A Selective Literature Review of CO 2 EOR in the UK North Sea Continental Shelf

Transcription

1 A Selective Literature Review of CO 2 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 willie.reid@aikenreid.com Final Report: June 2015 A CO 2 EOR overview from a DECC presentation in Aberdeen in October 2013 Caveat has made every effort to ensure that the interpretations, conclusions and recommendations presented herein are accurate and reliable in accordance with good industry practice. 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., Westhill Business Centre, Arnhall Business Park, Westhill, Aberdeen, UK AB32 6UF Tel: +44 (1224) Page 1

2 10 Key Messages: 1. The quantity and timing of supplies of CO 2 from UK Emitters is a critical issue for CO 2 EOR development in the UK North Sea. CO 2 EOR projects need a secure supply of CO 2 with a minimum critical mass of several million tonnes pa CO 2 to Cluster Fields in the Central North Sea in the early 2020 s. CCS storage sites, developed alongside CO 2 EOR, are also part of this key development phase. 2. Without economic incentives North Sea CO 2 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 CO 2 EOR, including the supply of free CO 2, 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 CO 2 EOR for the period 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 CO 2 EOR project is required to better evaluate the feasibility of CO 2 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 CO 2 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 CO 2 EOR has been identified as 3 billion barrels in total and 1 billion barrels in a CO 2 EOR cluster in the CNS (Central North Sea). However, the window of opportunity for development that exploits existing infrastructure is during the period 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 CO 2 EOR. They need to be considered together and an infrastructure development plan would be useful for Oil and Gas operators considering CO 2 EOR. 7. A potential visionary approach to development as an alternative to a slower stepwise approach is required for both CCS and CO 2 EOR. This could involve a plan for 60 million tonnes pa CO 2 storage by 2030, for the period which is a key decade for CO 2 EOR s introduction and maturity. This would include targets for Supply, Infrastructure, and Storage. 8. The case for CO 2 EOR plus alternative CCS storage has not yet been fully explored. A study on this may also assist in comparing the long term economics of CO 2 EOR vs CCS storage only options. 9. CO 2 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 CO 2 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. Page 2

3 A Selective Literature Review of CO 2 EOR in the UK North Sea Continental Shelf Contents 10 Key Messages Background to the Project A. Introduction B. CO 2 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 reports 1 cover CO 2 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. CO 2 EOR - Economics and Incentives a. Wood Review, Tax Incentives, and Storage Incentives b. How does the industry move to phase 2? c. CO 2 Volumes, Timing and price for CO 2 d. Back up stores e. Transport Cost f. Do reports give cost indications to provide guidance for incentives? D. Literature Analysis a. Enablers for CO 2 EOR b. Blockers for CO 2 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 Page References 44 1 See the references on page 44 Page 3

4 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 CO 2 Transport and Storage Development Group, which is led by The Crown Estate 2. - One of the seven key steps recommended was to incentivise CO 2 EOR to limit emissions and maximise UK hydrocarbon production to create a UK tax regime to support the development of brownfield CO 2 EOR in the UK North Sea. This action would also need to consider potential synergies and the cost benefits of CO 2 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 CO 2 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 commission 3 this brief review of existing studies and initiatives in CCS EOR with respect to key questions raised by the UK CO 2 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. Page 4

5 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 CO 2 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), CO 2 EOR and CCS The Importance of CO 2 EOR and CCS from a Global Perspective The size of the CO 2 EOR 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. CO 2 EOR 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 reports 4 cover CO 2 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. CO 2 EOR - 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 CO 2 in volumes required, the timing of this supply, and the price for CO 2. d. The capacity cost of a CO 2 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 Page 5

6 A. Introduction Enhanced Oil Recovery (EOR), CO 2 EOR, 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, CO 2 EOR, Low salinity, and polymer flood EOR. All four have been considered for the UK North Sea. The focus on CO 2 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 CO 2 from fossil fuel burning power stations or other industrial sources. CO 2 from this source is called anthropogenic CO 2. The CO 2 captured can then be used for either CO 2 EOR or it can be stored in depleted oil/gas reservoirs or saline aquifers. CO 2 EOR 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 CO 2 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. Page 6

