A Selective Literature Review of CO2 EOR in the UK North ... · PDF fileAiken Reid Energy Ltd Page 3 A Selective Literature Review of CO 2 EOR in the UK North Sea Continental Shelf

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A Selective Literature Review of CO2 EOR in the UK North Sea Continental Shelf This work has been carried out by Aiken Reid Energy Limited, on behalf of the UK CCS Transport & Storage Development Group, as part of a stock take on CCS EOR reports in the last couple of years. Author: Willie Reid [email protected] Final Report: June 2015

A CO2 EOR overview from a DECC presentation in Aberdeen in October 2013 Caveat Aiken Reid Energy Ltd has made every effort to ensure that the interpretations, conclusions and recommendations presented herein are accurate and reliable in accordance with good industry practice. Aiken Reid Energy Ltd does not, however, guarantee the correctness of any such interpretations and shall not be liable or responsible for any loss, costs, damages or expenses incurred or sustained by anyone resulting from any interpretation or recommendation made by any of its officers or employees. Aiken Reid Energy Ltd, Westhill Business Centre, Arnhall Business Park, Westhill, Aberdeen, UK AB32 6UF Tel: +44 (1224) 863144


10 Key Messages:

1. The quantity and timing of supplies of CO2 from UK Emitters is a critical issue for CO2 EOR development in the UK North Sea. CO2 EOR projects need a secure supply of CO2 with a minimum critical mass of several million tonnes pa CO2 to Cluster Fields in the Central North Sea in the early 2020’s. CCS storage sites, developed alongside CO2 EOR, are also part of this key development phase.

2. Without economic incentives North Sea CO2 EOR is unlikely to go ahead. There are a number of recent papers that give evidence from economic modelling and desk research on the incentives that are required for CO2 EOR, including the supply of free CO2, Field Allowances, and suspension of PRT (Petroleum Revenue Tax). This links in with the recent Wood Review recommendations.

3. Uncertainty on the oil price. Modelling suggests that incentives, alongside an oil price of at least $90/bbl, are required for CO2 EOR for the period 2020-2030. Alternative studies suggest $70/bbl oil will be sufficient. Further work needs to be done on oil price sensitivity.

4. An independent pre-feed study to assess a full chain CO2 EOR project is required to better evaluate the feasibility of CO2 EOR. The ERP (Energy Research Partnership) will report on progress during 4thQ 2015, although the aims of their report are more generally to understand the role of CO2 EOR and how it interacts with the development of CCS and to understand the risks and market failures that are preventing progress from being made.

5. The size of the UK oil prize for CO2EOR has been identified as 3 billion barrels in total and 1 billion barrels in a CO2EOR cluster in the CNS (Central North Sea). However, the window of opportunity for development that exploits existing infrastructure is during the period 2020-2030 in that, by 2030, it is estimated that two thirds of the suitable fields will have ceased production. Essentially, this means that incumbent operators are likely to have moved on, data will be lost and the opportunity for the re-use of infrastructure will have diminished. Therefore the estimation above is a technical one as opposed to a commercial one.

6. Infrastructure: Co-development of CCS storage, as well as pipeline transport infrastructure,

is required alongside CO2 EOR. They need to be considered together and an infrastructure development plan would be useful for Oil and Gas operators considering CO2 EOR.

7. A potential visionary approach to development as an alternative to a slower stepwise approach is required for both CCS and CO2 EOR. This could involve a plan for 60 million tonnes pa CO2 storage by 2030, for the period 2020-2030 which is a key decade for CO2EOR’s introduction and maturity. This would include targets for Supply, Infrastructure, and Storage.

8. The case for CO2EOR plus alternative CCS storage has not yet been fully explored. A study

on this may also assist in comparing the long term economics of CO2 EOR vs CCS storage only options.

9. CO2 EOR has been successfully used in 136 projects onshore in the USA, along with projects in Hungary, Croatia, Turkey, and offshore in Brazil. There can be learnings from this for the UK industry since in the USA, in particular, this is a mature technology.

10. A Regulated Monopoly Company model to stimulate development for CCS and CO2 EOR: There may be potential to consider the creation of a CNS regulated monopoly model for transport and storage, funded partly by industry and, at least initially, the public sector which could facilitate investment across multiple electoral and economic cycles.


A Selective Literature Review of CO2 EOR in the UK North Sea Continental Shelf

Contents 10 Key Messages Background to the Project A. Introduction B. CO2 EOR - General

a. What is EOR with storage and EOR without storage? b. Why does EOR combined with storage help with cost reduction? c. Do recent reports1 cover CO2 Supply and Chain Integration? d. Do reports cover efficiency losses in the supply chain? e. What are the liability issues with respect to EU directives?

C. CO2 EOR - Economics and Incentives

a. Wood Review, Tax Incentives, and Storage Incentives b. How does the industry move to phase 2? c. CO2 Volumes, Timing and price for CO2 d. Back up stores e. Transport Cost f. Do reports give cost indications to provide guidance for incentives?

D. Literature Analysis

a. Enablers for CO2 EOR b. Blockers for CO2 EOR c. Main findings for the study d. 10 key gaps in the literature and related recommendations e. Relevant future reports that will add to existing studies

References

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1 See the references on page 44


Background to the Project

- The CCS Cost Reduction Task Force issued its final report in May 2013 with seven key

recommendations that could help achieve cost reduction across the CCS Chain and lead to a

cost competitive CCS sector in the 2020s.

- Three development groups were agreed to be formed following the issuance of the final

report. This included the UK CO2 Transport and Storage Development Group, which is led by

The Crown Estate2.

- One of the seven key steps recommended was “to incentivise CO2 EOR to limit emissions and

maximise UK hydrocarbon production – to create a UK tax regime to support the

development of brownfield CO2 EOR in the UK North Sea”. This action would also need to

consider potential synergies and the cost benefits of CO2 EOR with different storage business

models.

- This final report indicated that there was a potential cost reduction, from EOR, in the range

of £5-12/MWh for gas CCS & £10-26/MWh for coal CCS.

- The UK CO2 Transport and Storage Development Group also identified a number of key issues with respect to CCS EOR that need to be addressed in the context of the key reports and findings from the last 2-3 years. These are picked up by the main objective of the literature review outlined below. The development group wanted to look at EOR as best it could, whilst it felt that it wasn’t ideally placed to cover the tax regime issue. Therefore, the group decided to undertake a ‘stock take’ of recent EOR related work to gather available evidence to better inform development decisions (see the references on page 44 to see what had been covered), as well as to pick up on the key themes.

- Therefore, The Crown Estate agreed to commission3 this brief review of existing studies and

initiatives in CCS EOR with respect to key questions raised by the UK CO2 Transport and

Storage Development Group, including a status report of the gaps that remain to be studied.

2 Other permanent members are Shell, National Grid, ETI, the Ecofin Foundation, CCSA, DECC OCCS Expert

Chair, 2CO, Pale Blue Dot. 3 The group agreed that this represented the best value for money option, given the resources available.


Main Objective for the Study

To carry out a selective literature review of the work that has been undertaken in the past 2-3

years on Enhanced Oil Recovery (EOR) and to produce a summary report of key findings in dealing

with the questions identified by the CO2 Transport and Storage Development Group. This includes

a short status report assessing what has been examined to date and the gaps that remain to be

studied.

A. Introduction

Enhanced oil recovery (EOR), CO2EOR and CCS

The Importance of CO2EOR and CCS from a Global Perspective

The size of the CO2EOR oil production prize in the UK North Sea

The Key Questions raised by the UK Transport and Storage Development Group with respect to CCS

EOR are:

B. CO2EOR – General a. What is EOR with Storage? What is EOR without storage? b. Why does EOR combined with storage help cost reduction? Does this enable ‘free’ or low

cost storage? c. To what extent do recent reports4 cover CO2 Supply and Chain Integration? d. Do reports cover efficiency losses in the supply chain? e. What are the liability issues with respect to EU directives and the cost of capture?

C. CO2EOR - Economics and Incentives a. The Wood Review, tax breaks and storage incentives for CCS EOR? b. How does the CCS industry move to “Phase 2”, as defined in the OCCS October 2013

response to the CCS cost reduction final report? c. How to incentivise the capture of CO2 in volumes required, the timing of this supply, and the

price for CO2. d. The capacity cost of a CO2 back-up store? e. What would be the dedicated transport cost? f. To what extent do the responses to the questions give an overall cost indication to provide

guidance for incentivisation?

D. Literature Analysis a. What are the enablers for EOR? b. What are the blockers for EOR? c. Main findings from the study d. 10 Key Gaps in the literature and related recommendations e. Relevant Future reports to be issued in 2015/16 that will add to existing studies

4 See the references on page 44


A. Introduction

Enhanced Oil Recovery (EOR), CO2EOR, and CCS (Carbon Capture and Storage) EOR is the term used for increasing the recovery of crude oil from an oilfield beyond primary and secondary recovery. Oil production is categorised in three stages, primary, secondary and tertiary. Secondary recovery, in the form of seawater injection, is the most predominant form of recovery in the UK North Sea. Tertiary recovery includes Natural Gas EOR, CO2 EOR, Low salinity, and polymer flood EOR. All four have been considered for the UK North Sea. The focus on CO2 EOR in this paper reflects the need to decarbonise the electricity and industrial sectors, whilst at the same time being able to realise more of the nation’s natural mineral assets. Carbon Capture and Storage (CCS) refers to a set of process technologies that are designed to capture CO2 from fossil fuel burning power stations or other industrial sources. CO2 from this source is called anthropogenic CO2. The CO2 captured can then be used for either CO2EOR or it can be stored in depleted oil/gas reservoirs or saline aquifers. CO2EOR is in fact “productive storage” in that income can be derived from additional oil production. 2-5 barrels of oil is the range of additional production that can be achieved from 1 tonne of CO2

injected into the reservoir. Storage only CCS is in fact “passive storage” in that no secondary income is derived from its underground placement. There will also be a cost attributed to the use of the underground store.


The Importance of CO2EOR and CCS from a Global Perspective CCS and CO2EOR have become strategic from a global perspective in that geological storage is seen as the best solution to reduce CO2 fossil fuel emissions from power stations and industry and to help meet targets for global emissions in 2050 (see reference 13). Figure 1 shows the 36 global CCS projects (ref.13) that are either operational, under construction or under consideration in 2014. Twenty two of these are operational or under construction and this is double the number from four years ago. It is projected that these projects alone will result in the capture and storage of 40 million tonnes CO2 pa in the next few years.

