BERGEN, NORWAY ExCo Papers _Email.pdf · SWOT/Scenario Exercise feedback to members and discussion GHG/12/11 : GHG/12/12 12) Feedback on IEA Activities No Paper 13) Discussion Papers

41st ExCo MEETING, 9th-10th MAY 2012, BERGEN, NORWAY

This document has been prepared for the Executive Committee of the IEAGHG Programme.It is not a publication of the Operating Agent, International Energy Agency or its Secretariat

Contents Page Motion on procedure at the meeting……………………………………………………………………………… 1

Adoption of agenda………………………………………………………………………………………………………… 2 Minutes of 40th meeting…………………………………………………………………………………………………. Corrections to minutes……………………………………………………………………………………………………

4 19

Matters arising from the 40th meeting - list of actions and status …………………………………. 20 Progress Report – IEAGHG Programme………………………………………………………………………. 21 Membership Issues/New Members……………………………………………………………………………… 31 Financial Report/Annual Accounts

2011/12 Financial update……………………………………………………………………………………… Budget for 2012/13………………..……………………………………………………………………………..

32 33

Annual Review 2011…………………..…………………………………………………………………………………. 35 IEAGHG Strategic Planning

Proposed changes to IA and Annex 1 changes.……………………………………………………… SWOT/Scenaria exercise feedback to members and discussion…………………………….

36 37

Feedback on IEA activities………………………..……………………………………………………………………. 38 Discussion Papers

CCS in CDM Feedback, work ahead………….……………………………………………………………. 39 UK FEED study analysis……………………………………………………..……………..…………………… 42 Update on costs network activities..……………………………………..………………………………. 43 Effects of Microbial Activity in CO2 storage, A review………………………………………….. 44

Completed/On-going Activities CCS Capacity constraints..……………………………………………………………………………………… 54 CO2 Capture in the Steel Industry……………………………………………………….……………….. 62 Operating Flexibility……………………………………………………………………………………………… 63 Capture in Gas Fired Power Plants……….………………………………………………………………. 77 Financial Mechanisms for Long Term Liability……………………………………………..……….. 78 Brine Abstraction…………………………………………………………………………. 88

Study Prioritisation………………………………………………………………………………………………………… 100 Assessment of costs of capture at baseline coal power plants................................ 102 CO2 storage efficiency in aquifers ..……………………………………….………………………………. 103 Evaluation of reclaimer waste disposal for CO2 Post Combustion Capture.…………. 106 Criteria of fault geomechanical stability during a pressure build-up.…………………….. 108 Environmental Impact Statements – Review of Gaps ……………………………………….….. 110 Review of the status of non CO2 GHG emissions and opportunities for future work. 112

Studies to be reconsidered for future voting rounds/Members Ideas for Future Studies.. 114 Update on GCCSI Programme………………………………………………………………………………………… 115 Feedback on Members Activities………………………………………………………………………………….. 116 Date of Next Meeting……………………………………………………………………………………………………… 117 Any other business………………………………………………………………………………………………………… 118

GHG/12/01

IEA GREENHOUSE GAS R&D PROGRAMME 41st EXECUTIVE COMMITTEE MEETING

MOTION ON PROCEDURE AT THE MEETING

The following motion is proposed:

Anyone who is present at this meeting shall have the right to speak, when recognised by the Chairman.

To gain the Chairman’s attention, members should turn their nameplate onto its end. This will help the Chairman ensure that everyone who wishes to speak has a chance to do so.

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Bergen, Norway, 9th – 10th May 2012

ITEM FIRST DAY (08.30 – 17.30hrs) Paper Number 1) Welcome, safety briefing, introduction of new members and observers No paper 2) Motion on procedure at the meeting GHG/12/01 3) Adoption of agenda GHG/12/02 4) Minutes of 40th meeting

Corrections to minutes GHG/12/03 GHG/12/04

5) Matters arising from the 40th meeting - list of actions and status GHG/12/05 6) Progress Report – IEAGHG Programme GHG/12/06 7) Membership Issues/New Members GHG/12/07 8) 2011/12 Financial Update GHG/12/08 9) Budget for 2012/13 GHG/12/09 10) Annual Review 2011 GHG/12/10 11) 11.1) 11.2)

IEAGHG Strategic Planning Proposed changes to IA and Annex 1 Changes SWOT/Scenario Exercise feedback to members and discussion

GHG/12/11 GHG/12/12

12) Feedback on IEA Activities No Paper 13) Discussion Papers 13.1) CCS in CDM Feedback, Work Ahead GHG/12/13 13.2) UK FEED study analysis GHG/12/14 13.3) Update on Costs network activities GHG/12/15 13.4) The Effects of Microbial Activity on CO2 Storage, A review GHG/12/16 14) Completed /On-Going Activities 14.1) CCS Capacity constraints GHG/12/17 14.2) CO2 Capture in the Steel Industry GHG/12/18 14.3) Operating Flexibility GHG/12/19 14.4) Capture in gas fired power plants GHG/12/20 14.5) Financial Mechanisms for Long Term Liability GHG/12/21 14.6) Brine Abstraction GHG/12/22

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ITEM Second DAY (08.30 to 17.00) Paper 15) Study Prioritisation GHG/12/23 15.1) Assessment of costs of capture at baseline coal power plants GHG/12/24 15.2) CO2 storage efficiency in aquifers GHG/12/25 15.3) Evaluation of reclaimer waste disposal for CO2 Post Combustion

Capture GHG/12/26

15.4) Criteria of fault geomechanical stability during a pressure build-up GHG/12/27 15.5) Environmental Impact Statements – Review of Gaps GHG/12/28 15.6) Review of the status of non CO2 GHG emissions and opportunities for

future work - GHG/12/29

16) Studies to be reconsidered for future voting rounds/Members Ideas for Future Studies

No Paper

17) Update on GCCSI Programme GHG/12/30 18) 18.1)

Feedback on Members Activities An Update on the Boundary Dam, Aquistore projects and CCS activities in Mexico

No Papers

19) DONM Presentation on 42nd ExCo meeting – Kyoto, Japan and travel advice to GHGT-11

GHG/12/31 No Paper

20) AOB 21) Close of Meeting

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IEA GREENHOUSE GAS R&D PROGRAMME 40th EXECUTIVE COMMITTEE MEETING

LIST OF ATTENDEES

Members Dr John Carras CSIRO Australia Prof Kelly Thambimuthu (Chair) CO2CRC Australia Dr Eddy Chui NRCan Canada Dr Malcolm Wilson University of Regina Canada Mr Peter Petrov EU Mr Eemeli Tsupari VTT Finland Dr Ilkka Savolainen VTT Finland Dr Nathalie Thybaud ADEME France Dr Ryo Kubo RITE Japan Mr Daan Jansen ECN The Netherlands Mr Peter Versteegh NL Agency The Netherlands Dr Trevor Matheson CRL Energy New Zealand Dr Klaus Schöffel Gassnova Norway Mrs Åse Slagtern Forskningrådet Norway Dr Taher Najah OPEC Dr Anthony Surridge SANERI South Africa Dr Jang Kyung-Ryong KEPRI South Korea Miss Mónica Lupión CIUDEN Spain Mr Sven-Olov Ericson (Vice Chair) Ministry of Sustainable Development Sweden Ms Camilla Axelsson Swedish Energy Agency Sweden Dr Gunter Siddiqi Swiss Federal Office of Energy Switzerland Dr Jay Braitsch US DOE USA Mr Philip Sharman ALSTOM Mr Markus Wolf ALSTOM Mr Kevin McCauley Babcock & Wilcox Mr David Jones BG Group Mr Arthur Lee Chevron Mrs Gina Downes CIAB Mrs Sarah Edman ConocoPhillips Dr Sven Unterberger EnBW Kraftweke AG Mr Mario Graziadio ENEL Dr Tim Hill E.ON Mr Richard Rhudy EPRI Mr Krishnaswamy Sampath ExxonMobil Mr Klaas van Alphen GCCSI Mr Fumihiro Ito JGC Dr Mohammad Abu Zahra Masdar Dr Johannes Heithoff RWE Power AG Dr Tony Booer Schlumberger Mr Bill Spence Shell Dr Helle Brit Mostad Statoil Mr Dominique Copin Total Prof Niels Peter Christensen Vattenfall

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IEA EPL Dr John Topper Mr John Gale IEAGHG Team Mr Tim Dixon IEAGHG Team Mr Neil Wildgust IEAGHG Team Mr Toby Aiken IEAGHG Team Miss Samantha Neades IEAGHG Team Dr Ameena Camps IEAGHG Team Mrs Sian Twinning IEAGHG Team Dr Stanley Santos IEAGHG Team Mr Steve Goldthorpe IEAGHG Team Mr John Davison IEAGHG Team Mr Mike Haines IEAGHG Team Miss Ludmilla Basava-Reddi IEAGHG Team Ms Jasmin Kemper IEAGHG Team

Observers Mr Bob Durie Australian Consortium Australia Prof Krzysztof Warmuzinski Polish Academy of Sciences Poland Miss Viviana Coelho Petrobras Brazil Mr Doug Campbell Nova Scotia Power Canada Dr Isabelle Czernichowski BRGM France Mr Juho Lipponen IEA France Mr Brendan Beck SANERI South Africa Dr Cheol Huh Korean Ocean Research and Development Korea Mr James Godber International Energy Technology UK Mr Nick Otter GCCSI UK Dr Antonio Marin IIE Mexico

Apologies Mr Jürgen-Fr. Hake Forschungszentrum Jülich Germany Mrs Briony Daw DECC UK Mr Jeremy Martin DECC UK Miss Louise Barr DECC UK Mr Keith Burnard IEA France Dr David Campbell Scottish Power UK Mr Theodor Zillner Ministry of Transport Innovation and

Technology Austria

Mr Gardiner Hill BP UK Mr Michael Maloney Doosan Babcock UK

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1. WELCOME AND INTRODUCTIONS On behalf of the Executive Committee (ExCo), Kelly Thambimuthu opened the meeting and welcomed all new members, new member representatives and observers attending ExCo for the first time. 2. MOTION ON PROCEDURE The motion for procedure at the meeting (document GHG/11/34) was adopted. 3. ELECTION OF CHAIR Document GHG/11/35 refers. Kelly Thambimuthu was the only candidate for election, proposed by Monica Lupion of Spain, and seconded by Tony Surridge of South Africa. Kelly Thambimuthu was therefore unanimously re-elected as chair for two further years. 4. ADOPTION OF AGENDA Document GHG/11/36 refers. Members adopted the agenda for the meeting. 5. MINUTES OF PREVIOUS MEETING & CORRECTIONS TO MINUTES Documents GHG/11/37 and GHG/11/38 refer. Only minor adjustments were received, therefore members were asked to approve the minutes as they stood. Members approved the minutes of the 39th ExCo meeting. 6. MATTERS ARISING FROM THE 39TH MEETING, LIST OF ACTIONS & STATUS Document GHG/11/39 refers. John Gale addressed this item, and went through the actions from the previous meeting, explaining that they are all either complete, or would be discussed at the meeting. 7. PROGRESS REPORT – IEAGHG PROGRAMME Document GHG/11/40 refers. John Gale provided a summary of the past 6 month. He explained the recent and forthcoming staffing changes, Neil Wildgust had resigned to Join PTRC, in Canada and Dr Prachi Singh and Dr Jasmin Kemper had been recruited to boost the capture team. A number of staff have undertaken some in-house training to aid their professional development, and this has proved beneficial to the office as a whole. On reporting, a number of topics that the ExCo has identified previously have been reviewed internally to determine the benefit of IEAGHG conducting a study. These will be presented to members at the meeting. Since the last meeting 10 technical studies have been reporting, overcoming the backlog that had built. Following discussions at the 39th ExCo, as a trial two non-contentious reports had been selected for webinar reporting. At the time of the ExCo only one webinar report had been completed, but we will complete the trial and feed back to members at the next meeting how these webinars went.

Action: 1 General Manager The Summer school in 2011, was hosted by Illinois State University of the USA. 53 students attended from 23 countries. The summer school series remains as popular as ever. The 2012 summer school is planned to be held in Tsinghua University, Beijing, China. Four network meetings had been organised since the last ExCo. It is planned to change the reporting format for the network meetings to a more glossy style report focusing on key leanings. A joint storage network meeting was being planned for 2012. Discussions were underway as to whether to retain the wellbore integrity network, refocus it or to close it down The new website was proving popular with 1220 registered members. All our members are encouraged to register.

Action 2: Members We are seeing increased interest in our social networking pages, with growth in user numbers for both the Twitter feed and the Facebook page. The impact factor for IJGGC journal increased in 2010 to 4.074. We are still publishing six regular issues a year. A special oxyfuel issue was also produced this year, managed by Stanley Santos, drawing papers from the OCC series.

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Planning for GHGT-11 is proceeding well. The call for papers is now out; the technical programme committee has been agreed. The conference web site is on line at www.ghgt.info. Agreement has been reached with Elsevier to publish the proceedings on line in Energy Proceedia as with previous conferences. Discussions have commenced with University of Austin, Texas to host GHGT-12 in 2014. 8. MEMBERSHIP ISSUES / NEW MEMBERS Documents GHG/11/41 refers. John Gale presented this agenda item. He explained that all the paperwork was now complete and that MASDAR are now a formal member of the programme. IIE (Mexico) have expressed an interest in joining as a sponsor. SENER (Mexican Ministry of Energy) has approved the application, and as Mexico is an IEA NEET country, their membership falls in line with CERT guidelines. The IEA OLC has raised no objections. Dr Antonio Marin on behalf of IIE, explained that funding could prove an issue if CP membership status was required, which is why they elected to join as sponsors. John Carras (Australia) suggested that we should welcome IIE to join as it will be very good for the programme. The Executive Committee unanimously resolved to invite IIE to join the Implementing Agreement for a Co-operative Programme on Technology Relating to Greenhouse Gases Derived from Fossil Fuel Use as a Sponsor. The Executive Committee authorised the General Manager to expedite the formal procedures for IIE’s membership as a Sponsor and complete negotiations on the terms and conditions on behalf of the Executive Committee.

