technical and operational efciency will also improve with experience. The two areas most likely to

achieve signifcant improvement are the power plant (which currently accounts or approximately two

thirds o lietime costs in each CCS scheme) and storage sites. Pipelines are much more o a known

quantity, and levels o operational risk can be well estimated in advance. Some additional fnancial risk

may be associated with the construction o early CCS power plants, where delays are more likely than

or conventional stations because o the complexity o the projects.


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*

* Short run marginal cost

Figure 22

Mitigation o risks in a CCS scheme.

Figure 23

Summary o the three

business models

examined in this study.

9| Business mo

co2 joint study full

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