Figure 1 Actual and expected operation dates for large-scale CCS Global Projects in the Operate,

Execute and Define stages by industry and storage type (ref. 13)

The significant majority of these global projects currently use, or plan to use, CO2 EOR as the preferred storage method. It is North America and China that mainly use onshore CO2 EOR. Also, the majority of the global projects being developed (19 in total) are currently in the United States where the industry receives significant funding from the US Department of Energy (DOE). Only two of these projects use aquifer storage whilst the rest focus on onshore CO2 EOR. Europe and Australasia are the main proponents of storage only CCS utilising dedicated stores (depleted gas or saline aquifers). Storage only CCS projects at Peterhead and White Rose are being evaluated as a start to the UK industry. With respect to the global projects, power generation and natural gas processing are by far the largest sources of captured CO2. The offshore Petrobras Lula Oil Field CO2 EOR Project in Brazil uses natural gas processing as the CO2

source with a CO2 capture capacity of 0.7 million tonnes pa (ref. 13).


The size of the UK offshore CO2EOR oil production prize in UK North Sea (ref. 11) In the UK North Sea, the main driver for CO2EOR is the incremental size of the additional oil that will be produced from suitable oil and gas fields that can have their life extended by upwards of 15 years. The North Sea fields have been examined as to their suitability for CO2EOR (refs. 4, 11). A summary of the potential for increased oil production and associated CO2 storage is as follows:

- All of the UKCS Fields that are suitable for CO2, including 2nd and 3rd stage candidates, have a potential of 3058 million barrels incremental production with 1435 million tonnes associated CO2 storage.

- The UKCS leading Fields have a potential of 1879 million barrels incremental production with 885 million tonnes CO2 associated storage

- All fields in CNS (Central North Sea) suitable for CO2 EOR, including 2nd and 3rd stage candidates, have a potential of 1557 million barrels incremental production from CO2 EOR with 796 million tonnes associated storage.

- The leading fields in the CNS have a potential of 683 million barrels incremental Production from CO2EOR with 336 million tonnes CO2 associated storage.

Reports conclude (refs. 4,7,9,11) that a cluster of fields in the Central North Sea are the best candidates for the development of CO2EOR in the UK North Sea. These fields are shown in figure 2 below.

Figure 2: Fields that are suitable for CO2 EOR in the Central North Sea (CNS) (ref. 11) Analysis (refs. 7,9) has found that with the development of a UK CO2EOR cluster in the CNS, more than one billion barrels of incremental oil could be co-produced with the storage of at least 0.5 Gt CO2.


B. CO2 EOR General

a. What is EOR with Storage? There are a number of references to EOR with Storage in the literature listed at the back of this paper. In the USA is has been accepted that CO2 EOR is an effective emission reduction technology. CO2 EOR is similar to a waterflood, where a fluid is injected into the formation and then co-produced with oil and gas from production wells. The CO2 and gas is then separated from the oil which is sold, and the mixture is recompressed and injected back into the formation. During the process of circulating the fluids, some of the CO2 remains permanently and is immovably trapped in the formation as part of the process of displacing the ‘hard to move’ oil. This CO2 is permanently stored, while other back-produced CO2 is either injected into other areas of the field or sold on to other EOR operators. A simple mass balance of imported CO2 less sold CO2 less almost insignificant fugitive emissions gives the total stored in the formation. This storage is beginning to be termed “incidental storage” as CO2 EOR always stores CO2. It can also be argued that EOR with Storage refers to the further development of an oilfield for additional oil recovery, followed by conversion of the field into a dedicated storage facility for CCS purposes. There is also a view in the literature that, in Europe, whilst CO2 EOR should be planned alongside storage (CCS) options, it is storage via CCS that should come first in order to establish a critical mass of CO2 supply. This would bring a constant supply and allow flexibility in that the CO2 could be switched between EOR and nearby storage as required. It is worth mentioning that switching from pure storage to an EOR store would entail higher capital and opex. However, the capital and opex for the EOR store would be expected to be paid for by the EOR operator. So, though there would need to be a capacity cost related to maintaining the fall back site that is not injecting, the fall back site could have a smaller capacity. This would require owners of storage and EOR to agree to this process, or to have the same owners. This could present some tax challenges related to the existing petroleum tax ring fencing process; however, this can likely be overcome. Some reports discuss cluster development for both CCS and CO2 EOR in some detail with particular reference to the Central North Sea (CNS) area where most of the potential storage and CO2 EOR opportunities are co-located5. They discuss the use of common infrastructure for both storage and CO2 EOR. The Northern North Sea is also a relevant area for CO2 EOR, but it gets less attention because EOR candidates are farther from UK CO2 sources. It is important to mention that buffer storage is also mentioned with respect to pressurised CO2 being kept in storage tanks near Peterhead harbour in NE Scotland. This could be delivered to Peterhead in custom designed transportation vessels. This transport and supply model allows for this CO2 to be co-mingled with any existing CO2 delivered by land based pipelines. The reports do not cover circumstances where an established CCS store would be used as a buffer/fall back store6. This was a proposition that was widely discussed by the cost reduction taskforce.

5 The storage opportunities in the Southern North Sea and the East Irish Sea are not seen as EOR plays, but

more about ‘pure’ storage of CO2. 6 This is not an EOR store but a storage site that allows the emitter to deal with variability of supply.


What is EOR without Storage? No reference is made in the reviewed literature to “EOR without storage”. In a UK/EU context perhaps a better term is CO2 EOR without separate back-up storage or purely this is about additional hydrocarbon production not attached to any CCS process. If the CO2 being stored is not captured from an EU emissions trading scheme qualified installation, then it is not subject to the EU Storage Directive and is treated as just another working fluid. In this case there is no opportunity for an operator to treat any injected CO2 – even if it is trapped and immobile – as stored. When referring to CO2 EOR in the USA, EOR without storage is a direct process where CO2 is sent directly from a natural CO2 reservoir to an EOR project via a dedicated pipeline, or pipeline infrastructure, going directly from source to application. The CO2 remaining in the reservoir is eventually stored after the abandonment and decommissioning of the oilfield. This type of CO2 EOR has been established for at least 40 years, mostly in North America where a pipeline infrastructure has been created to transport natural CO2 from underground reservoirs to 136 US CO2 EOR projects. Little processing7 is required for this natural occurring CO2. About 68-70 million tonnes CO2 pa is used for EOR in the USA, of which 80% is natural CO2 and 20% is from industrial sources (ref. 14). Up until recently there has been no attempt to qualify the CO2 from industrial sources as stored, however, some states are now recognising that this is actually the case. The first commercial scale full chain Carbon Capture Project for power generation in North America is in Canada. The Boundary Dam Project, which as a power plant can be seen as an analogue for UK CCS, goes directly to an established EOR reservoir some 60 km from the plant. This is actually EOR with storage as the Weyburn field is monitored and the CO2 remaining in the subsurface is accounted as stored. It is worth mentioning that a slipstream (~10%) is going to a saline storage site. The significance is that the Boundary Dam project does not consider operational backup is needed, even though they have a backup store available. The amount is limited to ~10% because they don’t need to sacrifice a greater portion of CO2 revenue to the research project. This may be an important point for the UK, where it has been claimed that backup storage is needed for EOR. This issue therefore needs further examination. In the UK, the original BP/Miller/Peterhead project in 20078 was CO2 EOR going directly to a hydrocarbon reservoir, with no separate back up storage (ref. 4). In essence it is a commercial and regulatory decision if backup storage is required.

b. Why does EOR combined with storage help cost reduction? Does this enable ‘free’ or low cost storage? Various reports indicate that an EOR Development Model combined with a Storage (CCS) Model helps with cost reduction in the form of free storage. Also, as a result of the parallel development of CO2 EOR Clusters alongside CO2 Storage Clusters, this should reduce the overall cost of the transport and storage infrastructure that is required. These cost reduction opportunities, combined with the additional production potential of 0.8-1Billion Barrels of Oil (ref. 119), are key to the arguments presented in favour of CO2 EOR in various reports.

7 It always has to be dehydrated, and almost always compressed, but it is only a minor cost.

8 FID could have been in June 2007; the project was cancelled in May 2007. It had been announced in July

2005. 9 Review of UKCS miscible flooding and appraisal – DECC EOR workshop September 2013.


A CCS focused storage workshop in May 2014 (ref. 510) found that: ”special mention must be made of the potential for CO2-EOR to lower the cost of storage. This comes about because storage of CO2 left behind during the EOR process is a “by product” of the operations. Fortuitously the CO2-EOR potential is clustered in two regions of the Central North Sea (CNS), not too far from one of the current demonstration projects. It should be pointed out, however, that co-located or nearby storage formations that allow a first step of investment decisions by emissions sources which lead to sufficient volume aggregation is essential to enable CO2-EOR investment decisions to be made in parallel.” A key element that explains the above is that you do not have storage costs, as such, with EOR (in its purest sense i.e. non-CCS). These costs form part of the hydrocarbon extraction so you save in whatever those costs are with conventional CCS. However, this only applies to the CO2 left in the reservoir after decommissioning, though at any point in a CO2 EOR project the vast majority of the CO2 is within the reservoir with only a few thousand tonnes (out of a few million tonnes) in the platform recirculation and processing facilities. If a field is just switched off and the wells plugged there will be mixture of trapped and mobile CO2 in the field, all trapped beneath the geological seal that previously held the gas and oil. The findings of the CRTF (Cost Reduction Task Force) were that storage costs would drop from £25/MWh to £5-10/MWh, so this is the scale of the potential saving (211). It was found that the area with the greatest potential for savings in CCS was in the scale and utilisation of transport and storage. DECC and the CCS industry have indicated that the UK needs to store c50-60 million tonnes pa CO2, using CCS, during the 2030s (and more than 100/150 million tonnes pa eventually). In the Central North Sea (CNS) a proportion of this can also be deployed directly to CO2 EOR in clusters very close to the options for clusters for CCS Storage only; this will result in savings by adding the CO2 EOR options to planned future supply, transport and storage infrastructure. The CCS Cost Reduction Task Force (CRTF) findings (ref. 2), with respect to EOR cost savings, indicate that “only a rough estimate can be made currently as to the value CO2 may attract, if it were delivered, at pressure, to CNS oil field operators. Based on US experience this could well cover the cost of conventional CO2 storage, and perhaps some of the transport costs as well. As a result this might decrease electricity costs by £5-12/MWh for gas CCS and £10-£26/MWh for coal CCS.” There is no specific mention of such cost savings from the USA in the recent literature and it would be useful to have more details in published papers, although this may also refer to the onshore infrastructure that has been developed in the USA, over the past 30+ years, where there are around 150 operating EOR projects, where natural CO2 is transported in a conjoined pipeline network that allows the natural product to be sold at $20-$38/tonne for commercial use on EOR. However, it is clear that onshore CO2 EOR in the USA is very different from Offshore North Sea CO2 EOR, in terms of costs and infrastructure and readily available CO2 supply. It should be noted that most of the recent reports and models from 2014 suggest that the Offshore Oil and Gas industry may be more likely to accept the supply of CO2 free of charge in return for free storage and for potentially accepting responsibility for the associated regulatory issues concerning the reservoir during operation and following decommissioning for CO2 EOR.