Action 3: General Manager Peter Petrov (EU) questioned that in the text of paper GHG/11/45 suggests a desire to maintain a balance between contracting parties and sponsors, but we are now not in balance. John Topper explained that we operate under an IEA framework, and this framework does not stipulate a balance of membership types. A proposition was made to CERT by the IEA secretariat some time ago saying that if a company was 100% nationally owned, they would not be allowed to join as sponsors. But this was universally rejected, as often this does not fit with the structure of companies and ownership. Kelly Thambimuthu confirmed that although this was worded in the paper, there is nothing that prevents the balance moving either way. Sven-Olov Ericson (Sweden, Vice Chair) suggested that the word ‘balance’ doesn’t need to mean equality of numbers; it can mean balancing activities to offer value to both CP’s and Sponsors. The diversity of sponsors that we have is a very important point of our programme, and gives us access to a wide variety of expertise. Gunter Sidiqi (Switzerland) suggested that the balance of numbers would not necessarily support our goals so we should not be too driven towards an equality of numbers. Kelly Thambimuthu summed up the potential value of sponsor members from a variety of countries – if Chinese companies expressed a wish to become sponsors, it would be very good for the programme, regardless of CP status. 9. FINANCIAL REPORT / ANNUAL ACCOUNTS 2010/11 Members Accounts Document GHG/11/42 refers. John Gale presented this item. The audited member’s accounts for 2010/11, approved by the IEA EPL Board were sent to members prior to the ExCo meetings. The accounts show a surplus of income over expenditure of £228k. This however includes the £170k from the surplus of GHGT-10 which members agreed to set aside to cover any financial risk for GHGT-11. The working surplus for the year was therefore more like £68k. Tony Surridge (South Africa) asked about the issues relating to the pension schemes. John Gale explained that 2 long standing staff are included in an old pension scheme that has not performed as well as hoped, and there is a statutory requirement that the company covers the shortfall. Most staff fall under the Rio Tinto scheme, which remains very healthy. The new accountants have also revisited the previous years’ figures and the stated loss was an error, and in fact we made a surplus of income over expenditure for that year of £138k. The error related to the manner of the inclusion of the GCCSI funds in our accounts. Trevor Matheson (New Zealand) asked if it was worth going back further on the accounts for previous years, but John Gale explained that the issue was only relating to the GCCSI money, so there will be no further errors previously.

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2011/12 Financial Update Document GHG/11/43 refers. Membership fees are almost up to date, but there are issues with the Indian membership. The IEA desk officer for India will offer assistance in contacting the relevant people shortly. John Topper explained that it is desirable to maintain the Indian membership, and hopefully this will be remedied in the near future. Note: subsequent to the meeting contact has been re- established with NTPC who have expressed their desire to remain as members of IEAGHG. Special Awards to IEAGHG Staff (In-camera session without the IEAGHG Team present) The Chairman reminded members of email correspondence with all members in which he had obtained agreement on a special award to John Gale in recognition of the excellent performance in his role as General Manager since 2007 and to mark the milestone of the programme’s 20th anniversary. He had also received comments from several members suggesting that all staff be considered for a similar type of award. He was supportive of this and had been in communication with the Operating Agent’s CEO on the topic. He now recommended that a suitable reward also be made to every deserving member of the GHG team and that this be implemented at the discretion of the CEO and GM of the Operating Agent. In the ensuing discussion it was agreed to call this a “Special Performance Recognition” award. John Topper assured members that the overall cost of the awards to both John Gale and GHG staff that he had discussed with the Chairman was well within the programme’s ability to afford. Also, he would not benefit in any way from these decisions himself. 10. ISSUES ARISING FROM WPFF MEETING Document GHG/11/44 refers. John Gale explained that the GHG IA’s request for a renewal of it operating mandate had been unanimously approved by the WPFF. One question in particular raised at the meeting regarding overlap between IEAGHG and IEACCC, which had been addressed in the meeting but there was an action for the Operating Agent to report back to the WPFF on this matter in December 2011. Peter Petrov (EU) explained that he is a member of both GHG and CCC ExCo’ s and confirmed in his opinion there is no overlap. 11. REPORT ON IEACCC STRATEGIC PLANNING ACTIVITIES No paper. John Topper explained that the IEACCC was going through its renewal process and an ad hoc strategic planning group had been set up to review its future work programme. He reinforced that it was important for IEAGHG and IEACC to collaborate and mutually reinforce each other. IEACCC’s core product will continue as now to be specialist reviews, different from IEAGHG’s engineering based studies. The only area of overlap is on CO2 capture, but again the different operating methods of the two groups mean they do not overlap. Also IEAGHG is running specialist conferences on aspects of capture, whereas IEACCC runs a more general conference on clean coal technology that includes some capture aspects. A yearly annual EPL meeting is held to reinforce the different areas of operation. Members accepted this information and the statements about mutual reinforcement without comment. 12. IEAGHG STRATEGIC PLANNING Ad Hoc Committee Feedback to Members Document GHG/11/45 refers. John Gale presented this agenda item, describing the changes to the strategic plan, and the proposal to undertake a SWOT (Strengths, Weaknesses, Opportunities & Threats) analysis to determine where our future focus should centre. John Carras (Australia) pointed out that the activity via email by the group was very thorough, and the engagement of the issues was beneficial. Secondly, the concept of the SWOT analysis was strongly supported by all members. This was undertaken at the 10 year mark, so this is a particularly relevant time to repeat the exercise. Krishnaswamy Sampath (ExxonMobil) asked what was meant by the term competitor analysis. John Gale confirmed that we were simply trying to avoid repetition of effort by ourselves and groups such as CSLF and GCCSI. We know that the CSLF mandate will expire during our current 5 year term, and we do not know whether or not they will be extended, so we need to be aware of the efforts of other groups. Richard Rhudy (EPRI) pointed out that CCS is sitting within a changing landscape – we must ensure that we can determine our near term future effort, i.e. what topics would be topical and relevant in the current economic and political climate. Arthur Lee (Chevron) suggested that we should look at scenario planning coupled with SWOT analysis to help insure against different situations that may or

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may not unfold. Dominique Copin (TOTAL) asked about the technical focus of the strategic plan, finding that the focus on storage should be strengthened. Kelly Thambimuthu proposed that this should be a facilitated exercise, and volunteered to chair the meeting as necessary, with the GM providing secretariat support. Members were asked to approve this activity, and agreement was unanimous. Action 4: Chair/General Manager Kevin McCauley asked whether the strategic plan document was finalised, but John Gale explained that the document was always subject to review, and following the SWOT analysis, the document would be revisited to ensure it remained current. 13. UPDATE ON ACTIVITIES LEADING UP TO COP17 Document GHG/11/46 refers. Tim Dixon presented this topic, updating the ExCo on the activities since the previous COP in Cancun and in the run up to COP17 in Durban. In addition, there is a proposal to develop an ISO standard for CCS, and members are asked to approve IEAGHG contributing directly to the ISO Technical Committee (International), and associations with the BSI mirror group; the regulatory working group. Jay Braitsch (USA) asked what the intention was for the ISO standardisation to achieve. Tim explained that the overall objective was harmonisation of the processes in different areas, taking the best elements of each and creating a standard. Tim Hill asked if there was an indication of timescales that they can deliver standards. Tim confirmed that there is no indication, and the process will likely take several years to complete. Tony Surridge (South Africa) suggested that we are a good organisation to be involved as we are so multilateral in our membership. Sarah Edman (ConocoPhillips) suggested that the regulations in the USA are intended to be adaptive as the situation is still not clearly defined, to this end, it is a good idea for us to be involved from an early stage as we can try to ensure that regulations do not make the projects economically unfeasible. She also asked whether these standards intended to look predominantly at storage or capture and storage, Tim confirmed that they would address all aspects of the CCS chain, but probably not public perception. They would however include such elements as MMV. Sven-Olov Ericson (Sweden) asked whether ISO was primarily an industry standardisation, and in this respect, the programme would appear to be an objective party with no hidden agenda, and we represent a lot of groups that are not able to take an active part in this process. Phil Sharman expressed that although Alstom usually would be pro an early standardisation it feels it is too early for standards discussions, but as they are going ahead, it is beneficial for IEAGHG to be involved to try to prevent wrong turns. Gina Downes (CIAB) also supported this, possibly getting other IA’s to be also involved. Kelly Thambimuthu summed up members comments that we must be as pragmatic as we can in undertaking this activity. 14. DISCUSSION PAPERS Techno Economic Assessments and Costs Document GHG/11/47 refers. John Davison presented this agenda item. The review was conducted as the study proposed at the 39th ExCo was not approved, but due to the popularity of the proposal in the voting round, it was determined that we would review the data and research already underway to determine if there is a value in an outright study. Jay Braitsch then presented on the work underway by the US DOE on similar subjects to put the review paper into perspective, showing the work on cost of electricity production with CCS and how this has reduced over time as new advanced technologies have come into play. Tim Hill (EoN) observed that producing this review has proved to be a good manner to identify the issues and provides the members with a better opportunity to develop an understanding of the specifics of a subject. The wide range of topics we deal with could be part of the reason that we receive so few suggestions from members; it could be that these reviews provide the insight required for members to propose more study topics. Tony Booer (Schlumberger) suggested that the best way to learn about costs is to undertake work, and then see how much it costs, as modelling studies are only indicative, not representative. Johannes Heitoff (RWE) suggested that costs are moving entities, and creating cost studies will be an ever repeating exercise, and we need to identify the costs of the whole CCS chain, and the individual elements. We could then determine through another study the target costs, which would enable us to see what needs to be done to go from actual to necessary costs. Sarah Edman (ConocoPhillips)

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supported extending the suggested future work, as although the storage costs may be 2-5% of the capital costs, on a relatively small~$1bn project, this means a cost of between $20-50 million. We need to identify the storage costs as this is often overlooked. Peter Petrov (EU) questioned the costing of a baseline power plant, and flagged a recent study that looked at this for all 3 capture technologies, and this could provide some of the answers to the questions raised. A lot of the information that would be required for such studies would however be sensitive, and possibly proprietary, which could complicate the data gathering process. Also, it could be beneficial to look at costs going on to 2030 and beyond as there are some studies published that are very pessimistic in their outlook, and we could benefit from an unbiased thorough view. Gunter Sidiqi (Switzerland) explained that there are plans in place in Switzerland to revise the relevant legislation, so it would be interesting to look at the cost of capture from industry. Juho Lipponen (IEA) responded on behalf of the IEA, suggesting that there is no question as to whether we should look at costing issues as it is a very important area for further work. Secondly, capture in industry is an increasingly important area, and this should be included in the future work in this area. John Topper explained that there is an equal interest from the IEACCC members on this topic, so this would be an ideal area for collaboration. Bill Spence (Shell) pointed out that comments about learning curves are fair, but we must be aware that there are fewer demonstrations around than we had hoped, so anything that can move us along the curve faster would be valuable. Kelly Thambimuthu commented that the learning curves we are on are valuable in themselves, current plants will not be the epitome of cost efficiency, but the future plants may be so we should identify these curves. Helle Brit Mostad (Statoil) suggested that before deciding on which study becomes the baseline, a review of what is already available should be completed, including the disclosure of differences in the existing studies with an explanation of these differences. The achievements of several EU projects should also be incorporated into the review, and it could also look at open FEED studies such as the Longannet work. These could assist to calibrate against other open studies such as the NETL/DOE study. Richard Rhudy (EPRI) pointed out that if we work on the basis of the costs associated with 1st generation technologies, it could be potentially very different to nth generation technologies. This needs to be emphasised to avoid over-reliance of any work produced. Arthur Lee (Chevron) and Philip Sharman (Alstom) suggested that the role of the baseline study is important, and we do need an update of baseline data, for coal and gas, so that comparisons can be made as necessary. Kelly Thambimuthu summed up that the discussion and asked that the General Manager to review the comments received and respond with study ideas to the ExCo for consideration at future meetings.

Action 5: General Manager

Integrating Renewables into Fossil Based CCS Plants Document GHG/11/48 refers. Mike Haines presented this agenda item. Sven-Olov Ericson (Sweden) commented that this appears to be an interesting area, but it appears there are no synergies between this and the CCS case, Mike Haines confirmed that the integration of steam is the option that appears most favourable, with the least impact on the economics of the operation. Mike Haines pointed out that there are also issues with the land use surrounding these plants, trees, agriculture etc. Richard Rhudy (EPRI) asked for clarification of the efficiency of the steam turbines, and Mike Haines explained that the turbines only operate at 50% efficiency at night, so the overall efficiency was adversely affected. You have to either design the turbines for the night time operation or daytime, but not both as the turbine must turn at a constant speed, and any gearing options introduce similar losses of efficiency. Jay Braitsch commented that the USDOE had a project that didn’t quite make it to actualisation, and asked if this was the programmes first foray into renewable and CCS, and John Gale confirmed it was. John Carras (Australia) commented on the importance of this study and its conclusions, which clarifies the wishful thinking as such, and asked that this be published as swiftly as possible as it is very important. Gunter Sidiqi (Switzerland) suggested an amendment to the title, so as not to appear to be disregarding all renewable integration, but to focus on the solar thermal integrations.