7 The Importance of CO 2 EOR and CCS from a Global Perspective CCS and CO 2 EOR have become strategic from a global perspective in that geological storage is seen as the best solution to reduce CO 2 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 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 CO 2 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, CO 2 EOR as the preferred storage method. It is North America and China that mainly use onshore CO 2 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 CO 2 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 CO 2. The offshore Petrobras Lula Oil Field CO 2 EOR Project in Brazil uses natural gas processing as the CO 2 source with a CO 2 capture capacity of 0.7 million tonnes pa (ref. 13). Page 7

8 The size of the UK offshore CO 2 EOR oil production prize in UK North Sea (ref. 11) In the UK North Sea, the main driver for CO 2 EOR 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 CO 2 EOR (refs. 4, 11). A summary of the potential for increased oil production and associated CO 2 storage is as follows: - All of the UKCS Fields that are suitable for CO 2, including 2 nd and 3 rd stage candidates, have a potential of 3058 million barrels incremental production with 1435 million tonnes associated CO 2 storage. - The UKCS leading Fields have a potential of 1879 million barrels incremental production with 885 million tonnes CO 2 associated storage - All fields in CNS (Central North Sea) suitable for CO 2 EOR, including 2 nd and 3 rd stage candidates, have a potential of 1557 million barrels incremental production from CO 2 EOR with 796 million tonnes associated storage. - The leading fields in the CNS have a potential of 683 million barrels incremental Production from CO 2 EOR with 336 million tonnes CO 2 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 CO 2 EOR 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 CO 2 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 CO 2. Page 8

9 B. CO 2 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 CO 2 EOR is an effective emission reduction technology. CO 2 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 CO 2 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 CO 2 remains permanently and is immovably trapped in the formation as part of the process of displacing the hard to move oil. This CO 2 is permanently stored, while other back-produced CO 2 is either injected into other areas of the field or sold on to other EOR operators. A simple mass balance of imported CO 2 less sold CO 2 less almost insignificant fugitive emissions gives the total stored in the formation. This storage is beginning to be termed incidental storage as CO 2 EOR always stores CO 2. 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 CO 2 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 CO 2 supply. This would bring a constant supply and allow flexibility in that the CO 2 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 CO 2 EOR in some detail with particular reference to the Central North Sea (CNS) area where most of the potential storage and CO 2 EOR opportunities are co-located 5. They discuss the use of common infrastructure for both storage and CO 2 EOR. The Northern North Sea is also a relevant area for CO 2 EOR, but it gets less attention because EOR candidates are farther from UK CO 2 sources. It is important to mention that buffer storage is also mentioned with respect to pressurised CO 2 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 CO 2 to be co-mingled with any existing CO 2 delivered by land based pipelines. The reports do not cover circumstances where an established CCS store would be used as a buffer/fall back store 6. 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 CO 2. 6 This is not an EOR store but a storage site that allows the emitter to deal with variability of supply. Page 9

10 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 CO 2 EOR without separate back-up storage or purely this is about additional hydrocarbon production not attached to any CCS process. If the CO 2 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 CO 2 even if it is trapped and immobile as stored. When referring to CO 2 EOR in the USA, EOR without storage is a direct process where CO 2 is sent directly from a natural CO 2 reservoir to an EOR project via a dedicated pipeline, or pipeline infrastructure, going directly from source to application. The CO 2 remaining in the reservoir is eventually stored after the abandonment and decommissioning of the oilfield. This type of CO 2 EOR has been established for at least 40 years, mostly in North America where a pipeline infrastructure has been created to transport natural CO 2 from underground reservoirs to 136 US CO 2 EOR projects. Little processing 7 is required for this natural occurring CO 2. About million tonnes CO 2 pa is used for EOR in the USA, of which 80% is natural CO 2 and 20% is from industrial sources (ref. 14). Up until recently there has been no attempt to qualify the CO 2 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 CO 2 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 CO 2 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 was CO 2 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 CO 2 EOR Clusters alongside CO 2 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 ), are key to the arguments presented in favour of CO 2 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 It had been announced in July Review of UKCS miscible flooding and appraisal DECC EOR workshop September Page 10