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This workshop was used as evidence for the characterisation of storage paper by the transport and storage development group. 11

CCS Cost Reduction Task Force Final report - May 2013.


c. To what extent do reports cover CO2 Supply and chain integration? Element Energy et al (ref. 9) cover the development of the CO2 Supply Chain, for both CCS and CO2

EOR from Demonstration Phase (Phase 1 in DECC Policy Review Aug 14) to an Early Commercial

Phase (Phase 2), and eventually to a Commercially Driven Phase (Phase 3).

If CCS is to play a significant role in decarbonising power station and industrial sector CO2 emissions

in the UK and Europe then very large amounts of CO2 eventually will need to be captured,

transported and stored. Figures of up to 150 million tonnes of CO2 pa have been quoted by various

studies. Element Energy indicate that the fastest development scenario would require up to 60

million tonnes by 2030 (see below). This CO2 needs to be transported in liquid form and stored in

geological formations under the North Sea.

Transporting this amount of liquid CO2 will be an enormous engineering challenge. To put it in

context, the UK North Sea peak oil production was 125 million tonnes of oil/year, equivalent to

about 150 million tonnes of CO212. We may therefore need a new offshore CO2 transport & storage

infrastructure on a similar scale to that already existing in the North Sea for oil production. This will

take very careful planning and is likely to need major pre-investment.

Figure 3: An overview of the CO2 Supply Chain and how it fits together (ref. 9).

Figure 3 shows the different elements of the supply chain from CO2 emitters to an eventual CO2 EOR

project.

Reports (ref. 9) have analysed the details in the chain from publically available data and have matched

the availability of Emitter sites with potential storage and CO2 EOR sites up to the 2030’s and beyond.

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The challenge is about the same size as oil production: 125 Mt of 30 API oil is 142 million m3; according to

DECC the peak in 1999 was about 135Mt [153 million m3]. Whereas 150 Mt of CO2 at a pipeline condition (200

bar, 5C) is 150 million m3. 60 Mtpa equates to about 40% of the peak oil transport.


The potential transport infrastructure has also been mapped, using existing reusable pipeline networks

and including new build pipeline networks.

The sequential analysis has included an interpretation of each of the following:

- Existing data bases for North Sea Reservoirs, including CO2Stored.

- Analysis of emitters and likely volumes of CO2 to feed into the CO2 supply chain.

- Technologies for offshore CO2 transport and storage.

- Supply chain infrastructure options including pipeline transportation.

- Facilities for CO2 Storage.

- Facilities for CO2-EOR.

- Storage Site Development.

- CCS Network Development.

- Pipeline infrastructure requirements.

- Well infrastructure requirements.

The synergies between oil and gas, CO2 EOR, and CCS storage site development were also considered. For the development of a CCS network, these were: - Seismic imaging (raw data and interpretations);

- Reservoir simulation models;

- Field production, injection and pressure history;

- Well logs and cores;

- Well test data;

- Formation mineralogy and brine composition.

Oil and Gas Services applicable to and Offshore CCS and CO2 EOR industry were identified as: - Seismic;

- Reservoir modelling;

- Drilling & well services;

- Fabrication;

- Pipeline & equipment services (design/construction/installation);

- Facilities services (operation/inspection/repair/maintenance);

- Logistics;

- Dive services.

With respect to overall infrastructure development, Figure 4 shows potential sources of emissions

from power stations and industrial facilities from throughout the UK in three different phases:

Demonstration Phase, Early Commercial Phase and Commercially Driven Phase. This would arise

from a significant stimulus to the industry via incentivisation and pre-investment, with a steep increase


in CO2 supplies from Power Stations and Industrial sources where it assumes that all of the initial (as

opposed to shortlisted) five competition applicants will reach FID by 201913.

Figure 4 shows CO2 sources and how the demonstration phase moves into the Early Commercial

Phase in the 2020’s and follows with a Commercially Driven Phase before the 2030’s.

Figure 5 shows a combination for stores and CO2 EOR projects that will require alignment with the emitters identified in the previous table. This gives 55-60MMtonnes pa CO2 in 2030.

It is also based on a Storage/ CO2 EOR cluster in the CNS and transportation hubs at St Fergus and N E

England.

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This clearly cannot now be the case in that timescale.


The fastest growth scenario modelled in Figure 5, was 55-60 million tonnes CO2 pa by 2030, this being consistent with ETI’s ESME modelling which indicates CCS capacities to at least 60 million tonnes CO2/yr from the 2030s are required to meet the UK’s climate target at least cost. “This would save £30bn/yr (nearly 1% of GDP) compared to decarbonisation options where no CCS is employed. The scenario is consistent with a mix of coal, gas and biomass power generation with CCS and industrial CO2 capture concentrated in a handful of regional clusters”. This 55-60 million tonnes CO2 pa figure contrasts with the ETI’s most recent request (ref. 12) for a 40-52 million tonnes CO2 pa proposal to establish 5 UK North Sea storage options by 2026. Although ambitious, this is also consistent with timing requirements of CO2 EOR from 2020-2030 in particular, which has been set out by some references as being a critical opportunity to develop CNS opportunities.

It is also consistent with DECC’s aims “of ensuring CCS technology is available as a cost competitive option during the 2020s, where the choice and designs of the early CCS projects should support medium-term development of CCS technology and infrastructure in the UK”. Reports also found that capacity would most efficiently be developed through shared CO2 transport and storage infrastructure. A model for pipeline transportation was developed alongside CO2 sources and Storage and CO2 EOR sites as shown in figure 6.

Figure 6. Phased transport infrastructure growth in six 5-year phases from 2013-2042 (ref. 9).


It should be noted that some reports also indicate that “there are currently multiple and significant market failures and unbearable risks for commercial developers of infrastructure that could meet the capacity required in the 2030’s”. These relate to a lack of a market for CCS in general and captured CO2 delivery, along with the different business models that will need to exist for the parts of the CCS chain. The Energy Technologies Institute considered five potential options for CO2 transport and storage infrastructure development that could be considered with increasing levels of public intervention; these are: 1. Government informs and enables competitive market for CO2 transport and storage

infrastructure. 2. Industry co-ordinates and provides leadership on CO2 transport and storage infrastructure,

with Government support. 3. Regional monopoly system operator(s) are established to deliver transport and storage

infrastructure in priority zones. 4. Public-private Joint Venture(s) are established to deliver transport and storage

infrastructure. 5. Government design, own and operates CO2 transport and storage infrastructure.


d. To what extent do reports cover efficiency losses in the CCS chain? Efficiency losses are not covered in a specific section in any of the reports. However, efficiencies are regularly mentioned in general reference:

- to the re-use of existing infrastructure; - to pre-investment in infrastructure; - when the opportunities for stacked multiple storage in the Central North Sea are discussed.

Some of this has already been discussed in the previous section on CO2 supply and integration. A re-use of existing pipeline infrastructure can reduce upfront transportation costs by around one third (ref. 9). The following quotes are related to efficiencies in general:

1. “The current UK Government and EU’s preferences for project-by-project competitive

approaches provide insufficient price signals and substantial risks for commercial developers of storage”. Consequently there is a shortage of commercial storage development activity. This approach is not well suited to efficiently:

developing backup capacity to minimise risks,

developing CO2 storage in stacked clusters,

exploiting saline aquifer formations with very large areas, where pressure footprints and CO2 migration may need to be managed,

progressing the development of a CO2-EOR cluster.

2. “If stakeholders wish to deploy CCS aggressively, the capacity would most efficiently be developed through shared CO2 transport and storage infrastructure. There are multiple and significant market failures and unbearable risks for commercial developers of infrastructure that could meet the capacity required in the 2030”.

3. “Currently there are significant hurdles for commercial investment in transport, storage or

EOR infrastructure, implying real risks that without further intervention, infrastructure investments made in the 2010s and 2020s will be inefficient”.

Several reports found that capacity would most efficiently be developed through shared CO2 transport and storage infrastructure (see references 2, 3, 4, 5, 6, 9). Note: Other aspects of efficiency like CO2 production efficiency from power stations, and the efficiency of offshore CO2 EOR injection facilities, are also not covered in specific sections of the reports.

e. What are the liability issues with respect to EU directives and the cost of capture? Reports reviewed do not go into great detail on the EU CCS Directive. However, the August 2014 DECC Policy review stated that: “The European Commission is currently reviewing the CCS Directive. The Commission will submit a review report to the European Parliament and to the Council by March 2015. An external evaluation study consisting of an on-line survey, follow-up interviews and stakeholders meetings is underway.


The Commission has signalled that the review will also be a broad based policy review and therefore an opportunity to consider wider European CCS policy – particularly in the light of the forthcoming agreement on the 2030 climate and energy package”. DECC have asked for responses to the following questions:

- Are there elements of the way the CCS Directive has been implemented in the UK that ought to be revisited?

- What should the UK be asking for during the Directive review process? It is also understood that CO2 EOR sites will be covered by the same obligation as CCS sites, if they wish to store CO2 under a UK Storage License. A Storage License is not necessary to conduct CO2 EOR, but presumably would be required for a site storing CO2 for which emission reduction benefits (e.g., CfDs) were claimed by the capture plant. So if the CO2 is not to be classed as emitted it must be transferred to an EU ETS qualified installation in accord with the EU ETS directive, as it stands. The only way to qualify a subsurface formation as an ETS installation is via the EU Storage directive. This process currently involves an EU Financial Security Bond or Insurance which covers the cost of any future leaks of CO2. Licensees will also be responsible for covering the on-going cost of monitoring and adherence to regulation policy. There is also a post injection monitoring period after decommissioning and cessation of injection under the Directive. This may be for a period of 20-30 years or more, but can also potentially be much shorter. It was also noted by Element Energy et al. that: “The EU CCS Directive requires significant financial securities to cover a number of liabilities. This could include leakage of CO2 stored when CO2 prices are much higher than today.” They also state that: “ CCS Directive… sets out conditions for storage, third party access rules for infrastructure, mandates CCS Readiness examinations for new build power stations above 300MW, and allows full chain projects to be considered single installations within the ETS. “


C. CCS EOR Economics and Incentives

a. Wood Review, tax breaks and storage incentives A number of economic models have been produced in various reports in recent years. The main UK sources of these for have been Kemp et al. (Aberdeen University), Element Energy et al. (2012 and 2014) and Senergy, on behalf of DECC, in 2013. The economics of CO2 EOR and incentive options have been discussed in some detail in these desk studies. There is good synergy between the findings of the Wood Review and the general findings in these studies.

1. Wood Review The findings of the Wood Review (ref. 8) on CCS EOR are summarised as follows: The new Regulator should work with Industry to develop and implement the strategies outlined in this Review which build on the excellent work already conducted within PILOT and will underpin the MER UK strategy: Technology (including Enhanced Oil Recovery and Carbon Capture and Storage) -

“While ageing assets are a factor, there are strong signs that under investment in assets and insufficient uptake of Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) techniques will have a significantly adverse effect on maximising economic recovery for the UK.”