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Action 6: General Manager

Storage Costs Study Phase 2 Document GHG/11/49 refers. Sam Neades presented this report to members, and asked the ExCo to discuss whether to continue with phase 2 using the ZEP model, with its inherent confidentiality issues, or whether we should start from phase 1 again, to develop a fully transparent model. John Gale explained that the latter of these two options would be substantially more expensive, but would be more valuable. Richard Rhudy (EPRI), Eddy Chui (Canada) and Helle Brit Mostad (Statoil) all expressed the opinion that the fully transparent model would be more beneficial, together with our impartial unbiased view. John Gale clarified that the higher cost would be in the ‘higher than average’ range of study costs. Kelly Thambimuthu summed up that we would proceed with a new model from first principles. Tim Hill (EoN) asked if members would have the opportunity to guide the direction of the model, and John Gale confirmed that input from members would be most welcome.

Action 7: General Manager Shale Gas Methane Releases Document GHG/11/50 refers. Steve Goldthorpe presented this item, with a short video animation to describe the process for drilling, fraccing and producing the shale gas. Many members had various comments about the suitability of the options for further work, A, B, C and D, and these are detailed in the further agenda item in GHG/11/67. Peter Versteegh (Netherlands) suggested that our remit is relating to greenhouse gas emission reductions, so we should look at shale gas production from a perspective of mitigating emissions. Kelly Thambimuthu commented that we need to understand the processes and issues before we can assess the mitigation aspects. Phil Sharman (Alstom) commented that as any unconventional gas resources become more relevant in the energy balance, we need to ensure we maintain our position of unbiased knowledge, and maintain an awareness of the situation. John Carras (Australia) commented that we should not limit this work on fugitive emissions to gas, as we don’t actually understand coals as well as we think we do, so this should be encompassed as well. Ship Transport – Review of Work Underway Document GHG/11/51 refers. John Davison presented this topic. Peter Versteegh (Netherlands) asked if the ships could be used for transport for other gases, or whether they are for one purpose only. John Davison confirmed that it can be done, but the cleaning between gases would come into play. Brendan Beck (South Africa) asked from a regulatory perspective, and the London Convention currently prohibits cross boundary transport of CO2, how would this work within country boundaries. John Davison accepted that this is a potential limiting factor. Helle Brit Mostad agreed that the transportation element of the ZEP study was good, and Statoil are working on this topic, and the opinion is currently that neither of the transportation studies should go ahead at this stage. Klaas van Alphen confirmed that the GCCSI is also working on this independently. Kelly Thambimuthu asked for comments on the option of going ahead with a revised scope, or not at all. Helle answered neither, and no other objections were made. A further study on ship transport was therefore deferred. Review of Work Underway on Alternative Capture Systems Document GHG/11/52 refers. Steve Goldthorpe presented this agenda item. Gunter Sidiqi (Switzerland) suggested we must keep abreast of these non-conventional solutions, so this is a valuable topic to maintain a watching brief on. Phil Sharman (Alstom) asked whether ocean seeding with plankton was considered, and commented that co-firing with the right balance could be a good option for zero / negative emissions. Steve Goldthorpe responded that plankton seeding was not considered, and Phil said that Southampton University were planning a project looking at this to include costs. Tim Hill (EoN) asked if there were plans for this paper to be released as a technical review, and John Gale confirmed that we can. Peter Petrov (EU) suggested it would be a good resource for members, and that we should continue to monitor and maybe assess the alternative capture systems vs. CCS (for example), but should not express explicit support for any system due to potential controversial aspects from an environmental point of view. Brendan Beck (South Africa)

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suggested that these papers should be produced as short information papers, on this and similar topics. Sven-Olov Ericson commented that the Biochar option appears feasible, and this should be the focus of such studies. John Gale explained that there was no initial scope It was an opportunist activity, but one that we can expand so that it is a more comprehensive summary of these options.

Action 8: General Manager Public Summary Brochures: Review and Update Document GHG/11/53 refers. Toby Aiken presented this paper. Peter Petrov (EU) and Helle Brit Mostad (Statoil) expressed their approval of the activity, commenting on the importance of providing public information. Monica Lupion (Spain) suggested that the EU ZEP communication task force be engaged to align activities on this topic. Brendan Beck (South Africa) suggested that a further activity of worth would be for IEAGHG to conduct a peer review of the CCS pages on Wikipedia. Kelly Thambimuthu suggested that we look at this in the context of different energy scenarios. John Gale agreed that we could look at different options – energy efficiency, renewables, and other low carbon options. Juho Lipponen offered a selection of information providing the pro’s and con’s of different options, from the IEA sources.

Action 9: General Manager 15. COMPLETED / ONGOING ACTIVITIES Quantification of Leakage Document GHG/11/54 refers. Ameena Camps presented this completed study. John Carras (Australia) commended the study, praising the thoroughness of the data. Monitoring techniques have been overstated for some time, and this study highlights the uncertainties associated with many of them. The concept of averaging time should be included as this can have a significant impact on monitoring results. Tony Booer (Schlumberger) commented that when the study discusses inaccuracies, it should also describe the natural variance as this is often overlooked. Peter Petrov (EU) asked if contact had been made with ECCO2, and Ameena confirmed that we are in discussion with them as to whether we can take a place on the advisory body. Feasibility of Monitoring Techniques for Substances Mobilised by CO2 Document GHG/11/55 refers. Millie Reddi presented this completed study. Tony Booer (Schlumberger) commented that the terminology used in one of the tables included trademarks which weren’t recognised, so these should be identified or relabelled appropriately. Kevin McCauley (B&W) commented that the background to the study didn’t seem to match the content, and maybe the background should identify that which is probable and that which is possible. Tim Hill (EoN) commented that the overview seemed to focus on CO2 detection rather than other substances and Millie confirmed that this had been changed in the report, and she will alter the overview to mirror this. Tim Hill (EoN) asked for clarification that the mobilised substances can be used as an early warning system, and Millie agreed to check this mechanism and alter the wording in the overview if necessary. Ethical Attitudes and Underground CO2 Storage Document GHG/11/56 refers. Ameena Camps presented this completed study. Jay Braitsch (USA) commented that the approach seemed overly complicated, and asked what the theory behind the approach was, whether a simpler approach may have achieved equally useful results. Ameena confirmed that there are groups taking a simpler approach, but this was the first attempt to understand the underlying issues, cultural background and personal opinions of concerned groups. There are plans to hold a workshop to clarify the outcomes of this and unify the strategy used. Brendan Beck (South Africa) asked if there are similar situations where bodies have used this approach to overcome objections. Ameena responded that the approach has been used in other situations, but not within the CCS area. Tim Hill (EoN) asked for clarification on a point relating to the comment on this being a preliminary study, and cautioned that any follow up activity could be very costly. Peter Versteegh (Netherlands) asked if this approach should be carried out in advance of projects, or after proposed projects had been approved or declined; Ameena confirmed that the approach could be adjusted to various scenarios, be it forthcoming studies, or failed studies to determine what went wrong. Niels Peter Christensen (Vattenfall) asked for a baseline reference, to determine how this

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methodology would apply to an everyday situation as CCS appears to come out of this in a bad light. Gina Downes (CIAB) commented that a decision needs to be made for each project at what time to engage opinions, and not all opinions can be applied to ethical principles. Richard Rhudy (EPRI) suggested we should think about not publishing this report as it could be damaging; if it is published, it will be used as results regardless of the content. John Gale agreed and confirmed we would wait until the full study has been completed, and reassess the situation then.

Action 10: General Manager Emissions of Substances Other than CO2 Document GHG/11/57 refers. Mike Haines presented this completed study. Richard Rhudy(EPRI) questioned the increase of sulphur, and questioned where that was from. Mike confirmed it was due to the degradation processes involved. Evaluation of PCC Chemical Emissions and Technologies for Deep Removal Document GHG/11/58 refers. Mike Haines presented this completed study. Sven-Olov Ericson (Sweden) asked for comment on the nitrosamine issue – have some researchers detected them, and others not, so is the detection the issue? Mike confirmed that the detection has been in the solvent, rather than the vapours, but the concentration is the issue as the concentration is often very low, which makes detection complex. There is a forthcoming project where an attempt to monitor them in the emissions will be made. John Topper commented that at the PCC conference a conclusion was forwarded that nitrosamines are probably limited to accumulation in the solvent, so from this it is anticipated that they will only be found in the solvent, and not the vapour as they are relatively heavy. Mohammad Abu Zahra (Masdar) commented that the number of case studies are limited, so comparisons are relatively tricky, and cannot be relied on. Mike Haines commented that the legislative limits are within the technical study, and this is addressed. Klaus Schoffel (Norway) commented that this is of relevance in Norway, and the Norwegian government was concerned about such emissions, and worried that it would affect the applicability of the technology and was preparing to delay Mongstad. The emission allowances for the Mongstad plant have been set and were based on published and recommended values for the concentration. The atmospheric chemistry is very complex, and needs to be fully understood. The establishment of international emission standards is very important. Johannes Heitoff (RWE) commented that they have operated a pilot plant for 18 months, and have not detected nitrosamines, but this could be dependent on the monitoring technique used. Phil Sharman (Alstom) commented that the legislative limit may be set at a level that is undetectable, and this would be a bad situation to find ourselves in. It is therefore desirable that we understand detection limits before standards are set. Sven-Olov Ericson (Sweden) commented that this was an interesting discussion, but until we know what the emissions are we cannot ask for regulations and standards, as we need a greater understanding before legislation can be set. Helle Brit Mostad (Statoil) commented that this was a high quality study which incorporated a lot of work. Furthermore there are limitations on the scope of the study which restricted it to look solely at MEA and also limited the study to only consider ASPEN modelling; thus the study does not mention the nitramines or the photo-catalysed degradation products. Emission standards are not yet established for many substances, and the analytical decision techniques struggle to identify compounds that may be dangerous at very low levels; because of this it is important to include detection techniques and analytical methodologies in further research. Overview of Iron and Steel Study Document GHG/11/59 refers. Stanley Santos presented this completed study. Stanley explained that this was the first part of a larger report. Tim Hill (EoN) commented that this type of highly technical engineering study is exactly what we should be doing, he questioned that this was only part funded by IEAGHG and Stanley confirmed that this study is funded by a consortia, and this is necessary as the scale of the study would put it outside our affordability range if we were to undertake it solo. Tim Hill (EoN) followed up to ask if this funding mechanism affected whether this was classed as an IEAGHG report and it was confirmed that it would. Kelly Thambimuthu commented that the capture cost per ton appears only slightly higher than from power generation, and Stanley confirmed that the costs are expressed in CO2 avoided, so for complete capture, you need to allow for additional cost. Richard Rhudy (EPRI) asked where the energy for these processes came from, whether there is an additional

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energy supply need. Stanley responded that there is a need for an additional energy supply. John Carras clarified that the Australian government has introduced a carbon tax at $23 ton. This has caused consternation for the steel industry, but there is also a compensation package available. This report will therefore be particularly interesting to many in Australia. Johannes Heitoff (RWE) questioned the efficiency rating of the plant, and suggested that this appeared lower than that being experienced within similar plants in Germany. Jay Braitsch (USA) questioned the market concerned would be predominantly retrofit, and questioned the availability of space for retrofit; is this likely to be a problem. Stanley confirmed that the market would be mainly retrofit, but the area needed would likely be available. Richard Rhudy (EPRI) commented on the need for installation of new equipment for additional steam and electricity, and whether this would cause issues as well. Stanley confirmed that these figures are included in the report, and the integration issues are still undetermined, and depends on the individual steel mill. Summary of Key Points from Storage Networks Document GHG/11/60 refers. Tim Dixon presented this item, covering the conclusions from the Monitoring, risk assessment and combined wellbore integrity and modelling networks. Jay Braitsch (USA) asked whether there was discussion of the inducement of seismic activity where none had been recorded previously, and Tim confirmed that the RA network did discuss this, but this is an area where prediction is complex and would benefit from real experiences. Gunter Sidiqi (Switzerland) commented that although most news is of a negative nature, we should focus on the positives such as the issues with geothermal storage taking place in tectonically active areas, CCS is likely to be focussed in less active areas. Peter Petrov (EU) asked about the baseline data for these events, and Tim explained that this was dependent on the geological survey of the country. If data is only recorded in the year leading up to a project, it may not be a reliable baseline. Jay Braitsch (USA) commented about the work on monitoring using tracers, and asked whether this was still used. Tim confirmed that it is still used in some cases, but requires foresight. Tony Booer (Schlumberger) suggested that if it is assumed that the pressure front of the injected CO2 can mobilise brine, then there is no point to use tracers. Feedback from High Temperature Solid Looping Network Meeting Document GHG/11/61 refers. Mike Haines presented this network report. Kelly Thambimuthu asked whether CLC had been done with gas, but Mike Haines confirmed that the efficiency is not sufficient when combusting gas. There are certain conditions whereby an alteration to the process is utilised, and in those cases, the efficiency is higher, and CLC can be applied to gas fired power generation. Sven-Olov Ericson (Sweden) queried the concerns over emissions of trace elements, could this be seen as an opportunity to concentrate the trace elements, and subsequently utilise these elements, but Mike explained that it is seen as a risk as the high temperatures involved could volatilise the heavy metal elements, although the risk is considered low. Peter Petrov (EU) commented that the technology tends to be referred to as next generation technologies, so it is satisfying that we are seeing developments in this area, and it should perhaps be considered as a nearer term technology than a future technology. Feedback from PCC1 Conference Document GHG/11/62 refers. John Topper presented this agenda item. He concluded by asking for approval for Norwegian Technical University (NTNU) Trondheim to host PCCC2 in 2013. This was accepted by members. Mohammad Abu Zahra suggested we try to encourage increased industrial participation at the conference.

Action 11: General Manager Feedback from OCC2 Conference Document GHG/11/63 refers. John Topper presented this agenda item. Monica congratulated the IEAGHG team on a successful conference, and confirmed the venue for OCC3 would be the same as the 37th ExCo in Leon, Spain. Feedback from 5th IEAGHG International CCS Summer School No paper. Ameena Camps presented this update for members, and highlighted the plans for the 6th event in Tsinghua University in 2012, and outline plans for the 7th in Leon in 2013 with Ciuden.