11 A CCS focused storage workshop in May 2014 (ref ) found that: special mention must be made of the potential for CO 2 -EOR to lower the cost of storage. This comes about because storage of CO 2 left behind during the EOR process is a by product of the operations. Fortuitously the CO 2 -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 colocated 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 CO 2 -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 CO 2 left in the reservoir after decommissioning, though at any point in a CO 2 EOR project the vast majority of the CO 2 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 CO 2 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 (2 11 ). 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 CO 2, 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 CO 2 EOR in clusters very close to the options for clusters for CCS Storage only; this will result in savings by adding the CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 EOR in the USA is very different from Offshore North Sea CO 2 EOR, in terms of costs and infrastructure and readily available CO 2 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 CO 2 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 CO 2 EOR. 10 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 Page 11

12 c. To what extent do reports cover CO 2 Supply and chain integration? Element Energy et al (ref. 9) cover the development of the CO 2 Supply Chain, for both CCS and CO 2 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 CO 2 emissions in the UK and Europe then very large amounts of CO 2 eventually will need to be captured, transported and stored. Figures of up to 150 million tonnes of CO 2 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 CO 2 needs to be transported in liquid form and stored in geological formations under the North Sea. Transporting this amount of liquid CO 2 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 CO We may therefore need a new offshore CO 2 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 CO 2 Supply Chain and how it fits together (ref. 9). Figure 3 shows the different elements of the supply chain from CO 2 emitters to an eventual CO 2 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 CO 2 EOR sites up to the 2030 s and beyond. 12 The challenge is about the same size as oil production: 125 Mt of 30 API oil is 142 million m 3 ; according to DECC the peak in 1999 was about 135Mt [153 million m 3 ]. Whereas 150 Mt of CO 2 at a pipeline condition (200 bar, 5C) is 150 million m Mtpa equates to about 40% of the peak oil transport. Page 12

13 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 CO 2 Stored. - Analysis of emitters and likely volumes of CO 2 to feed into the CO 2 supply chain. - Technologies for offshore CO 2 transport and storage. - Supply chain infrastructure options including pipeline transportation. - Facilities for CO 2 Storage. - Facilities for CO 2 -EOR. - Storage Site Development. - CCS Network Development. - Pipeline infrastructure requirements. - Well infrastructure requirements. The synergies between oil and gas, CO 2 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 CO 2 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 Page 13

14 in CO 2 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 Figure 4 shows CO 2 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 CO 2 EOR projects that will require alignment with the emitters identified in the previous table. This gives 55-60MMtonnes pa CO 2 in It is also based on a Storage/ CO 2 EOR cluster in the CNS and transportation hubs at St Fergus and N E England. 13 This clearly cannot now be the case in that timescale. Page 14

15 The fastest growth scenario modelled in Figure 5, was million tonnes CO 2 pa by 2030, this being consistent with ETI s ESME modelling which indicates CCS capacities to at least 60 million tonnes CO 2 /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 CO 2 capture concentrated in a handful of regional clusters. This million tonnes CO 2 pa figure contrasts with the ETI s most recent request (ref. 12) for a million tonnes CO 2 pa proposal to establish 5 UK North Sea storage options by Although ambitious, this is also consistent with timing requirements of CO 2 EOR from 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 CO 2 transport and storage infrastructure. A model for pipeline transportation was developed alongside CO 2 sources and Storage and CO 2 EOR sites as shown in figure 6. Figure 6. Phased transport infrastructure growth in six 5-year phases from (ref. 9). Page 15

16 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 CO 2 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 CO 2 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 CO 2 transport and storage infrastructure. 2. Industry co-ordinates and provides leadership on CO 2 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 CO 2 transport and storage infrastructure. Page 16

17 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 CO 2 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 CO 2 storage in stacked clusters, exploiting saline aquifer formations with very large areas, where pressure footprints and CO 2 migration may need to be managed, progressing the development of a CO 2 -EOR cluster. 2. If stakeholders wish to deploy CCS aggressively, the capacity would most efficiently be developed through shared CO 2 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 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 CO 2 transport and storage infrastructure (see references 2, 3, 4, 5, 6, 9). Note: Other aspects of efficiency like CO 2 production efficiency from power stations, and the efficiency of offshore CO 2 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 An external evaluation study consisting of an on-line survey, follow-up interviews and stakeholders meetings is underway. Page 17