“A significant number of interviewees also suggested that Government should consider further extension of field allowances to incentivise Enhanced Oil Recovery (EOR) as the business case emerges.”

“Industry must also undertake to provide some of its best and most experienced people to work with the new Regulator on developing and implementing MER UK strategies in areas such as exploration, production, increased and enhanced oil recovery and decommissioning.” “…where deployment of Enhanced Oil Recovery (EOR) techniques could greatly improve recovery rates.”

“Operators should be required, where appropriate, to co-operate with the Regulator and

with other licence holders in the wider adjacent area on all aspects of field and cluster

development, from exploration through to decommissioning, with the overarching aim of

maximising economic recovery from clusters of fields as well as from individual fields.”

2. Tax Incentives Recent economic modelling by Professor Alex Kemp at Aberdeen University suggested that fiscal incentives could also drive CO2-EOR investments in the UKCS (12) Kemp et al. have explored how tax amendments for CO2-EOR could help to kick-start investments. Their modelling suggests that without any fiscal incentives, CO2-EOR projects will fail to meet the investment criteria of commercial oil companies (at a screening oil price of $90/barrel). This is true both in the 2020’s for early projects for which there will likely be a sizeable investor risk premium, and even in the 2030’s by which time reports anticipate CCS with CO2-EOR would have similar risk profiles to other North


Sea oil investments. Fiscal incentives are therefore needed for both demonstration of CO2-EOR projects and for second-movers during the 2020’s.

3. CCS EOR Storage and Infrastructure Incentives

Findings in a number of reports indicate that Separate storage developed in conjunction with potential EOR projects will be required to ensure a secure supply of CO2. Reports by Element Energy et al. come to similar conclusions to Kemp et al. regarding the need for incentivisation with respect to CO2-EOR projects. A number of financial mechanisms to support CO2-EOR specifically have been analysed by Element Energy et al. in their two 2014 reports. These options are summarised in the table below:

Intervention Advantages Disadvantages Flat field allowance for

CO2-EOR Targeted, transparent, in line with current practice for ultra-heavy oil fields.

Would be insufficient for some fields or excessive tax reduction could lead to deadweight losses.

Field allowance based on unit development cost

Targeted, transparent, in line with current practice for brownfield allowance. Minimises deadweight losses if structured efficiently.

Does not provide a strong incentive for cost reduction. Focus on CAPEX may distort investment in OPEX-heavy projects.

Would require ex-ante agreement on predicted CAPEX and oil production.

Field allowance based on unit technical cost

Targeted, transparent, recognises that OPEX will have a material influence on costs.

Would require ex-ante agreement on predicted CAPEX and long-term OPEX, including CO2 transfer prices (if included).

Field allowance based on DPI

Minimises deadweight losses if investors have the same DPI threshold.

Would require ex-ante agreement on predicted CAPEX, OPEX, reservoir performance, discount rates and revenues. Information asymmetry creates risks of “gaming” these assumptions.

Field allowance based on CO2 stored

Likely to lead to project designs that maximise CO2 storage Could be extended to storage-only projects. Addresses market failure for storage.

Estimating storage performance will be difficult. Does not lead to a focus on oil production, and therefore may not maximise tax revenues.

Field allowance based on incremental oil

Transparent, in line with current practice for small field allowance.

Does not promote higher oil production. Would require ex-ante agreement on

predicted oil production.

Reducing headline tax rate (Supplementary charge and/or PRT)

Simple, promotes investment in a field-neutral manner Would be insufficient for some fields

without additional tax incentives; however, could also lead to high deadweight losses.

Capital grants Simple for commercial operators, common stimulus for new technology demonstration.

Requires up-front public subsidy. Unlikely to win environmental NGO support.

Low-interest loan Use of lower public sector discount rates makes investment more attractive.

Loans not usually appropriate for new technologies with multiple and significant risks.

Create national CO2 storage company that could co-invest in CO2- EOR projects

Allows a much larger number of options for CO2-EOR. Potential for a joint company with Norway and Denmark. Revenues could support nationally strategic investments. Addresses market failure for CO2 storage

Contrary to prevailing approach for major new UK infrastructure projects which are privately led.

Table 1: Summary: Financial Interventions analysed in Reports regarding Incentivisation Options (ref. 7)


Reports indicate that reduced taxes would be an effective supportive measure for CO2-EOR projects. In the early years CO2 supply will be limited. However, modelling suggests a combination of a PRT (Petroleum Revenue Tax) waiver and field allowance would be sufficient to make EOR projects commercially viable at a project screening price of $90/bbl and CO2 supplied for free at the oilfield. Policy and infrastructure should also consider that CO2-EOR fields are close to CCS stores, and CO2EOR-store combinations would have more flexible economics than considering CO2 EOR alone. An overall conclusion, from analysis (refs. 7,9) finds that with the early development of a UK CO2-EOR cluster in the CNS, more than one billion barrels of incremental oil could be co-produced with the storage of at least 0.5 Gt CO2. A reasonable proportion of this CO2 will also go to dedicated CCS stores. They indicate that the associated potential real pre-tax Net Present Value (NPV) from a UK CO2-EOR cluster would be £4bn @ $90/bbl (3.5% discount rate). They also find “that for many CNS oilfields, CO2-EOR projects can be NPV positive under a wide range of plausible conditions”. For example, if there are suitable incentives for CO2 capture and transport to allow CO2 to be supplied for free at the platform, real oil prices are sustained above $90/bbl and a combination of a PRT (Petroleum Revenue Tax) waiver and field allowance is introduced for CO2 -EOR projects, then barriers to development can be overcome. “Analysis also reveals that if investment in CO2-EOR is led by a hypothetical “National CO2 Storage Company”, which would benefit from a public sector discount rate and base investment decisions on pre-tax NPV, the potential combined revenues from CO2-EOR could amount to £6 billion (at $90/barrel).” (ref. 9) This reference also applied to specific opportunities in the CNS only. Apart from the economic analysis, only limited details were presented on the “National CO2 Storage Company”. However, it was mentioned that it could take the form of a Public/Private partnership that could take part ownership in transport and infrastructure, offshore CCS storage sites and even shares in CO2-EOR projects alongside existing Oil and Gas operators. Some contrasting conclusions regarding CO2 EOR from a Scottish Government (2009) Study, which was reviewed again by Senergy in September 2013, are as follows: - “Contrary to many expectations most North Sea oil fields cannot be used to the same extent

for CO2 storage, because produced fluids have been replaced by water. - The redevelopment of a mature North Sea field for CO2 EOR is a major undertaking

equivalent in complexity, scale and cost to the original development. - Each project will need to be the subject of detailed engineering design and economic

appraisal including a full assessment of the risks. - Unrisked CO2 EOR may be viable in the North Sea fields at an oil price of £50 ($70) per barrel

or above. - Taking risks into account, it is unlikely that CO2 EOR will be viable in North Sea fields at an oil

price less than £70 ($100) per barrel. - If a subsidy is available for the CO2 stored then a project could be economic at an oil price

significantly lower than £70 per barrel. - CO2 EOR has never been applied offshore so early projects will carry significant additional

technical and financial risks. (Note: The Lula offshore CO2 EOR project with Petrobras in Brazil is now fully operational and there have also been a number of offshore CO2 EOR pilots conducted in the Gulf of Mexico, Middle East and Malaysia.)

- Development of a CCS infrastructure in the UK could lead to the application of CO2 EOR in some fields”


b. How does the Industry move to Phase 2 as defined in the DECC OCCS October 2013 response to the cost reduction final report? These stages are clarified in DECC’s Policy Scoping Document (ref. 6) of August 14 and also in figure 5.

The DECC OCCS response (16/10/2013) to the CRTF anticipates 3 phases to CCS evolution over the

next decade or so:

1. Commercial Demonstration phase (Phase 1) - with material (£1bn) government support,

including R&D funding, to incentivise industry to participate and invest. This is the current

phase which includes UK Commercialisation Programme projects and additional support

from EU funding (EEPR, NER300);

2. Transition phase (Phase 2) – taking the sector through the first power generation CfD

contacts and moving from point to point projects to part chain infrastructure capable of

achieving independent FID;

3. Fully Commercial phase (Phase 3) – when power generation costs with CCS have been driven

down to be affordable & competitive in a price driven electricity supply market.

Figure 7: Next steps in CCS and CO2 EOR: DECC’s Policy Scoping Document (ref. 6) Phase 2 is about moving beyond the two Commercialisation Projects that are expected to complete FEED and reach FID in 2015/16. The approach to this transition phase will evolve during the next two years and this key planning stage is critical for the period 2020-2030 when there is a key window of opportunity to develop and commence CO2 EOR Projects. It is also about deciding about whether this should be a step wise evolutionary process or a visionary process that takes CCS and CO2 EOR in the UK to 60 million tonnes pa CO2 storage in 2030.


Figure 7 shows the first two projects in blue and the subsequent development phases in red. It is an illustration of a development plan that is designed to take advantage of a transportation network (yet to be developed) with options for CO2 Emitters to join at the front end and Storage or CO2 EOR projects to be joined at the back end. The development of phase 2 is also considered in the recent Strategic UK CCS Storage appraisal proposal request from ETI (ref. 12) where the specific objectives of the project are to:

- Develop storage options which contribute to an extendable storage scheme for 1500 million tonnes of storage, injecting 50 million tonnes/pa, by 2030, incorporating storage previously de-risked by other initiatives. This will include expansion from both Phase 1 projects;

- Screen and de-risk commercially attractive options for storage for Phase 2 projects thus de-risking onshore investments by 2026;

- Estimate and schedule the resources needed to get down-selected stores fully appraised and then operational;

- Facilitate the future commercial development of UK storage capacity by accelerating development of capacity and making the results of the Project available to all current and potential future stakeholders.

This will involve evaluations of the steps required to get to pre-FID of 5 new stores by 2026. The £2.5million project will be completed by May 2016.

Figure 8: Three options are presented from the ETI (ref. 12) on the development of CCS (storage only) and CO2 EOR up to 2030. The options presented in figure 8 are Balanced, Concentrated and CO2 EOR and represent 40- 52 million tonnes pa CO2 stored offshore by 2030. The CO2 EOR option, as illustrated above, most closely represents the development plans in the recent literature (ref. 9). This has the potential to give the best return for UK PLC and HMT (ref. 9).