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16. STUDY PRIORITISATION Document GHG/11/64 refers. Tim Dixon presented this paper, explaining the votes received, and that the late received votes did not affect the order of studies. Methodologies and Technologies for Intervention during CO2 Leakage Events Document GHG/11/65 refers. Millie Reddi presented this study proposal to members. Arthur Lee (Chevron) suggested ARI could be potential contractors, along with Sally Bensons’ group at Stanford.. Tim Hill (EoN) commented that the specification should incorporate the costs involved with remediation techniques, to provide an indication of the range of costs involved with differing technologies. Sarah Edman (ConocoPhillips) suggested Ron Sweatman, API and Brent Lakeman, Alberta Innovates as expert reviewers, and asked whether the term leakage would encompass movement of the plume away from modelled directions, and whether intervention would include control of the plume. Also the term leakage suggests ‘to the atmosphere’, so we need to define the terminology carefully. Gunter Sidiqi (Switzerland) suggested we should indicate the frequency of real leakage events, so that the risks are placed in context. Niels Peter Christensen (Vattenfall) emphasised the importance of the study, and ensured that it looks at real data, not just theoretical data. The contractor should therefore be well briefed in actual analogue cases and areas to lend the study more weight when published. Kelly Thambimuthu confirmed that members approved this study proposal. The Process of Developing a CO2 Test Injection: Experience to Date and Best Practice Document GHG/11/66 refers. Millie Reddi presented this study proposal to members. Tony Booer (Schlumberger) said he hoped that the study will underline the importance of baseline monitoring as it must be included, rather than assuming it has been completed already. Brendan Beck (South Africa) questioned what would be excluded from the scope, asking whether the site would be chosen by the best storage site, or closer to the emission source, in a reasonable storage site. There would be costs of transportation issues here, so it would be interesting to see some analysis of this aspect. Also, the scope suggested that the public acceptance would not be included, but it would be interesting to see what stage this would normally be undertaken. John Gale confirmed that we need to be reasonable in our aims, and not repeat work already completed. There is a lot of work already published on when to engage the public, so we might refer to this but not repeat it. Klas van Alphen (GCCSI) questioned whether permitting would be included and John Gale commented that there are elements of this, but this is also included in the WHWL study that will be presented later. Helle Brit Mostad(Statoil) highlighted that we must be careful not to encroach on other research or to redo that which is already underway, specifically the EUROSCOOPS project (European Sizeable CO2 Storage Pilots). Gina Downes (CIAB) suggested that the rationale used in various test injections would be interesting to see compared as part of it. Richard Rhudy (EPRI) suggested that we should look at those sites that encountered problems and didn’t proceed as well as the successful examples. Niels Peter Christensen (Vattenfall) commented that the scope should not only include the large scale demos, but include the smaller operations as well and John Gale confirmed that we intend to focus on the small pilots. Brendan Beck (South Africa) suggested that countries that have not operated in CCS before would find the premise quite daunting, and a thorough repository would be very useful. Kelly Thambimuthu summed up that members approved the study, but suggested that the web tool should be viewed as a second part and returned for consideration by the ExCo at a later date. GHG Footprint and Other Issues on Shale Gas Production Document GHG/11/67 refers. Steve Goldthorpe presented this study proposal. Sven-Olov Ericson (Sweden) suggested that there is a wide variance in this set of review proposals, and we should consider revising to a scope closer to the initial proposal. The scope as presented seems to include topics away from shale gas. The timescales in the GWP calculations can determine whether the GWP’s are politically relevant – shorter times are more relevant to political elements and factors. Due to the variance in the scope, it was suggested we prepare a review paper on the GWP variances similar to the shale gas paper presented earlier in the meeting. There is the potential to develop the GWP 20, and extrapolate the GWP100 from this, so we should look into a paper to investigate these. Arthur Lee (Chevron) agreed with the recommendations in the paper, but advised caution on providing ammunition to those looking to use the GWP figures to argue against CCS technologies. Sarah Edman (ConocoPhillips) suggested we should focus on the areas that we can make a significant contribution, and the political basis of GWP calculations is not one of these areas. We should focus on the shale gas,

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other unconventional gas and natural gas utilisation issues, and this is an area where IEAGHG could actually make a contribution Kelly Thambimuthu summed up the wide variety of views expressed emphasising the controversial nature of this issue, and that it is important that we bring our impartiality and independence when undertaking this work. We will move on by looking into the topic in greater detail, but with a caveat of not reviewing the GWP until the IPCC publish their work. On the fuel cycle emissions, we will review the work underway by others, and revisit this after that. The shale gas element is an area where we should commit to, and conduct a more thorough review. Option A is to be the subject of a review, option B is out, C is in, but as a review, D is included, but only in terms of water use in CCS, contaminated water issues are not within our remit, and we do not have the expertise to cover this. John Gale suggested we broaden the scope slightly to encompass all sources of unconventional gas and this was agreed. Kelly Thambimuthu suggested we change the title to GHG footprints and other issues on unconventional gas, and this was approved. Dehydration of Captured CO2 Document GHG/11/68 refers. Mike Haines presented this study proposal. Tim Hill (EoN) commented on the specification, noting that there is a suggestion of less stringent water standards for supercritical CO2, but this should be the same standard for low pressure CO2. Mike responded that transporting supercritical CO2 involved less corrosion issues, hence the less stringent standards. Tim Hill (EoN) asked if the conclusions would contain comments on reliability and the connections with efficiency and CAPEX / OPEX etc. Mike confirmed that this would be addressed. Phil Sharman (Alstom) supported this study as it is particularly relevant to the oxy systems work that Alstom is involved with. Peter Petrov (EU) suggested it would be worth mentioning the volume of glycol that would be required as this is something that is currently uncertain. Mike confirmed he would look into this before confirming. Kelly Thambimuthu summed up that the study was approved. Biomass CCS – Guidance for the Accounting of Negative Emissions Document GHG/11/69 refers. Tim Dixon presented this study proposal. Kelly Thambimuthu asked about the scope, and Tim explained that there was awareness of the IEA work, and duplication would be avoided, but additional detail on their work may be included. Peter Petrov (EU) asked is we were considering 2nd generation biomass, and Tim confirmed that it would look at 1st and 2nd generation biomass types. Juho Lipponen (IEA) commented on the complexity of this topic, and suggested that the accounting for negative emissions is one aspect, but then any credit for such emissions introduces a new level of complexity. John Carras (Australia) commented on the national level of inventory and how accounting works, and asked for clarification of whether this study would look at this level, or generic cap and trade schemes. Tim confirmed we would be looking at generic models predominantly, and use case studies to illustrate this. Arthur Lee (Chevron) commented that this scope appears clear, and worthy of our effort. Brendan Beck (South Africa) asked if the study would cover carbon tax as avoidance credits cannot account for negative emissions. Also, could another study look at how negative is negative? Tim suggested we could possibly include this type of analysis, but it might not be easy to choose an example to account for. Markus Wolfe (Alstom) clarified that to attain negative emissions, you must know what type of biomass accounts for what emissions, and there is no example of this at the moment. Kelly Thambimuthu summed up that the study was approved in line with comments received. XtL with CCS Proposal 40-02 refers. Steve Goldthorpe presented this additional proposal as the general manager confirmed we had capacity to undertake an additional study. Kelly Thambimuthu commented that the scope should be as inclusive as possible to allow ease of comparison, so gas to liquids should be included. Sarah Edman (ConocoPhillips) asked if all conversion processes were to be looked at and Steve confirmed that this would be the case. Peter Petrov (EU) highlighted some complementary work that should be checked to avoid repetition. Steve confirmed we would look at this and check. Daan Jansen (Netherlands) suggested an extension to include biomass to gas, but Kelly Thambimuthu suggested that this would be outside of the scope of XtL to liquids. John Gale suggested this could be covered in existing biomass work, so we would check this and reassess. Jay Braitsch commented that the US was interested in this as long as it confirms to certain criteria, and this study would be of

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interest. Brendan Beck commented that this would work well with some of RSA’s activities, and they would happily facilitate contact between the contractor and those working within RSA at Sasol. Kelly Thambimuthu summed up that members approved the study. 17. STUDIES TO BE RECONSIDERED FOR FUTURE VOTING ROUNDS / MEMBERS

IDEAS FOR FUTURE STUDIES No Paper. Kelly Thambimuthu confirmed that studies that weren’t selected would be resubmitted for the next voting round. 18. UPDATE ON GCCSI PROGRAMME Document GHG/11/70 refers. Tim Dixon presented this brief topic. Peter Versteegh questioned whether the final report on ethical attitudes would be presented at next years’ SRN. John Gale confirmed there are no plans to include this in the meeting. What Have We Learnt, Phase 1b Document GHG/11/71 refers. Sam Neades presented this technical review. Tony Booer (Schlumberger) commented on some of the terminology which should be unified, and Sam confirmed that this would be corrected. It was mentioned that there is a drop off in survey responses, and John Gale confirmed that this is an issue, but we are working to overcome this with assistance from key individuals or we might have to do more data mining ourselves. 19. FEEDBACK ON IEA ACTIVITIES No Paper. Juho Lipponen presented this update to ExCo members. Juho described the continued analysis contributing to the WEO activities, and the role of CCS within this. Kelly Thambimuthu questioned the fuel use patterns in the newest WEO, with the implications for CCS being that there will be more gas fired plants going forward, and in response to the G8 initiative, there was the blue map scenario requiring revision. If you look at the emission profiles, it is different now, so will the pathway projections be revised in line with this. Juho confirmed that this was in hand, and the normative modelling is linked. Next years’ ETP would likely throw more light on this, and the CCS roadmap is under revision as we speak. Peter Petrov (EU) asked what was intended by the bullet of publication on CCS in China, and this was explained as a publication that was developed in conjunction with a Chinese partner, and is a fairly general publication. 20. FEEDBACK ON MEMBERS ACTIVITIES No paper. Four members wished to contribute. Firstly, James Godber from the UK made a statement about the UK position, relating to the recent announcements on the UK CCS competition. He outlined the plans for CCS deployment within the UK and also the work taking place to deliver the Clean Energy Ministerial in April 2012. The Secretary of State (Chris Huhne) remains firmly committed to CCS, as evidenced by his recent visit to Beijing for the Carbon Sequestration Leadership Forum Ministerial. Following the decision not to proceed with the Longannet proposal, £1bn capital funding remains available to support early CCS projects in the UK. Building on the lessons from Longannet, the government will be launching the new competition as soon as possible. Internationally, the 2nd Clean Energy Ministerial in Abu Dhabi established a number of policy, regulatory and financial targets for the countries to make progress against and the UK hope that the London Ministerial will provide a platform for demonstrating progress. Daan Jansen reported to members that the Dutch ministry for economic affairs have withdrawn funding, but efforts are being made to continue with funding from other mechanisms. Peter Versteegh (Netherlands) informed members that this would be his last ExCo meeting as he is due to retire before the next meeting. Eddy Chui (Canada) will provide a presentation for distribution to members post meeting, but wanted to inform members that the IEAGHG supported Weyburn-Midale project received recognition from CSLF recently. Jang Kyung-Rong (Korea) presented an update to members on Korea’s CCS activities, outlining the plans to invest $1bn (US) by 2019 on there CCS roadmap. They are developing proprietary amines for

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the capture process, and are working on the success of the 0.1MW plant to develop a 10MW plant between 2014-18. 21. DONM Document GHG/11/72 refers. Sian Twinning presented this paper. The 41st ExCo meeting will be held in Bergen, Norway on the 7th to 10th May 2012. The meeting will hopefully include a site visit to Mongstad. 22. AOB 23. CLOSE OF MEETING Kelly Thambimuthu closed the meeting, bringing attention to the 20th Anniversary Booklet. He thanked members for their input to discussion and to enjoy the event planned to commemorate our 20th anniversary.

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CORRECTIONS TO MINUTES

Three members of the ExCo requested textual changes to sentences that were attributed to them, which were made as requested. Members are asked to formally approve the minutes.

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LIST OF ACTIONS

Action

No. On Action Status

1 General Manager

Feedback at 41st ExCo Webinar Results At Meeting

2 Members Register for Website On-going 3 General

Manager Complete Negotiations with IIE Complete

4 Chair / General Manager

Complete and report SWOT Analysis Complete

5 General Manager

Draft Study Proposals on Baseline Costs Complete

6 General Manager

Amend title of Technical Review to Integrating Solar Options

7 General Manager

Develop Cost Model from first principles In-hand

8 General Manager

Expand work on Alternative Capture Systems In-hand

9 General Manager

Develop info papers on different energy options In-hand

10 General Manager

Assess final report on Ethical Attitudes and determine whether to publish

Complete

11 General Manager

Proceed with negotiations for Trondheim to host PCCC2. Look to increase industrial participation

In-hand

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PROGRESS REPORT

Introduction This report provides a summary of activities completed since the last ExCo meeting (40th) held in London, UK in November 2011. The report covers a 6 month period which included the Christmas holiday period. Staff Changes The new staff members: Dr Prachi Singh and Dr Jasmin Kemper started work in December 2011 and are both making effective contributions to the team’s efforts. Steve Goldthorpe also left to return to New Zealand in December 2011 but has been continuing to contribute the teams activities on shale gas under contract. Neil Wildgust’s position has not yet been filled. Neil has still been contributing to the teams activities as per our agreement with PTRC. A decision on how or if the replace Neil will be taken after the SWOT/Scenario exercise is complete and the budget for next financial year has been agreed. Office/Operational Changes We have made some modest changes to our office space with kitchen improvements and the addition of multiple desks in three rooms to allow staff to double up when we have secondees in during the summer. Demolition of the old office buildings on the Stoke Orchard site is well underway and is expected to end in April 2012. After that time construction of housing will begin. So far we have had only one problem when our internet/phone lines were accidentally cut, full functionality was returned in a couple of days. We hope that there will be no more disruptions in the coming months. The current lease on the office premises expired on 31st March 2012. After a due diligence exercise IEA EPL agreed to renew the lease for a further 5 years. The new parking arrangements on site are considered to be an issue and are being discussed with the landlord at the time of writing this paper. Progress on Delivery of the Technical Programme a) Technical Studies A summary of the status of studies is presented at the time of drafting this paper is provided, an updated summary will be presented at the ExCo meeting. Studies in progress Studies that are expected to be published between the 40th and 41st meetings, studies that will be underway at the time of the 41stth meeting and studies that are outstanding are summarised in the tables overleaf.