18 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 CO 2 EOR sites will be covered by the same obligation as CCS sites, if they wish to store CO 2 under a UK Storage License. A Storage License is not necessary to conduct CO 2 EOR, but presumably would be required for a site storing CO 2 for which emission reduction benefits (e.g., CfDs) were claimed by the capture plant. So if the CO 2 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 CO 2. 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 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 CO 2 stored when CO 2 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. Page 18

19 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 The economics of CO 2 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 CO 2 -EOR investments in the UKCS (12) Kemp et al. have explored how tax amendments for CO 2 -EOR could help to kick-start investments. Their modelling suggests that without any fiscal incentives, CO 2 -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 CO 2 -EOR would have similar risk profiles to other North Page 19

20 Sea oil investments. Fiscal incentives are therefore needed for both demonstration of CO 2 -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 CO 2. Reports by Element Energy et al. come to similar conclusions to Kemp et al. regarding the need for incentivisation with respect to CO 2 -EOR projects. A number of financial mechanisms to support CO 2 -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 CO 2-EOR Field allowance based on unit development cost Field allowance based on unit technical cost Field allowance based on DPI Field allowance based on CO 2 stored Field allowance based on incremental oil Reducing headline tax rate (Supplementary charge and/or PRT) Capital grants Low-interest loan Create national CO2 storage company that could co-invest in CO2- EOR projects Targeted, transparent, in line with current practice for ultra-heavy oil fields. Targeted, transparent, in line with current practice for brownfield allowance. Minimises deadweight losses if structured efficiently. Targeted, transparent, recognises that OPEX will have a material influence on costs. Minimises deadweight losses if investors have the same DPI threshold. Likely to lead to project designs that maximise CO 2 storage Could be extended to storage-only projects. Addresses market failure for storage. Transparent, in line with current practice for small field allowance. Simple, promotes investment in a field-neutral manner Simple for commercial operators, common stimulus for new technology demonstration. Use of lower public sector discount rates makes investment more attractive. 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 Would be insufficient for some fields or excessive tax reduction could lead to deadweight losses. 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. Would require ex-ante agreement on predicted CAPEX and long-term OPEX, including CO 2 transfer prices (if included). Would require ex-ante agreement on predicted CAPEX, OPEX, reservoir performance, discount rates and revenues. Information asymmetry creates risks of gaming these assumptions. Estimating storage performance will be difficult. Does not lead to a focus on oil production, and therefore may not maximise tax revenues. Does not promote higher oil production. Would require ex-ante agreement on predicted oil production. Would be insufficient for some fields without additional tax incentives; however, could also lead to high deadweight losses. Requires up-front public subsidy. Unlikely to win environmental NGO support. Loans not usually appropriate for new technologies with multiple and significant risks. 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) Page 20

21 Reports indicate that reduced taxes would be an effective supportive measure for CO 2 -EOR projects. In the early years CO 2 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 CO 2 supplied for free at the oilfield. Policy and infrastructure should also consider that CO 2 -EOR fields are close to CCS stores, and CO 2 EOR-store combinations would have more flexible economics than considering CO 2 EOR alone. An overall conclusion, from analysis (refs. 7,9) finds that with the early development of a UK CO 2 - 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 CO 2. A reasonable proportion of this CO 2 will also go to dedicated CCS stores. They indicate that the associated potential real pre-tax Net Present Value (NPV) from a UK CO 2 -EOR cluster would be $90/bbl (3.5% discount rate). They also find that for many CNS oilfields, CO 2 -EOR projects can be NPV positive under a wide range of plausible conditions. For example, if there are suitable incentives for CO 2 capture and transport to allow CO 2 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 CO 2 -EOR projects, then barriers to development can be overcome. Analysis also reveals that if investment in CO 2 -EOR is led by a hypothetical National CO 2 Storage Company, which would benefit from a public sector discount rate and base investment decisions on pre-tax NPV, the potential combined revenues from CO 2 -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 CO 2 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 CO 2 -EOR projects alongside existing Oil and Gas operators. Some contrasting conclusions regarding CO 2 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 CO 2 storage, because produced fluids have been replaced by water. - The redevelopment of a mature North Sea field for CO 2 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 CO 2 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 CO 2 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 CO 2 stored then a project could be economic at an oil price significantly lower than 70 per barrel. - CO 2 EOR has never been applied offshore so early projects will carry significant additional technical and financial risks. (Note: The Lula offshore CO 2 EOR project with Petrobras in Brazil is now fully operational and there have also been a number of offshore CO 2 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 CO 2 EOR in some fields Page 21