However, the ETI wants to keep the development options open in order to create a range of possible future scenarios. It will be important for the ETI to consider the options for the development of CO2 EOR as this work is conducted up to April 2016. The steps for the progression of CO2 EOR into Phase 2. The three phases in the literature are Demonstration (Phase 1), Early Commercial Phase (Phase 2) and Commercially Driven Phase (phase 3). In the literature, the Early Commercial Phase lasts longer than DECC’s Phase 2. 2015/16 will see the two initial CCS projects, from Phase 1, reach FEED and FID and DECC have requested input from the industry on their views on how best to proceed to Phase 2; including proposals on incentives. Reports cover two approaches to the next phase of development. The first is that of taking time to learn from Phase 1 in order to reduce costs by using measured incentives to join up individual projects that emerge. The second (and most prominent model) is that of creating a real vision for the industry up to 2035 with 60-100 million tonnes pa of CCS and CO2 EOR, where advanced infrastructure in Power Generation, Capture, Transport and Storage/EOR CO2 storage is stimulated by strong government incentives and pre-investment in partnership with industry. It is the latter that is viewed as more likely to overcome “current multiple and significant market failures and unbearable risks for commercial developers of infrastructure that could meet the capacity required in the 2030’s” (ref. 9). Reported options for infrastructure are explained in the separate section on the CO2 chain and Integration (page 13). For CO2 EOR, moving from Phase 1 to Phase 2 relates primarily to the work initiated by DECC alongside the PILOT EOR Work Group set up in 2013. A number of recommendations followed the DECC PILOT EOR Work Group meeting in Aberdeen during October 2013. It should also be noted that this work has also been recognised in the recent proposal request from the ETI (ref. 12). A summary of Pilot DECC activities from October 2013

- The programme of work commenced in October 2013, with a workshop of over 40 experts. Using an advanced screening tool, all the major oil fields were screened for both hydrocarbon miscible gas injection and for CO2 injection. That screening also took into account the distance from the potential CO2 storage hubs that may be developed under the CCS Programme, as PILOT believes that CO2 EOR projects are more likely to develop by exploiting existing CO2 storage hubs than by developing stand-alone CO2 infrastructure.

- The data and feedback from this screening has led to a selective review of fields in the CNS area that are candidates for CO2 EOR.

- DECC are also engaging with the Key Active Stakeholders in the industry who are members of ERP (Energy Research Partnership) and the ERP will produce a report on Priorities and Strategy for CO2 EOR which will be issued in 3Q15. As discussed previously, DECC also issued their own policy document in August 2014 on CCS and CO2 EOR and have requested input from the industry on Strategy and Incentives for CO2 EOR in particular.

- DECC, as regulator for the offshore oil and gas industry, has also recently contacted UKCS field operators to begin a series of “EOR Reviews” to look in more detail at what is holding


back EOR project investment and what industry and government can do to increase EOR activity. This programme of reviews, responsibility for which will now pass to the Oil and Gas Authority, began in autumn 2014 and is expected to take 1-2 years. These planned reviews will include CO2-EOR proposals. These reviews will help inform DECC’s future approach to offshore EOR, including CO2 EOR. Losal and Polymer EOR are also included in this.

As a result of this activity, PILOT is keen to identify a candidate field for an independent pre-FEED study to assess economic feasibility of CO2 EOR.

DECC is also continuing to engage with developers on the design of a generic CCS CfD and options for the criteria which might be applied in any future allocation frameworks (including CO2 EOR). It is hoped that this work will enable the framework for CfD’s to be in place for CCS by 2016.


c. How to incentivise capture of CO2 in volumes required, timing of supply, and the price for CO2? Incentivisation of Volumes of CO2 Supply of CO2 in volumes required for CO2 EOR is perhaps the most critical issue mentioned in reports and DECC/PILOT meeting notes. A necessary condition for any gas injection EOR project is a reliable and secure supply of injectant and the failure to identify this has led to the failure of several potential North Sea EOR schemes (according to DECC EDU). The lack of clarity on timing and volume of CO2 supplies from the UK CCS programme is a significant disincentive to CO2-EOR developers which needs to be addressed (4). Most reports, focus on major CO2-EOR opportunities in the CNS, some touch on the NNS ,while the major UK CO2 emitters are clustered on the NE coast of England, around 500km away, and so the timing and routing of offshore CO2 export pipeline infrastructure needs careful consideration. Element Energy et al (ref. 9) suggest that 3 new projects plus the existing Peterhead and White Rose projects (making a total of 5) are required to get to FID by the end of this decade in order to start to get the volumes up to an initial critical mass for CO2-EOR. DECC have indicated that the strike price CfD incentives (governed by the Levy Control Framework) for the two initial projects will be agreed in 2015/16 and that any new project incentives on carbon capture will considered after that. It is the CfD incentives that will be key to getting sufficient CO2 for CO2 EOR. In addition, plans to evaluate storage sites for CCS need to be firmly in place to coincide with the development of Emission Projects (ref. 5) and greenfield saline storage sites can take 10 years14 to properly evaluate according to the Storage Group Workshop and subsequent paper. Indeed, in some cases a contractual storage site is required for fixed long term volumes 5 years before the final development a Power station or Emission source (ref. 5). If a CO2 EOR project were to commence development in say 2024, then the planning and organisation would have to start in 2018/19 on a typical development schedule. Of course it is understood that by definition EOR reservoirs are already well appraised (much more so than a greenfield saline storage site would be prior to CO2 injection). Therefore, the pre-FID lead time could be reduced to 2-3 years for engineering and subsurface studies (pre-FEED and FEED). Construction and commissioning may be around 3 years for the projects that have been subject to the detailed engineering studies. This makes a total of 5 years. For greenfield saline, this 5 years may be preceded by 2-10 years of appraisal. This means that EOR projects could start in 2018/19 for a 2024 start-up. The Crown Estate commissioned a report by Poyry (ref. 15) in 2013 which concluded that, in the absence of further interventions to incentivise exploration and appraisal of storage sites independent of power station projects, significant risks to CCS deployment would exist that could lead to: - Development of smaller stand-alone projects;

14

This time frame does not apply directly to EOR, as one of the benefits of EOR storage is that it can be available quicker and can meet the challenge of coordinating development of capture and storage facilities.


- Only roll out CCS projects at a slow rate, so sub optimal;

- Realise extremely slow growth of industrial non-power CCS projects. This report was not about CO2 EOR, but, although the same problems exist, it is clear that the development of CO2 EOR projects could happen much quicker and thus potentially overcome this slow roll out rate. Timing of Supply There are attractive CO2 EOR opportunities in the North Sea but time is limited. DECC has estimated the remaining EOR potential for every oil field in the North Sea. There are several high-rated candidates for CO2-EOR that have potential incremental oil reserves of over 100 million barrels (un-risked). Miscible gas injection EOR also has a successful track record in the North Sea (e.g. Magnus). However, most of the potential CO2-EOR candidate fields are already very mature and operating at high water cut. This means that if CO2-EOR projects do not start within the next 10-15 years, the remaining potential for CO2-EOR will reduce significantly. Based on the latest cessation of production (COP) dates for the individual fields held by DECC, around two-thirds of this potential is in fields that will have been decommissioned by the late 2020s which implies some urgency in establishing a CO2 supply and associated infrastructure if this potential is to be realised without redeveloping fields that have already ceased production. (ref. 11) The combination of a high oil price (sustained above $90/bbl) and a favourable tax regime could see deferred decommissioning of old fields and a significant role for CO2-EOR if there is a reliable supply of CO2 and an appropriate transport infrastructure.

For projects to meet this opportunity window in CO2 EOR they will likely follow the illustrative cashflow model shown in figure 8 (page 29). This not only shows the gestation period that CO2EOR projects in the North Sea are likely to take, but also shows why the planning for such a project would have to take place in the next few years for it be even considered. A critical element of such a project will be security and timing of guaranteed supply of CO2. It is also a useful illustration of projected costs and revenues for a project that will not be decommissioned until 2047. Decommissioning: It should also be noted that although figure 8 (below) shows that the cost of decommissioning with CO2-EOR can be deferred for 15 years or more, its nominal cost is likely to be higher due to additional regulatory requirements associated with subsequent CO2 storage and monitoring. Also, the current tax treatment of decommissioning and “change of use” arrangements, need careful consideration for both CCS and CO2-EOR (ref. 2).


Figure 8. Illustrative cash flow of a CO2-EOR investment for a developer, showing high up-front and operating costs, high taxes, complex decommissioning economics and long-term monitoring requirements. Assumes Project Planning and Assessment commenced on or before 2020. The Price for CO2 As indicated previously, most of the recent reports and models from 2014 suggest that the offshore

Oil and Gas industry may be more likely to accept the supply of CO2 free of charge in return for

storage and for accepting responsibility for regulatory issues concerning the reservoir during

operation and following decommissioning for CO2 EOR. An illustration as to why this may have been

concluded can be seen in Figure 9 where various prices for CO2 are presented in the right hand y

axis, with CfD strike price in the left y axis, and potential field allowance in the x axis.

At a CfD of £150/MWh and a zero price for CO2, then CO2EOR, in this model, becomes viable by a

variation in the field allowance. Another example is that if there is no field allowance, then the

oilfield operator needs to be paid £10/Tonne to accept CO2 at a strike price of £160/MWh, assuming

of course that the oil company accepts the resultant cashflow.

Figure 9. This shows the interplay of onshore and offshore incentives for a network comprising an IGCC capture project with a CO2 EOR project (refs. 7, 9)


d. The Capacity Cost of a CO2 back up store? (If one is required) A back up store for CO2 EOR would not necessarily be a strict requirement of a single CO2 EOR prospect, but it would certainly be helpful in terms of flexibility, reliability and critical mass for a transportation and supply system. As explained earlier, there is also a view in the literature that whilst CO2 EOR should be planned alongside storage (CCS) options, it is storage via CCS that should come first in order to establish a critical mass of CO2 supply. This would bring a constant supply and allow flexibility in that the CO2 could be switched between EOR and nearby storage, as required. Reports discuss Cluster Development for both CCS and CO2 EOR in some detail with particular reference to the CNS area where most of the potential storage and CO2 EOR combined opportunities are co-located. They discuss the use of common infrastructure for both storage and CO2EOR. A large North Sea CO2-EOR project, according to DECC EDU, is likely to need relatively large amounts of CO2 (5-10Mt/yr15) at the start of the project, reducing quite sharply as produced CO2 gets recycled through the reservoir. The CO2 injection may well be part of a WAG (water-alternating-gas) scheme to improve reservoir sweep and in this case the CO2 requirement could be variable on a short term basis. In contrast, the Don Valley CO2EOR project was designed to take 99% of all the CO2 from a single emitter with very little variation in offtake due to alternating gas and water injection at different rates. The only exception was to plan for seasonal maintenance shutdowns coordinated with the capture plant. Reports (refs. 9, 11) suggest that CO2-EOR projects may take CO2 supplies on demand from a trunk pipeline system supplying several projects. In contrast, Don Valley was to use a dedicated pipeline system. However, it is clear that every CO2-EOR project will be different and will be designed to meet the specific needs of a particular oilfield. Storing large amounts of CO2 needs a lot of storage sites and experience has shown that storage reservoirs, particularly saline aquifers, require lengthy (up to 10 years) and expensive appraisal. There is currently little incentive to appraise the aquifer storage sites that are needed. CO2-EOR projects have an advantage for CO2 storage in that they generally already have extensive production history and so the reservoir geology is normally quite well understood. The disadvantage of CO2-EOR is that typical CO2 storage capacity is generally lower than for aquifer storage sites. Offshore aquifer appraisal presents particular difficulties because effective CO2 storage then relies on displacing large amounts of nearly incompressible water over large distances in the subsurface. One of the major concerns for any aquifer storage project is long term CO2 injectivity, which is related to hydraulic connectivity over very large distances. The only effective way to test for good hydraulic connectivity is via a long term injection or production test (either CO2 or water) and this is generally prohibitively expensive offshore. The risk is then that investment decisions have to be taken on very limited test data. Evaluation of storage sites then is a priority for CCS. The costs of developing a single CCS store have been estimated at up to £110 million (ref. 5) with appraisal and development taking approximately 10 years (ref. 5). This contrasts with the minimum £1billion cost of developing CO2 EOR at the Oilfield (ref. 12), but with substantial oil production revenues and a development period of approximately 5 years.