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Table 1 Technical Studies published since the 40h ExCo meeting Title Contractor Report

number Publication date

Geological storage of CO2 in Basalts IEAGHG 2011/TR2 September 2011

Feasibility of Monitoring Techniques for Substances Mobilised by CO2 Storage in Geological Formations

CO2CRC 2011/08 December 2011

Quantification Techniques for CO2 Leakage CO2GeoNet 2012/02 January 2012 Integration of Solar Energy Technologies With CCS

IEAGHG 2012/TR1 March 2012

Emissions of substances other than CO2 from power plants with CCS

TNO 2012/3 March 2012

Technologies for Deep Removal of Amines, Additives and Other Degradation Products from Flue Gas Emissions of Post-Comb. Capture

CSIRO 2012/4 April 2012

Table 2 Studies being reported Title Contractor Publication date CCS Capacity constraints Ecofys June 2012 Ethical Attitudes to CCS UMIST June 2012 Iron and Steel Study MEFOS June 2012 Capture in Gas Fired Power Plant Parsons

Brinkerhoff June 2012

Operating Flexibility of CCS in Future Energy Systems

IC Consulting July 2012

Financial Mechanisms for Long Term Liability ICF July 2012 Abstraction of Brine from Geological Storage Formations

EERC August 2012

Key Messages for Stakeholders Univ. Edinburgh August 2012 Table 3: Studies underway Title Contractor Draft Report date Incorporating future technological change in existing capture plants


Induced seismicity CO2CRC August 2012 Post Combustion Capture Scale Up and Challenges

Black & Veatch October 2012

Implications of Gas Production on Shale’s and Coals

ARI October 2012

Subsurface resource interactions CO2CRC September 2012 Incorporating future technological change in existing capture plants


Co2RiskMan DNV June 2012 Monitoring Selection Tool BGS December 2014

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Table 4: Studies out to tender Title Proposal number CO2 Migration Mitigation Options 40-08 Dehydration of CO2 40-01 CO2 Test Injection Development Process 40-18 Table 5: Studies outstanding awaiting start Title Proposal number Potential for Reducing the Life Cycle GHG Emissions of CCS Plants 38-09 Biomass CCS – guidance on accounting for Negative Emissions 40-15 b) Facilitating implementation.

The IEAGHG helps to facilitate the implementation of CCS by: participating in key meetings to support CCS policy /implementation strategies and by undertaking workshops or studies to provide information that is needed to assist implementation. Meetings that IEAGHG has participated since the last ExCo include:

• UNFCCC. COP-17 was held in Durban. Tim Dixon attended, working with GCCSI and seconded into the UK government DECC to participate in the negotiations representing the EU. Reports on the successful outcome of CCS in the CDM were sent to members on the 9 and 12th December. IEAGHG worked with GCCSI and CCSA, co-organising one side event and speaking at other events and disseminating IEAGHG publications on GCCSI and CCSA stands. Further details are provided in paper GHG/12/13. In addition, the UNFCCC has requested Tim Dixon to attend and present in a workshop on the CCS-aspects of the future work of the CDM and JI mechanisms on 25th March in Bonn.

• CSLF Technical Group/PIRT. Limited activity over this period, some work in preparation for the CSLF TG meeting in June in Norway. On the study proposals from CSLF, the Basalts study was completed internally by IEAGHG and published as IEAGHG 2011/TR2 in September and the Implications of Gas Production on Shale’s and Coals study is underway and due late 2012.

• EU ZEP. No activity over this period. • Joint Task Force on Bio-CCS is a task Force set up by ZEP and the EU Biomass

Technology Platform to address development and deployment issues for biomass use with CCS, including co-firing. IEAGHG (Tim Dixon) is a member. The JTF organised an international workshop on Bio-CCS on 25-26 October in Cardiff UK, IEAGHG co-sponsoring and gave a presentation and chaired sessions. A report from this will be produced. Tim Dixon participated by phone the Joint Task Force meeting in Brussels on 16 March. Work continues on a research and deployment document, and a workshop will be organised for later in 2012.

• IEA Network of CCS Regulators. IEAGHG assists IEA with this Network. IEAGHG contributed to the third edition of the IEA Legal and Regulatory Review (due out soon). All this material and information from the IEA Regulators Network is available at: http://www.iea.org/subjectqueries/ccs/ccs_legal.asp. The next meeting will be on the 9 and 10 May 2012 (coincides with the ExCo).

• London Convention. The annual meeting of the London Convention was held on 17-21 October in London. Transboundary CCS was on the agenda. IEAGHG (Tim Dixon and Ameena Camps) participated, providing technical updates on topics of relevance and assisting IEA CCS Unit with their legal work on the transboundary issue. Ratification of the transboundary amendment continues at a slow pace. No progress was made in the meeting on the revision of the CO2 Guidelines to take into account transboundary

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issues. The UK ceased to be the lead of this working group, and subsequently Korea took up the lead. IEAGHG are contributing in this working group.

• CCSA. IEAGHG (Tim Dixon) participates in the Post-2012 Working Group. IEAGHG (Tim Dixon) is also an observer in the CCSA Working Group on Regulation. IEAGHG anticipate participating in the meeting on the 27 January.

• EU CCS Demonstration Network. IEAGHG participates in the EU CCS Project Network Advisory Forum. No activity over this period.

• CCUS Action Group. IEAGHG was invited to take over the lead of the storage working group of the CCUS AG. IEAGHG (Tim Dixon) took this on. IEAGHG then contributed to the work that resulted in the CCUS agreement at the Clean Energy Ministerial in Abu Dhabi in April 2011 where Ministers endorsed the eight recommendations on financial gap, funding in developing economies, legal and regulatory frameworks, marine treaty amendments, sharing knowledge, investigating CO2 storage, supporting CCS in industry. GCCSI and IEA will report on progress to the Clean Energy Ministerial in 2012. More information can be found at http://www.cleanenergyministerial.org/CCUS/index.html .

• ISO TC265 on CCS. The new work by ISO to develop standards on CCS was reported at the 40th ExCo. Following members approval for IEAGHG to be directly involved, IEAGHG formally applied to be a Liaison Organisation to TC265. This was accepted by ISO on 13 March, and now goes to the TC265 for approval. IEAGHG will participate in the first meeting of the TC265 on 5-6 June in Paris.

• UK FEED studies, The Office of CCS in DECC published the details of the two FEED studies from the UK competition in London in January 2012. John Gale was asked to chair the two day meeting.

The 2012 IEAGHG International CCS Summer School will be held in Beijing, China hosted by Tsinghua University, and work is underway liaising with Tsinghua University in the organisation. The call for student applications generated 206 applications. Potential additional sponsors are being sought.

Following the success of the CO2QUALSTORE project IEAGHG was invited to join a new Joint Industry Project (JIP) called CO2RISKMAN. IEAGHG has now joined. The aim of CO2RISKMAN JIP is to develop guidance for the emerging CCS industry on effective risk management of HSE major accident hazards from the CO2 stream within a CCS operation. The project kick-off meeting was held on 7 September meeting in London and attended by Sam Neades, who is now on the on the CO2RISKMAN steering committee. Partners in the project include: Shell, Vattenfall, Gassco, National Grid, HSE, PSA, UK’s Environmental Agency, EON, DECC, Gassnova, Norton Rose, IEAGHG, Air Liquide and the GCCSI. DNV’s intention is to initiate the CO2RISKMAN JIP as quickly as possible, with guidance release in mid-2012. IEAGHG participated in several expert workshops during November. Workshops which had to be postponed were on intermediate storage and shipping, due to lack of availability of experts. A first draft Guidance report was issued in January and comments provided back.

IEAGHG’s activities under the GCCSI contract also fall under this theme but progress on this activity will be reported separately to members see paper GHG/12/31.

c) Facilitating international collaboration International Research Networks There have been no network meetings since the 40th ExCo. In 2012 there will be a second Joint Networks Meeting of the storage network, hosted by LANL in June. In addition, there

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GHG/12/06

will be the third meeting of the Social Research Network hosted by CSIRO in Brisbane, the fourth High Temperature Solid Looping Network hosted by Tsinghua University, and an Environmental Impacts workshop (focussing on controlled releases) hosted by Montana State University in July Planning for all these is underway. The meetings are listed in the table below: Network Date Venue Hosts 3rd Social Research Network

12th – 13th April 2012

Brisbane, Australia CSIRO

2nd Joint Networks Meeting.

19th –21th June 2012 Santa Fe, USA LANL

Environmental Impacts Workshop.

17th – 19th July 2012

Bozeman, Montana, USA

Montana State University

4rd High Temperature Solid looping Network

tbc Beijing, China Tsinghua University

Reports on all the 2011 network meetings have been published except for the Risk Assessment network which will be published in March 2012. ) The network reports published since the last ExCo meeting are: Network Report No. Publication Date Combined Modelling and Wellbore Integrity Network Meeting – Summary Report

2011/13 October 2012

7th Monitoring Network Meeting – Summary Report

2011/14 November 2011

2nd Social Research Network Meeting – Summary Report

2011/12 November 2011

6th Risk Assessment Network Meeting – Summary Report

2012/5 March 2012

The presentations given at all these workshops and the reports have to date been hosted on the website: http://www.ieaghg/org. Practical R&D Activities. IEAGHG is no longer directly participating in any EU supported practical R&D projects. IEAGHG does provide in direct support in an advisory capacity to the Mustang, RISCS and ECO2 projects. IEAGHG is participating in the IEAGHG Weyburn-Midale CO2 Monitoring project. This project largely completed the research programme in 2011 and in 2012 will incorporate the results into a best practice guide (draft due in mid 2012). Tim Dixon represents IEAGHG on the management committee and Neil Wildgust on the Technical Committee. Tim Dixon attended and presented at the project’s PRISM meeting in Denver February 2012. John Gale is his capacity as Chair of the International Advisory Committee and Prachi Singh attended the annual technical review of the Dutch National CCS Research Programme in February 2012.

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John also acts as a member of the USDOE supported National Risk Assessment Panel (NRAP), in the USA. The joint network meeting in the USA in the summer will be held in conjunction with NRAP. Dissemination activities Website. Following the report from the 39th ExCo on the successful launch of the new www.ieaghg.org website, we now have 1216 members across 12 networks. During the period 22/09/2011 and 19/03/2012 we have had 24,436 visits with 92,938, pages viewed from 13,910 different visitors, taking into account the different reporting period, this is a slight reduction on the previous reported figures. 33% is direct traffic, 52% from search engines and 13% from referring sites. The average visitor spends 3.37 minutes on the site. The table below shows the breakdown of the location of our visitors.

Visits Pages/Visit Avg. time on site

% new visits

1. United Kingdom 4,770 3.46 00:03:34 54.88%

2. United States 2,949 3.50 00:03:00 61.55%

3. Japan 2,084 4.01 00:03:14 43.86%

4. Germany 1,542 4.21 00:04:28 28.79%

5. Australia 1,260 3.39 00:03:20 41.90%

6. France 1,245 3.39 00:02:56 37.99%

7. Norway 1,114 4.77 00:04:32 44.17%

8. Canada 1,094 5.16 00:04:19 49.27%

9. Netherlands 853 3.86 00:05:10 48.42%

10. China 700 3.93 00:03:01 50.29%

Greenhouse News Some new layout options will begin to appear over the next few issues, in an effort to keep the newsletter fresh and avoid stagnating as has occurred previously. There has been limited input from members despite regular requests for news articles, and members are encouraged to send articles to Becky Kemp and Toby Aiken for inclusion in the newsletter. Conference series. GHGT-11. Planning for the GHGT-11 conference to be held in Kyoto, Japan 18th -22nd

November 2012 is well underway. The main developments are: • 1220 abstracts received

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https://www.google.com/analytics/reporting/maps?id=25928121&pdr=20110222-20110921&cmp=average&trows=10&gdfmt=nth_day&rpt=GeoMapReport&tab=0&tchcol=0&tst=0&tscol=v0&tsdir=0&mdet=WORLD&midx=0&gidx=0&glcnt=1










GHG/12/06

• Expert Panel reviews complete, Technical Programme Committee meets 20th -23rd May

• The following organizations have agreed to sponsor/support GHGT-11: Schlumberger Carbon Services, Hitachi, Gassnova, China National Petroleum Corporation (CNPC), and Elsevier, with a donation from The Japan Iron and Steel Federation. Other parties who have expressed interest in sponsoring GHGT-11 to date include: EU ZEP and ExxonMobil

• Global Industrial and Social Progress Research Institute (GISPRI) have allocated approx 9.5M Yen for the sole purpose of simultaneous translation(Japanese only) during the plenary sessions and translation of printed material into Japanese during and after the conference (conference programme, summary etc.) As this money is strictly regulated and specific to certain additional expenses not usually incurred by the GHGT conferences, it will not be included into the main budget.