22 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 CO 2 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 when there is a key window of opportunity to develop and commence CO 2 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 CO 2 EOR in the UK to 60 million tonnes pa CO 2 storage in Page 22

23 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 CO 2 Emitters to join at the front end and Storage or CO 2 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 derisking 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 The 2.5million project will be completed by May Figure 8: Three options are presented from the ETI (ref. 12) on the development of CCS (storage only) and CO 2 EOR up to The options presented in figure 8 are Balanced, Concentrated and CO 2 EOR and represent million tonnes pa CO 2 stored offshore by 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). Page 23

24 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 CO 2 EOR as this work is conducted up to April The steps for the progression of CO 2 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 /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 million tonnes pa of CCS and CO 2 EOR, where advanced infrastructure in Power Generation, Capture, Transport and Storage/EOR CO 2 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 CO 2 chain and Integration (page 13). For CO 2 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 A number of recommendations followed the DECC PILOT EOR Work Group meeting in Aberdeen during October 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 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 CO 2 injection. That screening also took into account the distance from the potential CO 2 storage hubs that may be developed under the CCS Programme, as PILOT believes that CO 2 EOR projects are more likely to develop by exploiting existing CO 2 storage hubs than by developing stand-alone CO 2 infrastructure. - The data and feedback from this screening has led to a selective review of fields in the CNS area that are candidates for CO 2 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 CO 2 EOR which will be issued in 3Q15. As discussed previously, DECC also issued their own policy document in August 2014 on CCS and CO 2 EOR and have requested input from the industry on Strategy and Incentives for CO 2 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 Page 24

25 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 CO 2 -EOR proposals. These reviews will help inform DECC s future approach to offshore EOR, including CO 2 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 CO 2 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 CO 2 EOR). It is hoped that this work will enable the framework for CfD s to be in place for CCS by Page 25

26 c. How to incentivise capture of CO 2 in volumes required, timing of supply, and the price for CO 2? Incentivisation of Volumes of CO 2 Supply of CO 2 in volumes required for CO 2 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 CO 2 supplies from the UK CCS programme is a significant disincentive to CO 2 -EOR developers which needs to be addressed (4). Most reports, focus on major CO 2 -EOR opportunities in the CNS, some touch on the NNS,while the major UK CO 2 emitters are clustered on the NE coast of England, around 500km away, and so the timing and routing of offshore CO 2 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 CO 2 -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 CO 2 for CO 2 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 years 14 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 CO 2 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 CO 2 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. Page 26

27 - 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 CO 2 EOR, but, although the same problems exist, it is clear that the development of CO 2 EOR projects could happen much quicker and thus potentially overcome this slow roll out rate. Timing of Supply There are attractive CO 2 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 CO 2 -EOR that have potential incremental oil reserves of over 100 million barrels (unrisked). Miscible gas injection EOR also has a successful track record in the North Sea (e.g. Magnus). However, most of the potential CO 2 -EOR candidate fields are already very mature and operating at high water cut. This means that if CO 2 -EOR projects do not start within the next years, the remaining potential for CO 2 -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 CO 2 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 CO 2 -EOR if there is a reliable supply of CO 2 and an appropriate transport infrastructure. For projects to meet this opportunity window in CO 2 EOR they will likely follow the illustrative cashflow model shown in figure 8 (page 29). This not only shows the gestation period that CO 2 EOR 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 CO 2. It is also a useful illustration of projected costs and revenues for a project that will not be decommissioned until Decommissioning: It should also be noted that although figure 8 (below) shows that the cost of decommissioning with CO 2 -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 CO 2 storage and monitoring. Also, the current tax treatment of decommissioning and change of use arrangements, need careful consideration for both CCS and CO 2 -EOR (ref. 2). Page 27

28 Figure 8. Illustrative cash flow of a CO 2 -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 The Price for CO 2 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 CO 2 free of charge in return for storage and for accepting responsibility for regulatory issues concerning the reservoir during operation and following decommissioning for CO 2 EOR. An illustration as to why this may have been concluded can be seen in Figure 9 where various prices for CO 2 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 CO 2, then CO 2 EOR, 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 CO 2 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 CO 2 EOR project (refs. 7, 9) Page 28