15

As cited earlier some projects may only require 2-5 Mtpa


e. What would be the dedicated transport cost? According to the CRTF (2), transport costs will drop from £21/MWh for 1-2 MTpa to £5-10/MWh for a capacity of 5-10 million tonnes pa. There is no reason to suggest that transportation costs for CO2 EOR would be any different from CCS. The specification and quality of the CO2 will be the same for both CCS and CO2 EOR and it will be transported in pipelines that require the same specification. However, there will be a saving on storage costs as explained earlier. However, Element Energy et al (ref. 9) have used a customised method for modelling the transport and storage component of a CCS and CCS EOR cluster in the CNS. They did not separate transport from storage costs in their model. When looked at by this method the cost range for both transport and storage is given as £5-32/tonne of CO2 for CCS and CO2 EOR combined and £10-40/tonne for CCS alone. Element Energy et al were comparing the introduction of CCS and CO2 EOR to the CNS using existing infrastructure and the benefit of saline aquifer stores in proximity to identified CO2 EOR prospects, with CCS (storage only). The details of their method of calculation were not indicated. Further discussion with Element Energy indicated that, in this example, if we use a 1GW coal fired power plant with 80% uptime which would normally produce 5 million tonnes of CO2 pa, this would equate to approximately:

- £3.5-22.4/MWh for both transport and storage for CCS and CO2 EOR; - £7-28/MWh for both transport and storage for CCS alone.

Element Energy et al. (9) also looked at the detailed costs of using Customised Shipping Vessels which are commonly used in the chemical Industry and are currently used at the port of Yara in Norway with each vessel having 1000-1500 cubic metres capacity. It was concluded that: “In the context of CCS, CO2 shipping provides much higher flexibility around the exact locations, amounts of CO2, and project duration than pipelines. CO2 shipping is competitive with pipeline transport for projects where offshore distances are large, with multiple small sources or sinks, short project durations, and where pipeline consenting risks are significant. Thus CO2 shipping could be a valuable enabler for small industrial capture projects or use of small stores (including small oilfields for CO2-EOR), CO2 appraisal, or supporting CO2 transport from European sources to Scotland. CO2 shipping can support future pipeline development and given the wide range of configurations, it should not be viewed as a direct alternative to pipelines.”


f. To what extent do the responses to the aforementioned questions give an overall cost indication to provide guidance for incentivisation? Exact costings are not possible for the individual costs described in selective reports and all economic studies provide a range of accuracy at the macro level. However, the recent literature contains a variety of economic models regarding incentives for CO2 EOR. The reports also identified strong synergies between CCS and CO2 EOR which suggests that they should be planned together and not separately (as they are at present) as part of an overall supply and infrastructure plan. Findings indicate that incentives are likely to contain a combination of the following:

- CO2 EOR Price for CO2: Analysis in a number of reports suggest that the price for CO2 could be zero in return for storage;

- Petroleum Revenue Tax (CO2 EOR): Findings suggests a dispensation for early projects; - Field Allowance (CO2 EOR): A Field Allowance as shown in figure 9; - CfD (Contracts for Difference): Paid only to the Power Station for CCS in return for the

production of Clean Energy for the National Grid. This will be rolled out in 2015/16 for the White Rose and Peterhead projects at part of Levy Control Framework. This is the main government subsidy that will apply to full CCS projects.

Figure 10 shows an overview of the cashflows for the full integrated network including Power Stations and Industrial Sources, Transportation Network, CO2 Storage only sites and finally, CO2 EOR projects. This shows a mechanism whereby some of the subsidy for CfD can eventually be returned to HMT via Oil and Gas taxation if CO2 EOR is deployed commercially. It is the allocation of the CfD allowance that will drive the supply of CO2 for both storage only CCS and CO2 EOR. However, in CCS, it is only the development of a CO2 EOR business that will create the potential of a positive contribution to HMT from eventual tax contributions as illustrated in figure 10.

Figure 10: Illustrative cashflows for an integrated CCS network with CO2 EOR. (refs. 7,9)


As indicated already in the Economics section, an overall conclusion, from analysis (refs. 7,9) finds that with the early development of a UK CO2-EOR cluster in the CNS, more than one billion barrels of incremental oil could be co-produced with the storage of at least 0.5 Gt CO2. This compares well with the Senergy study (ref. 11) in that it is the equivalent of the midpoint of their work for the CNS. They indicate that the associated potential real pre-tax Net Present Value (NPV) from a UK CO2-EOR cluster would be £4 billion @ $90/bbl (3.5% discount rate). They also find that for many CNS oilfields, CO2 EOR projects can be NPV positive under a wide range of plausible conditions. For example, if there are suitable incentives for CO2 capture and transport to allow CO2 to be supplied for free at the platform, real oil prices are sustained above $90/bbl, and the marginal tax rate is reduced for CO2-EOR projects. However, sensitivity analysis (refs. 7,9) demonstrates that, even with appropriate fiscal incentives in place, there is a very high sensitivity of revenues for both commercial oil developers and the UK Government to a range of factors. Most of these factors lie outside the control of either party, and include oil price, offshore capital and operating costs and reservoir performance.


D. Analysis of the Literature Review

a. What are the enablers for EOR? CO2 Supply - CO2 supply, in terms of volume and timing are key enablers: CO2 supply and infrastructure need to be in place, with a plan to get it to EOR projects, particularly in the CNS (Central North Sea). CO2 EOR projects, according to discussions with DECC EDU, may need a secure supply of CO2 with a minimum critical mass of at least 5-10 million (this may be a cluster structure, rather than a point to point project) tonnes16 pa CO2 to cluster Fields in CNS in the early 2020’s. Commercial, Economics and Incentives - Incentives: Field allowances and/or exemption from PRT (petroleum revenue tax) for early projects which are likely to require at least £1Billion in risked up-front investment costs in developing each CO2 EOR project. - Getting CO2 delivered free of charge to CO2 EOR in the CNS in return for free storage, decommissioning and regulatory obligations. - Oil Price: Modelling suggests that an oil price of at least $90/bbl (currently c$50/bbl) during the period 2020-2030 and beyond is a key enabler. However, further work is required on oil price sensitivity. Policy - Development of a visionary plan for 60 million tonnes pa CO2 storage for the period 2020-2030 which is a key decade for EOR’s introduction, due to abandonment timetables for suitable fields and the need for a reduction in costs, and maturity, including targets for Supply, Infrastructure and Storage. CO2 EOR needs to be worked alongside this. - Wood Review: Follow up on the recommendation from the Wood Review on CO2 EOR for assistance with incentives, infrastructure and cluster development. - Reservoir data for both Storage and CO2 EOR: this will enable early assistance in evaluating reservoir performance data combined with cooperation between current licensed oil operators in nearby or clusters. - The potential evaluation of a Regulated Monopoly Company to stimulate Phase 2 development: “The creation of a CNS regulated monopoly for transport and storage, funded partly by industry and, at least, initially the public sector, which could facilitate investment across multiple electoral and economic cycles”. This is relevant for both CCS and CO2 EOR.

16

This figure may seem high given that the Miller Project was designed for 1.8 Mtpa, Don Valley for 4.7 Mtpa, and Grangemouth has plans for 3.8 Mtpa; so some UK CCS developers planning EOR have contemplated 2-5 Mtpa. Therefore the 5-10 Mtpa need may be for a ‘cluster’. The threshold for development may be closer to 2-5 Mtpa, expanding later. Advocates of clusters claim they are cheaper; no actual developer has designed one, and projects under development are point-to-point. It seems inevitable that clusters will develop from point-point projects, so the minimum supply to get started is that for a single site, rather than a cluster.


Infrastructure - A consideration that CCS and CO2 EOR should be developed together with storage alongside CO2

EOR clusters in the CNS. - Infrastructure Development: As well as building infrastructure around a hub at St Fergus in Scotland, most reports recommend the building of a CO2 supply pipeline to the CNS from the power stations and industrial emitters that are clustered in the North East of England some 500Km away17. Reports indicate that this will lead to the creation of “hubs” and “corridors” for infrastructure (onshore and offshore) that will reduce the timescales, risks, and overall system costs for CCS development. - Storage Readiness of stacked aquifer clusters and depleted gas fields in the CNS in preparedness for CO2 EOR at a later stage. - More detailed engineering studies (at Pre-FEED and FEED level) for CCS shoreline hub infrastructure at Peterhead, St. Fergus, and at a North East England hub.

Confidence

- A Full Chain CO2 EOR Project: DECC and PILOT are keen to identify a candidate field for an independent pre-FEED study to assess economic feasibility of CO2 EOR. - Recognition that the requirements for CO2 EOR opportunities will be project-specific. The suitability and method of application of CO2-EOR processes to North Sea oil fields will need to be determined on a field-by-field basis and, apart from a consistent and timely supply of CO2, there is unlikely to be a ‘one size fits all’ solution. - A FEED and FID (Final Investment Decision) on the UK’s two Phase 1 CCS projects are seen as a key step to the commercial development of the CO2 Chain. - CO2 EOR technology has been successfully used in the USA in 136 projects which utilise 70 million tonnes CO2 pa from a conjoined pipeline transportation system. There are significant differences between Onshore EOR and Offshore North Sea EOR, but there will also be significant learning since in the USA this is a mature technology.