GHGT 12. Planning for GHGT-12 in 2014In Austin Texas is underway. Provisional dates are 5th-9th October. The MoU between IEAGHG and University of Texas has been agreed. Joph n Gale had the opportunity to visit the venue in Austin in February 2012. We have received confirmation that the USDOE have agreed to support the conference as the major sponsor as they did at GHGT-9. PCCC-2. The 2nd Post Combustion Capture Conference (PCCC2) will be held March/April 2013 in Trondheim, Norway in conjunction with TCCS-7 and hosted by NTNU. OCC-3. The 3rd Oxy-fuel Combustion Conference (OCC3) will be held in Leon, Spain September 2012 and hosted by CIUDEN International Journal on Greenhouse Gas Control (IJGGC). There is little news to report, the flow of papers to the journal for publication remains good. We are planning two supplementary issues this year; one on the CATO-2 Programme, one on Phase 2 of the IEAGHG Weyburn –Midale project and we will have a Special Edition in a standard Issue from the Cranfield project in the USA. New planned developments

• Social Networking. We are maintaining our presence on social media, with a continued steady growth in people following our Twitter feed, and regularly viewing our Facebook page. We are also monitoring LinkedIn, and have identified the most suitable groups which could be useful in publicizing reports and job vacancies.

• Animations & Videos. This will be looked at following the results of the Key Messages study, if animations and videos are identified as necessary, it may be the subject of a subsequent study due to the complexity of creating suitable animations.

• IEAGHG Blog. The IEAGHG Blog is up and running, plans to increase the frequency of the blogs are being developed, members are encouraged to suggest ideas for the blog, and to write and submit entries for it on subjects they deem relevant. A GHGT Blog will be developed to promote the conference in the lead up, and this will also be used during the conference in lieu of the GHGT Times newspaper.

• Information Sharing Facility - This facility is still populated by a select few members, all members are encouraged to submit information for sharing and dissemination by the programme.

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• Press Releases. Press releases will be developed for new study reports in the near future.

Publications/presentations The table overleaf provides a list of papers presented and presentations made at external conferences and workshops since the last meeting. Note: these are in addition to presentations given at our own workshops. Copies of these presentations are now placed on the member’s pages on the Programme web site for future reference.

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IEAGHG Presentations

Title Meeting Presented by Date

2012

Solvent Development for CO2 Absorption Process M.Sc. CCS Course, The University of Edinburgh, UK Dr Prachi Singh 23rd March 2012,

A summary of CCS Developments Worldwide 12th Annual APGTF Workshop Westminster, London, UK

John Gale 13-14th March 2012

Climate change and CCS as an international carbon abatement technology; Policy, regulations and financial issues for implementation; International status of CCS development

CGS Europe Spring School on CO2 Storage, Poland Ameena Camps 12th March 2012

IEAGHG Programme Updates and status of CCS

EPRI Generation Sector Programme Advisory Meeting, Arizona, USA

John Gale 22 February 2012

Technology update: Where do we stand with CCS technologies?

CERT Seminar “Carbon Capture and Storage - Regaining Momentum” Sydney, Australia

Kelly Thambimuthu 20-21 February 2012

Potential Impacts of CO2 Storage on Groundwater Resources Carbon Management Technology Conference, Orlando, USA

Tim Dixon and Ludmilla Basava Reddi 9 February 2012

CCS and the UNFCCC IEAGHG Weyburn-Midale Project meeting Tim Dixon 7 February 2012

Energy and the Environment: Intersection of Science, Technology and International Climate Policy in CCS University of Texas Tim Dixon 3 and 6 February 2012

CCS and the UNFCCC TREC STEP, India Tim Dixon 24 January 2012 Challenges for practical use and commercialisation of CCS Workshop on practical use and John Gale 18 January 2012

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http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/60_WPFF_IEAGHG_overviewEPRI_slide_deck_feb_2012_John_Gale.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Biomass_Dixon_Koornneef_Bellona_v3Groundwater_Impacts_TD.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CCS_and_the_UNFCCC_TD_INdia_24_Jan_2012_TREC_STEP.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/SsJohn_Gale_Rite_workshop_2012.pdf

GHG/12/06

commercialisation of CCS, Tokyo, Japan

CCS: How far have we come and what’s next? UKCCS Winter School Tim Dixon and Ameena Camps 12 January 2012

2011

Climate Change, emerging trends in global energy use and the role of CCS

CO2CRC Symposium Kelly Thambimuthu December 2011

An Overview of Developments in Oxyfuel Combustion Technologies for Power Plants with CCS

AFG 2011, Shanghai, China Kelly Thambimuthu December 2011

Can developing countries afford CCS? – CCS in the CDM GCCSI event at UNFCCC COP-17 Tim Dixon 1 December 2011

CCS – Transboundary Issues CCSA Side-event at UNFCCC COP-17 Tim Dixon 29 November 2011

Challenges and Opportunities for CCS in the Iron and Steel Industry

Iron and Steel Workshop, Dusseldorf, Germany John Gale 8-9 November 2011

CO2 Storage, Challenges to the Iron and Steel Industry

Iron and Steel Workshop, Dusseldorf, Germany John Gale 8-9 November 2011

Overview IEAGHG Activities and Capture Issues

EASAC Working Group on CCS, Cambridge, UK John Gale 26-27 October 2011

Overview of IEAGHG Activities on Bio-CCS Bio-CCS Workshop, Cardiff, UK Stanley Santos, and Ameena Camps, Tim Dixon, Steve Goldthorpe

25 October 2011

Incentivising and Developing a Market for Carbon-Negative Solutions Bio-CCS Workshop, Cardiff, UK Tim Dixon 26 October 2011

Review of Current Work and Progress Globally

Deep Saline Aquifers Workshop, Lodz, Poland Neil Wildgust 29 September 2011

Update on IEAGHG Activities (Including Basalt Review) CSLF TG Meeting, Beijing, China Tim Dixon 21 September 2011

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http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CarbonsqClimate_Energy_CCS_CO2CRC_Symp_Dec_2011_Dixon_Biomass_v1.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CarbonsqClimate_Energy_CCS_CO2CRC_Symp_Dec_2011_Dixon_Biomass_v1.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Pittsburgh_CaprocksThambimuthu_AFG_2011_Shanghai.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Pittsburgh_CaprocksThambimuthu_AFG_2011_Shanghai.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_-_CGS_CO2_East_Net_Mtg_Biomass_CCSIron_and_steel_industry_opening.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_-_CGS_CO2_East_Net_Mtg_Biomass_CCSIron_and_steel_industry_opening.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_-_CGS_CO2_East_Net_Mtg_CO2_Capture_OverviewIron_and_steel_industry_presentation.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/NACAP_-_Morgantown_2.pdfEASAC_summary.ppt

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_IEA_GHG_Flexiburn_Workshop_240311_-_Biomass_CCS_-_Final_Version.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Gap_Analysis_IEA_CCS_NW_Mar11_v2IEAGHG_-_EC_Aquifers_Workshop_0911.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Gap_Analysis_CCUS_NW_Feb11IEAGHG_Update_to_CSLF_TG_Sep_2011_v2.pdf

GHG/12/07


MEMBERSHIP ISSUES/NEW MEMBERS

Members Status IIE’s membership as a sponsor was confirmed at the CERT meeting in November 2011. All the formalities including the signing of the IA is now complete. Unfortunately ConocoPhillips notified us in December of their intent to withdraw from the IA, which to effect as of 31st March 2012. The reason given was that the current business was being split into two parts and in the ensuing partition they could not continue as members. The membership therefore stands at 47 members – 21 contracting parties and 26 sponsors. The status of invited parties is as follows:

• At the 33rd ExCo members invited CEPAC to join on behalf of Brazil. CEPAC’s membership is currently on hold.

New Members There are no proposals for new members to be considered at this meeting. Interested Parties The following progress with interested parties can be reported:

• Petrobras were invited to the 40th ExCo and attended as an Observer. Discussions held at the ExCo led to a number of actions to follow up with information that Petrobras asked for, these were completed. Petrobras have been invited again to this meeting as an Observer as of yet they have not responded nor followed our requests on their future intent to join or not.

• IGTP of Taiwan approached IEAGHG, with a request to join as a CP or a sponsor. Following discussions with the Legal Counsel at IEA, IEAGHG unfortunately had to write to IGTP informing them that it was not possible for them to join an IEA Implementing Agreement either as a CP or a sponsor.

• At the GCCUS conference in Beijing, the Chair met with senior representatives of the China Huaneng Clean Energy Group and the Chinese National Oil Company. These initial contacts have been followed up with invitations to both groups to consider joining IEAGHG as sponsors. However there has been no progress made on either group joining.

• Saskatchewan Power has indicated their interest in joining IEAGHG, at the time of writing this paper we have no received confirmation whether Canada would or would not support their application to join.

• Opening discussions had been held with Electricity Supply Board of Ireland re possible interest in joining as a sponsor.

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GHG/12/08


2011/12 FINANCIAL UPDATE

All membership income has been received for the year with the exception of one member. The only member not to have paid its subscription fees for the year is India. NTPC of India has indicated their desire to continue membership, but we have had a painfully slow response from them at each stage of our discussions. At the time of writing this paper management accounts for 10 months of the financial year (up to January 2012) had been received. A meeting has been held with the accountants to assess the budget out turn situation for the year and prepare ourselves for the audit in June 2012. It is expected based on projected income/expenditure for the next two months that the budget will be largely in balance i.e. matching income/expenditure. An additional income of £80k from GHGT-10 was offset by a number of unbudgeted expenditure items such as: the one off bonus paid to staff in December at members request (£22k), the SWOT/Scenarios contract (£35k), a repayment to the EU for an FP7contract (£17k) and additional cost items on the Steel Industry study (£33k) to satisfactorily complete the work programme. As of end of January 2012, IEAGHG’s financial position was healthy with £1.745m in treasury deposits, £985k cash in hand at the bank. A further £100,865 is held over from GHGT-9 and £170k is held in reserve to assist GHGT-11 as necessary.

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GHG/12/09


BUDGET FOR 2012/13

Introduction The budget proposed for the UK financial year 2012/2013 (1st April 2012 to 31st March 2013) is presented below. It was prepared on the basis that year-on-year income and expenditure should be essentially in balance.

INCOME

2012/13 Budget (£)

Contributions 1 671 000 Conferences/meetings (includes sponsorship, registration fees etc.,

255 000

Interest& exchange rate variations 12 000 Third party income 9 000 Total 1 947 000 EXPENDITURE Staff and administration costs 665 000 Travel 165 000 Technical studies and other external contracts 665 000 Meeting Costs 290 000 Communications (including publications) 18 000 Professional services 47 000 Office equipment including computing 50 000 Office: rent, rates, service charges etc.,, 47 000 Total 1 947 000

Notes on the proposed budget: Income The income is based on the current 47 members. The Conference/Meetings’ income, as budgeted, is based on projected recoveries of income from sponsorship for network meetings and the international summer school and GHGT-11. Interest is earned on money in the bank which is placed on fixed-term deposits in Treasury Accounts. Income on interest rates is based on a conservative figure similar to that received in the budget for 2011/2012. Sales and third party income includes monies recovered from sales of reports and contracts for services supplied with organisations like Elsevier for the Editorship of the Journal and income from short term contracts for pieces of work with GCCSI, such as John Gales involvement in the TAC. Expenditure Staff costs are based on 14 people (13 full-time and 1 part-time). The GCCSI staff subsidy that has been in place for the last 2.5 years expires in June 2012, hence direct staff costs are higher than previous years. Annual salary increases based on current UK RPI as of December

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2012 has been included in the budget. No further staff will be hired within the year. Salary and staff administration charges placed on IEAGHG by IEA Clean Coal Centre on behalf of IEA Environmental Projects Ltd include a proportion of John Topper’s and the Company Secretaries time as well as routine payroll, pension, and other services provided by the Operating Agent are included. The travel budget covers the cost of travel by IEA GHG team members in support of the Programme. Expenses incurred include holding Executive Committee meetings, travel and accommodation expenses in presenting the work of the IEAGHG Programme at conferences, etc. Travel costs have been based on those incurred for 2011/12 but were inflated to cover staff attendance the GHGT-11 conference. Technical studies are our main year-on-year expenditure. The number tabled is based on our forecasts of costs that will be incurred for studies underway at the end of 2011/12, estimated costs for studies currently out to tender and for studies awaiting tender. An estimate for new studies to be agreed at the 41st ExCo is also included. Meetings costs are based on the number of events planned for the year: 2 ExCo’s, 1 summer school and 4 network meetings. Costs for the network meeting where detailed budgets do not yet exist have estimated from cost data from last year’s meetings with an inflationary element included. With the exception of the ExCo meetings the summer school and network, meetings have been designed to be cost neutral or make a modest profit. The Communications line item in the budget allowed for printing and distribution of 4 editions of the newsletter “Greenhouse Issues”, 1 CD reports of technical studies , I summary booklet on studies completed, the annual review and 3 public summary (glossy) reports. Professional services include supporting services such as, insurance, accounting services, and the annual audits of accounts. Most of these costs are outsourced and have steadily increased year on year. Office equipment includes general office supplies and includes computer renewal on a 4 year cycle averaging 3 computers/year is assumed. . The last line item covers the costs (rates, rent and services) of the office accommodation Summary The proposed budget is aimed to balance income against expenditure for 2012/13. Action

Members are invited to accept the proposed budget for 2012/13.

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ANNUAL REVIEW FOR 2011

The annual review for the IEAGHG for 2011 has been drafted and at the time of writing this paper feedback is awaited from the Chair, Vice Chair and Operating Agent. A copy of the annual review will be circulated to members before the ExCo meeting and comments will be sought from members. A proof copy will be circulated at the meeting so that members can update their contact details as appropriate.

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GHG/12/11


PROPOSED CHANGES TO IMPLEMENTING AGREEMENT AND ANNEX 1

At the 39th ExCo members agreed a numbers of changes to the Implementing Agreement (IA) suggested By the IEA Office of Legal Counsel to bring the IA up to date on a numbers of issues relevant to membership issues from sponsors from developing countries. A copy of the revised IA dated 6th April 2011. IEA EPL (IEAGHG Team) would like to suggest one additional change to the IA for members to consider. Under Article 7, PROCUREMENT PROCEDURES item (b) currently reads;

(b) The Operating Agent shall not enter into any agreement for a total value of more than £100,000 without the approval of the Executive Committee;

IEA EPL (IEAGHG Team) would like to propose that members agree to increase the current limit from £100,000 to £180,000. This value has not changed for 20 years despite the increase in the overall budget. We occasionally get contracts with values that are close to or just above £100,000. In the latter case we ask the contractors to reduce them. This is becoming increasingly more difficult and IEAGHG would like to be allowed a little more flexibility to handle the larger, albeit in frequent contract sizes. The figure of £180,000 was derived from the same proportion of budget as the original figure. On inflation alone the figure would be around £140,000. In the revised IA dated 6th April 2011, no changes were made to the Annex 1. However on reading the Annex 1, IEAGHG considers that members should reconsider the Annex to bring it into line with the Strategic Plan for 2012-2017. The Annex was last amended on the 22nd April 2005. The items that are IEA GHG considers need to be changed are; 1. Objectives and 2. Scope and Means. However, it not proposed to discuss in detail revisions to the wording at the ExCo itself. We propose that following the SWOT/Scenario exercise, IEAGHG suggests revisions to Annex 1 and circulates these to the Ad Hoc Strategy Group for comment. A revised document will then be sent to members for approval at the 42nd autumn 2012.

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SWOT Scenario Exercise – Feed back to Members

At the 40th ExCo meeting it was agreed to undertake a SWOT (Strengths, Weaknesses, Opportunities and Threats) activity coupled with a Scenario planning exercise to determine where IEAGHG’s future focus should centre. An expanded Ad Hoc group comprising was formed: Kelly Thambimuthu, Chair John Carras, Australia Helle Brit Mostad, Statoil Jay Braitsch, USA, Arthur Lee, Chevron Gunter Siddiqi, Switzerland Tim Hill, EoN Taher Najah, OPEC Klass Van Alphen, GCCSI Eddy Chui, Canada Richard Rhuddy, EPRI Daan Jansen, Netherlands Kevin McCauley, B&W John Gale of IEAGHG agreed to provide secretarial support. A contractor, GSW Strategy Group, LLC of the USA were hired to help facilitate the exercise. A work plan was agreed which comprised:

1. An initial SWOT activity, information was collated by the consultant from all the group members by telephone interview.

2. The SWOT information and scenario planning exercise was completed at a meeting hosted by Chevron in San Ramon, California. This was a two day meeting, in which 7 members participated directly and two by phone. The information generated by this meeting was then summarized and supplemented as required and circulated to participants for further reflection/comment.

3. A draft report was generated by the consultant and sent to members ahead of the second meeting of the group held for one day just before the 41st ExCo meeting in Bergen. The results of this final meeting will be summarized and presented to members at the ExCo meeting.

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FEEDBACK IEA ACTIVITIES

NOTES

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CCS IN CDM FEEDBACK, WORK AHEAD

Background The mandate for activity on CCS was set by the Cancun Decision, which put in place a work programme for 2011 in terms of addressing the issues on concern within new Modalities and Procedures (ie rules) for the Clean Development Mechanism (CDM). This work programme consisted of submissions, then a technical and legal workshop of experts in Abu Dhabi in September, then the UNFCCC Secretariat produced draft modalities and procedures drawing upon these inputs. These were issued just two weeks before COP-17 at Durban, and in their 20 pages of detail provided the basis for negotiations in Durban. CCS Modalities and Procedures After over 32 hours of intense negotiations in Durban, on Friday 9 th December Parties (countries) agreed and adopted the Modalities and Procedures to allow CCS in CDM. These Modalities and Procedures include provisions for participation requirements (including national regulations), site selection and characterisation, risk and safety assessment, monitoring, liabilities, financial provision, environmental and social impact assessments, responsibilities for long term non-permanence, and timing of the CDM-project end. They draw from existing examples of CCS regulation, and will both ensure a high level of environmental protection and are workable for projects. A key concept is the ‘net reversal of storage’, where there are seepage emissions after project closure, or at a greater rate than injection. A key issue was the responsibility for net reversal of emissions in the long term (ie non-permanence). The solution agreed was to allow host countries to choose either to accept this obligation to replace the Certified Emission Reductions (CERs) for the leakage amount, or to transfer this obligation to the buyers of the CERs. In this case, a new type of CERs would be created, ones with responsibility. The issue of transboundary activities and a global CER reserve will be deferred to CMP 8. Thus a historic day for CCS, following six years of hard work but with little progress. The draft Decision and the Modalities and Procedures as adopted can be found at http://unfccc.int/2860.php . This is important official recognition by the UNFCCC of the role of CCS in mitigating global climate change in developing countries and sets an important precedent for the inclusion of CCS into other financing and technology support mechanisms. The Modalities and Procedures also establish the benchmark for managing CCS projects in developing countries. Climate Negotiations In terms of the bigger picture, Ministerial level negotiations continued intensely, both informally and formally, into the early hours of Sunday 11th, concluding at 6:22am. After several heart-stopping moments, significant agreements were achieved. These are for a process to a binding agreement that includes all countries (developed and developing) taking on emissions targets, to be agreed by 2015 and implemented from 2020 (known as the Durban Platform for Enhanced Action). Importantly also agreed, to avoid a gap, was that a second commitment period for the Kyoto Protocol will be agreed by the end of 2012 which will continue ‘project-based mechanisms’ such as the CDM. Also, further details on the Green Climate Fund and the Technology Mechanism were agreed, which will help developing countries for both mitigation and adaptation activities. Details of all are available on http://unfccc.int/2860.php

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IEAGHG’s role Since 2005 whether CCS should be eligible in the Kyoto Protocol’s Clean Development Mechanism (CDM) has been debated and negotiated without much progress. The main issues of concern have included: market effects, discrepancy between benefit and liability time periods, non-permanence; monitoring and verification; environmental impacts on ecosystems and climate (including a concept of “massive catastrophic release”), project boundaries and transboundary issues, liability, perverse outcomes, safety, and insurance and compensation for leakage. Over these years, IEAGHG has contributed information to this process. At the first UNFCCC workshop in 2006, in IEAGHG workshops, with studies and reports addressing CDM-specific issues of concern such as: • ‘Use of the CDM for CCS’ (IEAGHG PH4/36, Dec 2004), • ‘ERM - CCS in the CDM’ (IEAGHG 2007/TR2 Apr 2007), • ‘CCS in the CDM: Assessing Market Effects of Inclusion’ (TS 2008/13, Nov 2008) IEAGHG also contributed to the ‘Expert’s Report’ formally titled ‘Implications of the Inclusion of Geological Carbon Dioxide Capture and Storage as CDM Project Activities’ (UNFCCC EB50 2009), and in numerous presentations at side-events at the UNFCCC SBSTA and CMP meetings. Progress was then made at CMP6/COP16 (2010) in Cancun when it was agreed that CCS could be eligible for the CDM providing the range of issues of concern could be addressed in the modalities and procedures (ie the rules) for the CDM. A work programme was put in place consisting of submissions, a technical and legal workshop in Abu Dhabi in September 2011, and the production of draft modalities and procedures by the UNFCCC for negotiation at CMP7/COP17. IEAGHG then used the leading international technical expertise within three of its international research network meetings in 2011 (Modelling Network, Monitoring Network, and Risk Assessment Network) to address and discuss the relevant ‘Cancun Decision issues’ IEAGHG then ensured that the respective Networks’ outcomes and conclusions on these and other issues were shared in the UNFCCC workshop in Abu Dhabi. This workshop brought CCS negotiators into contact with some 28 experts, including IEAGHG and several who are members of the IEAGHG Networks. Presentations and discussions included on monitoring, modelling, risk assessment, environmental impacts and groundwater protection, and transboundary issues. This was in an environment very conducive to good and open discussion among negotiators and experts on all the issues of concern. The impact of this workshop was significant, in that technical concerns appeared to reduce, and negotiators appeared to have more confidence in the science and the technologies. This workshop, along with the submissions, provide the UNFCCC with the material for them to draft the 20 pages of detail for the CCS-specific modalities and procedures. These formed the basis for negotiations in Durban. With input from IEAGHG. elements from this workshop were also repeated in a CCSA side event in Durban, the only ‘official’ side-event on CCS. IEAGHG also worked with GCCSI, CCSA and IEA in Durban, participating in their activities and disseminating relevant IEAGHG publications on their booths. Tim Dixon was supported by GCCSI to be seconded into UK DECC, and thereby into the CCS team in the EU delegation as Lead Negotiator for the EU. This placed the technical evidence-based provided by IEAGHG right at the heart of the negotiations.

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As a general observation, the level of informed negotiation on the technical issues was much enhanced at Durban, and valid concerns were able to be addressed appropriately in the modalities and procedures whilst still progressing negotiations. The end result from CMP7/COP17 was that it was agreed that CCS can be included in the CDM, with a set of CCS-specific modalities and procedures to ensure environmental integrity whilst also being workable by projects. This is official recognition by the UNFCCC that CCS is a technology for use in developing countries, and sets an important precedent for the inclusion of CCS into other financial and support mechanisms. This is particularly relevant given the other achievements at Durban on future climate agreements and mechanisms. More information is available on the Durban outcomes at http://unfccc.int/2860.php , and on the Abu Dhabi workshop at http://unfccc.int/methods_and_science/other_methodological_issues/items/6144.php . We believe that science and technology better informing negotiations during 2011 greatly assisted in achieving inclusion of CCS in the CDM, and IEAGHG was pleased to play a role in this. IEAGHG was also pleased to work with GCCSI, CCSA, UK DECC, IEA and others in this process. Bonn Workshop on Sustainable Development Mechanisms On the 24-25 March 2012 the UNFCCC held a workshop on future CDM and JI work, in Bonn, called the 1st Sustainable Development Mechanisms workshop. This has a CCS session on future work in CDM.The speakers were UNFCCC on the Durban outcomes and future work, DNV on general CCS project procedures, Brazil on the CCS Modalities and Procedures (M&Ps) in detail and areas of challenge, and IEAGHG’s Tim Dixon was invited to speak by UNFCCC on implementation of the M&Ps. Tim highlighted the CDM documents which need revising, and the role of project precedents and best practice guidelines and IEAGHG reports. There was good discussion, and all presentations including the conclusions will be available in due course on https://cdm.unfccc.int/stakeholder/index.html . A general conclusion was the CDM Excecutive Board should create a CCS Working Group of experts to assist it with decisions. There will be work needed by UNFCCC on revising the many CDM documents, including standards and guidelines, and this work should be monitored for IEAGHG members. Next steps As well as the revision of the CDM hierarchy of documents, work will be undertaken on the two issues which were ‘parked’ in Durban. These were how to deal with CCS projects with a transboundary component, and the idea of a global reserve of CERs to compensate for any future seepage. Submissions on these have been provided by Parties and Observers to the UNFCCC, and these issues will be negotiated on in SBSTA-36 in Bonn in May. IEAGHG (Tim Dixon) plans to attend as part of the UK DECC delegation and EU CCS team. SBSTA-36 is mandated to provide information for a Decision on these issues to COP-18 in Qatar in December 2012.

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http://unfccc.int/methods_and_science/other_methodological_issues/items/6144.php

https://mailgate.ieaghg.org/owa/redir.aspx?C=fe7711a76cde4032bc958011befe5536&URL=https%3a%2f%2fcdm.unfccc.int%2fstakeholder%2findex.html

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UK FEED STUDY ANALYSIS

AS part the UK CCS Demonstration Competition two FEED studies were carried out to advance the technical, commercial and regulatory understanding regarding design and implementation of CCS at Scottish Power’s Longannet Power Plant and E.ON’s Kingsnorth Power Plant. The outcome of the FEED studies plays an important role for the commercial viability of CCS demonstration projects and their early development. These studies also provide information on the basic design of large-scale CCS systems to potential developers and the wider CCS community. Therefore, IEAGHG has conducted a review on these interesting FEED studies in order to provide the ExCo members with the concise and evaluated information. E.ON and Scottish Power FEED reports cover the sections related to Power Plant, CO2-Capture Unit, Transportation, Storage, Economics, Regulation, HSE and Risk Management. The corresponding information is presented in a variety of document types like PFD’s, heat and mass balances, P&ID’s and tables. E.ON and Scottish Power FEED studies consist of 206 and 123 documents respectively. In this FEED review relevant information is compiled from the existing FEED reports to give a short and clear summary of the key data and issues. One of the important aspects of this review lies in identifying the limitations, gaps, and lessons learnt from these FEED studies. The review starts with a high level definition of both FEED studies which gives a first insight into these two projects. Chapters focusing on power plant, CO2 capture unit and transportation provide all technical data in the form of simplified block diagrams and related heat and mass balances. Storage, economics and regulatory chapters are also developed in similar way. There is an intention from IEAGHG to evaluate other full-scale CCS demo FEED studies in the future based on this review process.