17

This could equate to £500M in pipeline cost, approximately.


b. What are the Blockers for EOR? CO2 Supply - Uncertain supply of CO2 is a major barrier. Large scale CCS EOR will require a major offshore engineering effort on a similar scale to early oil production investment in the 1970’s and 1980’s. Lack of clarity on timing and volumes of CO2 supplied from the UK CCS programme is a significant disincentive. Commercial, Economics and Incentives - Economics are a barrier. CO2 EOR is energy intensive and very expensive in terms of upfront investment costs in an offshore environment. An investment of at least £1Billion (refs. 9, 11) is required for each project. EOR costs in the North Sea are much higher than onshore in the USA, and the economics in the UK North Sea will be much less attractive (without incentives). - Without incentives North Sea CO2 EOR is unlikely to go ahead. There are a number of recent papers that give evidence from economic modelling and desk research on the incentives that are required for CO2 EOR, including Field Allowances and/or suspension of PRT (Petroleum Revenue Tax). However, the recommendations for incentivisation included in the Wood Review may take time to implement. Given that the expected first two UK projects have no EOR link it is reasonable to assume that the first CCS + EOR project will be 2020 or later. It may require a whole Parliament to enact the Wood reforms and related EOR incentives, which puts timing into perspective. - There is competition within each Oil and Gas Company for other global projects in a very competitive environment. Reports find that only the very large Oil and Gas companies are currently likely to have the resources to meet the large investments and consider the long term view for North Sea CO2 EOR. It also needs to be competitive with other Production Enhancement projects being considered (e.g. Losal EOR and chemical EOR). - Does not currently justify private investment. “Some of the benefits of capacity in CO2 transport and storage infrastructure do not translate into sufficient revenues in early years to justify private investment” (ref. 9). Whilst this point also refers to non-EOR storage the issue has relevance here given the difficult economics of EOR, with high costs in the CNS and NNS and the (current) low oil price. - Uncertainty on the oil price. Modelling suggests that incentives, along with an oil price of at least $90/bbl, are required for CO2 EOR for the period 2020-2030 (ref. 9). Alternative studies suggest $70/bbl oil with low risk models (ref. 11) will be sufficient. Further work needs to be done on oil price sensitivity. Pace of Development - Decisions on FEED and FID on the Peterhead and White Rose Projects will not be made until 2015/6. These decisions are also dependent on agreement being reached on the level of CfD support which is not scheduled until Q1 2016. Therefore, operational experience in the UK won’t be generated until 2019 or later and Phase 2 projects and the use of EOR have no clear line of sight at present. - Concerns regarding inefficiencies in the development of storage. “The Government and EU’s preferences for project-by-project competitive approaches provide insufficient price signals and


substantial risks for commercial developers of storage. Consequently there is a shortage of commercial storage development activity. This approach is not well suited to efficiently (i) developing backup capacity to minimise risks, (ii) developing CO2 storage in stacked clusters, (iii) exploiting saline aquifer formations with very large areas, where pressure footprints and CO2 migration may need to be managed, or (iv) progressing the development of a CO2-EOR cluster”.(ref. 9) Technical Hurdles

- Hard to conduct EOR Pilots Offshore - A number of reports indicate that a back-up store in proximity to a CO2EOR project is

preferable (refs. 9, 11, 13). However, the Don Valley and Miller projects provide alternative evidence that this may not necessarily be a North Sea CO2 EOR requirement. The caveat here is that the projects did not go ahead, so cannot be cited as proven working examples.

Other Barriers identified by the CRTF (Cost Reduction Task Force)18 are:

- A high regulatory burden for CO2 storage; - A high level of complexity in clean power commercial arrangements; - Fragile CO2 Economics, long lead times, high finance rates and weak financial incentives; - Shared equity ownership of oil fields creates potential commercial tension between

partners; - - High oil taxation and complex tax environment, which distort investment decisions

(particularly with regard to decommissioning of infrastructure); - Tax regime for individual fields can be non-transparent barrier to evaluation; - Tax treatment of decommissioning and change of use arrangements adds complexity; - Currently no specific tax benefits are available to CO2 EOR and no industry consensus exists on a preferred taxation structure. DECC’s most recent policy report (ref. 6) in August 2014 indicated that the principal barriers to implementing EOR projects include: - Higher risk for EOR offshore compared to onshore projects. The well spacing is much higher offshore, which increases reservoir uncertainty, and is more difficult to carry out small scale pilot projects before committing to full-field development. - Supply of secure, low cost EOR injectants, in particular for miscible gas (including CO2) EOR. - Weight and space limitations on offshore oil platform which make retrofitting major new equipment for EOR projects challenging.

18

Primarily from a meeting of working group leaders in Aberdeen in January 2014


c. Main findings from the study

CO2 Supply

-CO2 Supply, in terms volume and timing are key: The industry needs CO2 supply and Infrastructure (this refers to storage development as well as transport) in place and a plan to get it to EOR projects, particularly in the CNS (Central North Sea). CO2 EOR projects need a secure supply of CO2 with minimum critical mass of at least 5-10 million tonnes pa CO2 to Cluster Fields in the Central North Sea in early 2020’s. In terms of priority Capture (i.e. supply) is seen as a bigger issue for CO2 EOR than infrastructure. Construction and commissioning of even a large pipeline could take 2 years, whereas a capture plant is likely to be 3 years minimum. Planning (pre-FEED, FEED, permitting) for both is likely to be 2-3 years (or more). The most expensive pipeline is likely to be £500-700 million, whereas plant costs range from £1.5-3.5 billion. Many believe, although this hasn’t been explored in depth in the analysis, that if a suitable CfD was in place, infrastructure would be built, and it would be off the critical path. However, conversely the critical path to CfD and delivering capture is the critical path for EOR and any other CCS activities. This needs to be resolved and is seen as a key gap.

- Target setting: PILOT members have stressed the need for setting targets for volumes of CO2 to

match with storage and/or EOR opportunities.

Commercial, Economics and Incentives

-Tax Incentives for North Sea CO2 EOR. There are a number of recent papers that give evidence from economic modelling and desk research on the incentives that are required for CO2 EOR, including Field Allowances and suspension of PRT (Petroleum Revenue Tax). Such Incentives are also recommended in the Wood Review. A combination of the following incentives will be required:

- CO2 EOR Price for CO2 : Analysis in a number of reports suggest that the price for CO2 could be zero in return for storage;

- Petroleum Revenue Tax (CO2 EOR): Findings suggests a dispensation for early projects; - Field Allowance (CO2 EOR): A Field Allowance as shown in figure (7); - CfD (Contracts for Difference): Paid only to the Power Station for CCS in return for the

production of Clean Energy for the National Grid. This will be rolled out in 2015/16 for the White Rose and Peterhead projects under the Levy Control Framework. This is the main government subsidy that will apply to full CCS projects.

Uncertainty on the oil price. Modelling suggests that incentives, along with an oil price of at least $90/bbl, are required for CO2 EOR for the period 2020-2030 (ref. 9). Alternative studies suggest $70/bbl oil with low risk models (ref. 11). Further work needs to be done on oil price sensitivity.

- A Full Chain CO2 EOR Project: DECC and PILOT are keen to identify a candidate field for an independent pre-FEED study to assess economic feasibility of CO2 EOR. This is a key step in CO2 EOR development. - DECC have requested feedback on incentives in their most recent policy note and the ERP are to issue a further report in 2015 to address both strategy and incentives. - A FEED and FID (Final Investment Decision) on the UK’s two Phase 1 CCS projects as a key step to commercial development of the CO2 Chain and decision on CfD’s is also required for these projects in 2015/16. This is on the critical path to developing CO2 supply.


- Additional economic papers were also due to be released by SCCS, Kemp et al., and the ETI during 1Q15. CCS storage and CO2EOR to be developed together

- There is recognition in almost all reports that Storage for CCS and CO2 EOR has significant synergies. More work is required in considering the development of CCS and CO2 EOR together. -Storage development activity alongside CO2 EOR. More work is required to:

Develop backup storage capacity to minimise risks;

Develop CO2 storage in stacked clusters;

Exploit saline aquifer formations with very large areas (where pressure footprints and CO2 migration may need to be managed);

Progress the development of CO2 EOR clusters in the CNS in particular. - The evaluation of storage sites is seen as a priority action for both CCS and CO2 EOR. Actual

Storage costs are difficult to predict until injection performance is known19 and reports therefore

need to look for new cost effective ways of appraising storage aquifers.

Infrastructure - Infrastructure Development: As well as building infrastructure around a hub at St Fergus in Scotland, most reports recommend the building of a CO2 supply pipeline to the Central North Sea from the power stations and industrial emitters that are clustered in the North East of England some 500Km away. Reports indicate that this will lead to the creation of “hubs” and “corridors” for infrastructure (onshore and offshore) that will reduce the timescales, risks, and overall system costs for CCS development. This requires further work and analysis. - More detailed engineering studies (at Pre-FEED and FEED level): for CCS shoreline hub

infrastructure at St. Fergus, and at a North East England hub. More work is required.

-Transportation of CO2 by Ship: Detailed work on CO2 transportation combined with buffer storage

has been investigated by Petrofac (ref. 9). There is a gap in understanding just how relevant this is to

de-risking supplies of CO2 to CO2 EOR and it requires further investigation.

An outline infrastructure development plan would be useful for Oil and Gas operators considering CO2 EOR. Policy - Strategy and Vision for CO2 EOR: Reports discuss a potential visionary approach to development. This could involve a visionary plan for 60 million tonnes pa CO2 storage by 2030, for the period 2020-2030 which is a key decade for EOR’s introduction and maturity. This would include targets for Supply, Infrastructure, and Storage. CO2 EOR to be worked alongside this.

19

A difference will exist between existing fields and greenfield developments. Predictions of injection performance can be produced for existing fields, but greenfield sites are likely to require costly and lengthy well tests to ascertain injection performance and associated storage costs.


- Wood Review: Follow up is required on the recommendations from the Wood Review on CO2 EOR for assistance with incentives and infrastructure and cluster development. - A Regulated Monopoly Company to stimulate Phase 2 development: Reports discuss the potential creation of a CNS regulated monopoly for transport and storage, funded partly by industry and, at least, initially the public sector, which could facilitate investment across multiple electoral and economic cycles. This could be for both CCS and CO2 EOR. The ETI has also recently put forward a model for progressive State involvement in the industry and further work on this could be considered.

- A FEED and FID (Final Investment Decision) on the UK’s two Phase 1 CCS projects as a key step to commercial development of the CO2 Chain and decision on CfD’s is also required for these projects in 2015/16.

-DECC has begun a series of “EOR Reviews” to look in more detail at what is holding back EOR project investment in specific fields and what industry and government can do to increase EOR activity. This programme of reviews will be completed in 2016.

Regulatory and CCS EU Directive

- The EU CCS Directive will be reviewed in 2015 and the industry has been consulted on this process.

However, the full implications for CO2 EOR will not be known until this time.

Technology Learning from USA

CO2 EOR technology has been successfully used in the USA in 136 significant projects which utilise

about 70 million tonnes CO2 pa from a conjoined pipeline transportation system. There are

significant differences between Onshore EOR and Offshore North Sea EOR, but there will also be

significant learning’s since in the USA this is very much a mature technology. More work is required

to transfer North American CO2 EOR experience to the North Sea.


d. Key Gaps not covered in the recent literature and related recommendations to address them. Before looking at the key areas not covered in reports it is worth recapping the two actions identified in the CRTF Final Report (Next Steps p 50) to facilitate CO2 EOR:

making the case to HMT for fiscal incentives for CO2 EOR

identifying synergies and cost benefits of co-development of EOR with alternative CO2 storage

This review suggests that the background economics and options for the different types of incentives that could be considered have been covered in some detail by Element Energy et al (ref. 9) and their model could be used to test a number of scenarios for eventual consideration by the new OGA, as part of the Wood Review, as well as further follow up by the Commercial Development Group. Recommendation: The Element Energy et al (ref. 9) model could be used to test a number of scenarios for eventual consideration by the new OGA, as part of the Wood Review, as well as further follow up by the Commercial Development Group. In the case of identifying synergies and cost benefits of co-development of EOR with alternative storage, almost all reports provide general support for this, but in reality no study has actually focussed on this directly and this needs to be addressed. Recommendation: It would be useful to conduct a focussed study, on the co-development of EOR with alternative storage and this could be started in 2015 and developed alongside the current ERP Strategy Study where there will be significant and useful overlaps. Both of these recommendations are now included in the Key Gaps identified below.

10 Key Gaps in the literature and related recommendations 1. CO2 Supply: The industry needs CO2 supply and Infrastructure in place and a plan to get it to EOR projects, particularly in the CNS (Central North Sea). CO2 EOR projects need a secure supply of CO2 to Cluster Fields in the Central North Sea in the early 2020’s. Many believe, although this hasn’t been explored in depth in the analysis, that if a suitable CfD was in place, infrastructure would be built, and it would be off the critical path. However, conversely the critical path to CfD and delivering capture is the critical path for EOR and any other CCS activities. This needs to be resolved and is seen as a key gap. Recommendation 1a: A study to look at the supply and demand of CO2 over different timescales would be useful for prospects considering CO2 EOR. This could be a small engineering study using data bases from existing studies. Recommendation 1b: An understanding from DECC on how CfDs will affect CO2 EOR prospects would be useful and could be conducted along with Recommendation 4. 2. Without economic incentives North Sea CO2 EOR is unlikely to go ahead: There are a number of

recent papers that give evidence from economic modelling and desk research on the incentives that

are required for CO2 EOR, including the supply of free CO2, Field Allowances, and suspension of PRT

(Petroleum Revenue Tax). This links in with the recent Wood Review recommendations. The


background economics and options for the different types of incentives that could be considered

have been covered in some detail by Element Energy et al (ref. 9)

Recommendation 2: The Element Energy et al (9) model could be used to test a number of scenarios for eventual consideration by the new Oil & Gas Authority (OGA), as part of the Wood Review, as well as further follow up by the Commercial Development Group. 3. Uncertainty on the oil price is not covered in detail in reports. However, modelling suggests that incentives, along with an oil price of at least $90/bbl, are required for CO2 EOR for the period 2020-2030 (ref. 9). Alternative studies suggest $70/bbl oil with low risk models (ref. 11). The UK North Sea is also undergoing a significant step change in operating philosophy to improve overall efficiency. Recommendation 3: A study to look at sensitivities in oil price relative to CO2 EOR for the period 2020-2030 would provide more clarity regarding the extent of financial incentives that may be required. It may also consider incentives related to fluctuating oil price. This could also tap into existing models and data. 4. A Full Chain CO2 EOR Project: DECC and PILOT wish to identify a candidate field for an independent pre-FEED study to assess economic feasibility of CO2 EOR. This is a key step in CO2 EOR development. The ERP report will cover the progress towards this target in its report 4Q 2015 Recommendation 4: The ERP report will cover the progress towards this target in its report 4th Q 2015. It would be useful if this report also considers including an understanding from DECC on how CfDs will affect CO2 EOR prospects (Recommendation 1b). 5. The case for EOR plus alternative storage has not been fully explored: There is a recognition in almost all reports that Storage for CCS and CO2 EOR have significant synergies, but in reality no study has actually focussed on this directly and this needs to be addressed. More work is required in considering the development of CCS and CO2 EOR together. Recommendation 5: It would be useful to conduct a focussed study, on the co-development of EOR with alternative storage and this could be started in 2015 and developed alongside the current ERP Strategy Study where there will be significant and useful overlaps. This will also assist in comparing the long term economics of CO2 EOR v’s CCS storage only options. 6. A potential visionary approach to development as an alternative to a slower stepwise approach

is required for both CCS and CO2 EOR. This could involve a plan for 60 million tonnes pa CO2 storage

by 2030, for the period 2020-2030 which is a key decade for EOR’s introduction and maturity. This

would include targets for Supply, Infrastructure, and Storage.

Recommendation 6: It is recommended that this be considered alongside the stepwise option for development outlined by DECC in August 2014. However, an outline infrastructure development plan would also be useful for Oil and Gas operators considering CO2 EOR. 7. CO2 EOR technology has been successfully used in the USA in 136 significant projects which

utilise about 70 million tonnes CO2 pa from a conjoined pipeline transportation system. There are

significant differences between Onshore EOR and Offshore North Sea EOR, but there will also be

significant learning’s since in the USA this is very much a mature technology.

Recommendation 7: More work is required to transfer North American CO2 EOR experience to the

North Sea.


8. Reports do not cover much detail on the EU CCS Directive or Storage liabilities related to

financial security. The EU CCS Directive will be reviewed in 2015 and the industry has been

consulted on this process. However, the full implications for CO2 EOR will not be known until this

time.

Recommendation 8: Future CCS and CO2 EOR industry reports should include specific sections on the EU CCS Directive and Storage liabilities related to financial security. 9. A Regulated Monopoly Company model to stimulate development for CCS and CO2 EOR: There

may be potential to consider the creation of a CNS (Central North Sea) regulated monopoly model

for transport and storage, funded partly by industry and, at least initially, the public sector which

could facilitate investment across multiple electoral and economic cycles. The economics look

favourable but the potential operational details are not discussed.

Recommendation 9: A report on the potential of such a private/public partnership could be very timely considering the many options being considered by the new OGA. This could also be included in a section of the forthcoming ERP report in 4Q 2015. 10. Transportation of CO2 by Ship: Detailed work on CO2 transportation combined with buffer

storage has been investigated by Petrofac (ref. 9). There is a gap in understanding just how relevant

this is to de-risking supplies of CO2 to CO2 EOR and it requires further investigation.

Recommendation 10: A focussed report on the current potential role of the transportation of CO2

by ship would be very useful for CO2 EOR. This is a successful way of transporting CO2 for the

chemical industry and is similar to mini LNG carriers (ref. 13). TNO are specialists in this area. In the

long term it may also open up the largest potential source of anthropogenic CO2 in Europe which is

likely to be in the Rotterdam/Rhine area.


e. Relevant future reports that will add to existing studies The following is a list of relevant publications and reviews due for issuance in 2015 and 2016:

1. A project conducted by the ERP (Energy Research Partnership): a look at the CO2 EOR full value chain with recommendations on the strategic value for the application of CO2 EOR in the UK North Sea. It is understood that a short list of potential projects will also be reviewed with a view to identifying a single full chain CO2 EOR project that is suitable for pre-FEED evaluation. Due 4th Q 2015;

2. SCCS (Scottish Carbon Capture and Storage) Part 2, Due 2015; Note that this was recently issued and can be found at www.sccs.org.uk

3. Strategic UK CCS Storage Appraisal by ETI (Energy Technologies Institute) Due 2nd Q 2016; 4. ETI Strategy work on a suitable CfD mechanism for early projects. Due 2015; 5. DECC and PILOT are conducting technical reviews with North Sea operators of EOR potential

(including CO2) in selected fields. This started in Autumn 2014 and will continue for 18 months. The reviews may highlight one or more fields suitable for CO2 EOR when a suitable CO2 supply is available. Due 2nd Q 2016;

6. Kemp et al., University of Aberdeen. Further work on CO2 EOR economic modelling. 2015.


References 1. CCS Road Map: DECC Supporting the development of Carbon Capture and Storage in the UK

- April 2012. 2. The Potential for Reducing the Costs of CCS in The UK: Final report, published by the UK

Carbon Capture and Storage Cost Reduction Task Force - May 2013. 3. CCS in the UK: Government Response to the CCS Cost Reduction Task Force, October 2013. 4. DECC CCS EOR Workshop, Aberdeen 1st October 2013: Summary Paper issued by DECC and

PILOT. 5. May 2014 Storage Workshop & subsequent paper ”Delivering CO2 storage at the lowest cost

and in time to support the UK decarbonisation goals” (September 2014). 6. Next steps in CCS: Policy Scoping Document from DECC. Developing an approach for the next

phase of carbon capture and storage projects in the UK, August 2014. 7. CO2 EOR in the UK: Analysis of Fiscal Incentives. Final non-technical report, 20th January 2014

(Emrah Durusut and Harsh Pershad, Element Energy Ltd). Support by Alan Crerar, Dundas Consultants and Professor Alex Kemp, University of Aberdeen. For SCCS (Scottish Carbon Capture and Storage).

8. UKCS Maximising Recovery: Wood Review, February 2014. Sir Ian Wood. 9. Scotland and the Central North Sea. CCS Hub Study revised Final Report 31st March 2014.

(Emrah Durusut and Harsh Pershad, Element Energy Ltd) for SCCS (Scottish Carbon Capture and Storage).

10. Kemp, A.G. and Kasim, S., 2012, The Economics of CO2-EOR Cluster Developments in the UK

Central North Sea/Outer Moray Firth. 11. Review of UKCS Miscible Flooding and Appraisal of Potential. Conducted for DECC

(September 2013) by David Hughes, Senergy. SPE Expert Lecture presentation by David Hughes, February 2014.

12. A Request for a proposal. Strategic UK CCS Storage Appraisal issued by the ETI (Energy

Technologies Institute) 17th December 2014. 13. The Global Status of CCS 2014. Published by the Global Carbon and Capture and Storage

Institute Ltd. November 2014.

14. Kuuskraa, V.A. 2014. The “prize” becomes larger. PowerPoint presentation, Annual CO2 Conference Week, 8-12 December 2014, Midland, Texas, 29 p. http://www.co2conference.net/wp-content/uploads/2015/01/3-Kuuskraa_Carbon_Management_Workshop_Midland_TX_DEC_2014.pdf

15. “Options to incentivise UK CO2 transport & storage”: Poyry Report (May 2013) commissioned by The Crown Estate

http://www.co2conference.net/wp-content/uploads/2015/01/3-Kuuskraa_Carbon_Management_Workshop_Midland_TX_DEC_2014.pdf

http://www.co2conference.net/wp-content/uploads/2015/01/3-Kuuskraa_Carbon_Management_Workshop_Midland_TX_DEC_2014.pdf

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