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WORKSHOPS ON COSTS OF CCS

As reported at the 40th meeting, a two day interactive workshop on costs of CCS, covering the entire chain of capture, transport and storage, was held in Paris in March 2011. The workshop was attended by 38 invited experts who are working on CCS cost estimation. It was organised by a steering committee consisting of Howard Herzog (MIT), John Davison (IEAGHG), Richard Rhudy (EPRI), Matthias Finkenrath (IEA), Clas Ekström (Vattenfall), Chris Short (GCCSI) and Ed Rubin (Carnegie Mellon University). The main actions arising from the workshop were:

o GCCSI should produce a report summarising the workshop and including the presentation slides. This was completed after the 40th ExCo meeting and it has been posted on IEAGHG’s website and the websites of some other members of the workshop’s steering committee.

o The steering committee should organise a further workshop to discuss CCS costs. A

two day workshop will be held at EPRI in Palo Alto, USA on 25th-26th April 2012. To keep the number of participants about the same as at the first workshop, to ensure active discussion, this workshop will also be by invitation only. The invitees are the people who attended the first workshop together with some additional people, in particular with experience of costing of demonstration plants and costs of CCS in developing countries. The main themes for discussion at the workshop are:

o CCS costing methods and measures o Understanding the costs of demonstration projects o Evaluating economics of emerging processes o Costs of transport, storage and utilisation, with particular emphasis on EOR o CCS costs in China

o A sub-group of 7 people working on CCS cost estimation, headed by Ed Rubin and

including John Davison, Chris Short, Clas Ekström, Sean McCoy, George Booras (EPRI) and Michael Matuszewski (DOE-NETL) should work on harmonisation of methodologies for assessment of costs of CCS. This group is currently writing a ‘White Paper’ entitled “Towards a Common Method of Cost Estimation for CO2 Capture and Storage at Fossil Fuel Power Plants”.

o Compile a bibliography of CCS costing studies and papers, which will be made

available on a website hosted by GCCSI. This activity is being led by Howard Herzog.

Conclusions of the workshop to be held in April will be presented at the meeting.

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MICROBIAL EFFECTS ON CO2 GEOLOGICAL STORAGE

Background At the 40th ExCo meeting IEAGHG included in the voting round a proposal for a study on microbial effects on CO2 storage. The study was not accepted by members for voting therefore IEAGHG decided to undertake an initial review to inform members what the issues are and then discuss with members if further work should be considered and a study proposal resubmitted at a later date. The review undertaken By Ludmilla Bassava-Reddi is attached for member’s reference and the key findings from this work will be presented to members at the 41st ExCo meeting.

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Microbial Effects on CO2 Geological Storage

1. Introduction

Microorganisms are thought to be responsible for over half the biomass on planet earth with a substantial fraction of this in the subsurface. Microorganisms can exist in extreme environments from the ice sheets of Antarctica to submarine hydrothermal vents. Microbial activity in the subsurface may exist as deep as 3.5km, assuming a 110°C temperature limit for microbial activity and a geothermal gradient of 25°C/ km (Krumholz, 1998) and microbial communities have been found as deep as 3.2 km in goldmines in South Africa (Takai et al, 2001). They are therefore likely to exist in formations considered for geological storage of CO2. Additionally, microbes are likely to be introduced into these geological formations during the construction and operation of a storage site, mainly through drilling fluids.

In general the chemoautotrophic nature of subsurface ecosystems increases with depth, i.e. microbes in the deeper subsurface are more likely to be using CO2 to synthesize necessary organic compounds. Therefore these are what you may expect to find at the depth of a typical CO2 storage site. Deep subsurface microbial communities are dominated by four anaerobic, physiological types, methanogens, sulphate or sulphur reducing bacteria, fermentative anaerobes and Fe(III) reducing bacteria (Onstott, 2005).

Microbial activity in deep subsurface environments is controlled by nutrient and energy source availability and their activity in subsurface environments is generally slow due to limited availability and supply rates of energy sources. Their activity will cause both direct effects (mineral formation/degradation, porosity change through biofilm formation, corrosion) and indirect effects (changes in pH, redox). Biofilms are complex aggregations of microorganisms growing on a solid substrate and are characterized by structural heterogeneity, genetic diversity, complex community interactions, and an extracellular matrix of polymeric substances.

Introduction of injected CO2 and associated impurities into a geological environment, either dissolved in groundwater or in the gaseous phase, will stimulate these effects as they can be utilised by microbes in energy generating redox reactions or as a nutrient source. Many microbes may not survive the initial stages due to the presence of supercritical CO2, which is likely to be lethal; however once injection has stopped, microbes that use CO2 as an energy source are likely to propagate more rapidly and may end up in greater quantities than before injection.

If, as a result of CO2 injection the level of microbial activity is increased or decreased, this can affect the porosity and permeability and hence the storage capacity and injectivity of the formation. Geochemical parameters are affected and a variety of geochemical reactions may occur, affecting migration of potentially hazardous elements. These effects will likely be site specific.

2. Effect of CO2 on Microbial Activity

Injection of supercritical CO2 (SC-CO2) into the subsurface has been found to have a lethal effect on the majority of microorganisms. SC-CO2 is particularly damaging to cells because of its low viscosity and low surface tension and can therefore quickly penetrate cellular material. This is enhanced at higher temperatures, which will increase the fluidity of cell membranes, and higher pressures, which increases CO2 solubility in water and therefore penetration through cell walls. Experiments on the comparison of CO2 stress response on three model organisms, showed that biofilm formation and cell

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wall thickness may be two very important factors in resisting CO2 toxicity as they create a reactive barrier that slows the diffusion of CO2 into cytoplasmic membranes (Santillan et al, 2011).

As the CO2 plume moves through the storage formation, microbial communities may preside in residual brine left behind in cracks, dead flow zones and upstream of the front; this brine will have a gradient of dissolved CO2 in which microbial interaction may behave differently. Experiments looking at formation waters from the Arbuckle formation (Gulliver and Gregory, 2011) show different families of bacteria preside when varying the CO2 partial pressure. Knowledge of surviving and thriving microbial populations may enable improved models for predicting the fate of CO2 following injection and lead to better strategies for ensuring the security of CO2 in the subsurface. Other experiments (Peet et al, 2010) identified a strain of bacteria resistant to SC-CO2 and tolerant of conditions expected at geological storage sites. The bacteria was termed MIT0214, is similar to the Bacillus strain of bacteria and was taken from formation waters of the Frio storage site test site. The findings of the study suggest adaptation to a supercritical CO2 environment may simply reflect thermodynamic adaptations to growth under high pressure and differential regulation of genomic content. Colwell et al (2011) also show that native microorganisms at the proposed injection site into the Wallula Basalts, Columbia River are able to survive in water incubated with SC-CO2. Planned future work will compare communities at different depths, accurately determine microbial concentrations in samples and characterise microbial diversity using pyrosequencing.

Monitoring studies in Ketzin (Morozova et al, 2010) show that initial CO2 injection initially causes a decrease in total microbial activity, which after injection starts to increase again. However, the diversity of microorganisms are reduced. The study revealed temporal out competition of sulphate-reducing bacteria by methanogenic archaea (methane producing microorganisms). In addition, enhanced activity of the microbial population after five months of CO2 storage indicate that the bacterial community was able to adapt to the extreme conditions of the deep biosphere and to the extreme changes of these atypical conditions.

Onstott (2005) carried out a modelling exercise considering the main redox reactions associated with microbial activity and relevant to H, C, N, O and S. The free energy in an aquifer prior to CO2 injection was calculated during injection and post injection looking at different groundwater types. The results show that the most significant impact of CO2 injection is the reduction of pH.

The pH affects which reactions are more likely to take place, which may affect the energy available for microbial activity as lithotrophic microorganisms utilise the energy of redox reactions for their life processes.

For the ground water hosted in the siliciclastic reservoir, the pH is reduced by one unit. Which makes microbial Fe(III) reduction reactions more significant. If sufficient electron donors are available for both biotic and abiotic Fe(III) reducing reactions and sufficient Fe(III) bearing oxides are present in the aquifer then these reactions will restore the aquifer’s pH to its initial, pre-injection value. CO2 injection should cause a short term stimulation of Fe(III) reducing communities.

Dolomitic or carbonate aquifers may be more severely impacted by CO2 injection; the modelling study showed that the dissolution of carbonate failed to restore the pH to a range that is conducive to metabolism of some microorganisms.

Another factor associated with lower pH caused by CO2 injection is that it facilitates proton pumping reactions across the cell membrane. Microorganisms need to maintain an internal pH that is 1–2 units less than the external pH in order for the proton pumps to generate ATP (enzyme produced during the

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metabolic process). For pH values approaching 8.5–9, the high internal pH values affect the aqueous species of phosphate making it more difficult to synthesis ATP. The microorganism is then required to expend energy in ion transport across the membrane to correct for this problem. A more neutral pH of 6–7 alleviates this energy drain. The greater availability of energy will also facilitate the fixation of N2 which would help support growth of the microbial population. The lower pH values should also help solubilise phosphate for growth. Overall CO2 injection should increase the availability of N and P to microbial communities.

These findings are confirmed and added to in later research (Onstott, 2011), which states that many microbial redox reactions are favourably improved with greater CO2 pressure. If there are sufficient electron donors and and Fe(III)/ sulphate electron acceptors CO2 injection should lead to short term stimulation of anaerobic activity. For long term storage in siliciclastic reservoirs this should lead to carbonate precipitation. Injection into carbonate/ dolomite, may produce a greater impact on subsurface microbial ecosystems with dissolution on carbonate depending on pH range of indigenous microorganisms.

It is important to understand which reactions in the storage reservoir are likely to enhance microbial activity. This can be analysed with an evaluation tool using a microbial energetics approach (West et al, 2011). As lithotrophic microorganisms utilise the energy of redox reactions for their life processes, it is necessary to consider what reactions may be coupled with the reduction of CO2. The energy difference will show whether a particular reaction will provide enough energy to be utilised by the microbes. This is demonstrated for sulphur oxidation in figure 1, which shows that some intermediate sulphur oxidation above approximately pH 4, when coupled with CO2 reduction, could potentially provide enough energy for microbial usage.

Figure 1: Diagrammatic illustration variety of free energy of some potential intermediate S oxidation half reactions coupled to CO2 reduction half reaction as a function of pH. CO2 reduction (solid line) refers to the left hand scale while oxidations (dashed lines) refer to the right hand scale. From West et al, 2011

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If a reservoir is geochemically characterised before CO2 injection it can be determined beforehand if there are any potential reactions that could cause an increase in microbial activity. Modelling studies as those described above can be used to predict what is likely to occur

3. Effect of Microbial Activity on CO2 Storage

The reactions between microorganisms and the minerals of the reservoir and caprock may cause changes in the structure and chemical composition and corrosion of the casing and cement around the well. Biofilms have been known to cause corrosive effects on materials used in oil and gas drilling operations and is a fairly common occurrence, known as biofouling. The usual solution in most cases is the addition of chemicals into the wellbore to reduce the buildup.

Buildup of biofilm in the aquifer itself can cause pore blocking, which could potentially affect injectivity of CO2 into the reservoir. However, there is not expected to be much microbial activity in the area around the wellbore in the initial stages of injection as most microorganisms will be negatively affected by SC-CO2. Following the initial stages, microbial activity may continue to increase and this is especially likely after injection has ended.

Experiments show the ability of microbial biofilms to decrease permeability of natural and artificial porous media, survive exposure to scCO2 and facilitate conversion of CO2 into long-term stable carbonate phases as well as increase solubility of CO2 in brines (Gerlach et al, 2010). Reactive transport models describing the influence of biological processes on CO2 storage security have been developed and are continuously being modified to include relevant processes. Kirk et al (2010) show the effect of pH on hydraulic conductivity (K) of biologically clogged media. A reduction in pH showed an increase in K, but that clogging persisted. The results suggest that biomass in porous medium will remain largely in place following exposure to acidic water in a CO2 storage reservoir, particularly where buffering is able to limit to extent of acidification.

There have been studies considering the potential positive effects of microbial activity on storage security. Mitchell et al (2010) consider the potential of microorganisms for enhancing mineral and solubility trapping by utilising the bacterial hydrolysis of urea (ureolysis). This has the effect of increasing the pH, which causes increased solubility of CO2. Any carbon from the urea undergoes mineralisation to CaCO3, which in turn may increase storage security by creating an impermeable barrier. It is also suggested that waste water containing urea could be utilised, which will also reduce the amount of labile surface carbon. Figure 2 shows a schematic representation what such microbially enhanced storage would look like.

Numerical models are also being developed that can simulate the development of a biofilm, barrier near the injection well (Ebigbo et al, 2010). This will account for the transport of bacteria, biofilm accumulation as well as the role of increased ureolysis, which leads to the precipitation of carbonate minerals. Influence of precipitates and biofilm of the two fluid phases (water and CO2) are accounted for and the model may be a useful tool for optimisation of strategies for the proposed technology involving the use of such microbially induced barriers to increase storage security near wellbores.

Cappacio et al (2010) show that even metabolically inactive microorganisms can have a positive effect on mineral trapping. Experiments using mutated bacteria showed that crystalline surface layer proteins can selectively attract Ca2+ ions, serving as nucleation sites for CaCO3, thereby accelerating crystal formation.

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Model systems have been developed (Freedman et al, 2010) to look at the effects of SC-CO2 on the SC-CO2 tolerant strain of bacteria (MIT0214), discovered in the experiment mentioned in the previous section, with the intent to understand how to optimise mineral trapping techniques. At Otway, after initial identification of a CO2 resistance strain of microorganism, further study is underway with the possible aim of engineering biofilms to enhance trapping of CO2 in saline aquifers (Mu et al, 2011).

Mitchell et al (2009) considered the use of biofilms as a mitigation method for the leakage of CO2 out of the storage reservoir. Experiments were carried out to investigate the growth of biofilm under high pressure and salinity conditions and its utility for reducing sandstone permeability, and how flowing SC-CO2 and biofilm starvation affect viability and permeability of the biofilm barrier, and its structural resilience to mechanical stress.

The results show that permeability of the sandstone decreased in both high salinity and high pressure conditions. The effect of starvation of the microorganisms showed negligible changes in permeability. The effect of SC-CO2 showed an increase in permeability, but by less than 5% after 71 hrs. This suggests that subsurface biofilm barriers do not require continued nutrient feeds in order to sustain the long-term integrity of the barrier. However, continued feeding of starved biofilms may promote further biofilm growth and permeability reduction.

It has also been suggested that stimulating methanogenic bacteria in coal samples can enhance the production of methane (Jones et al 2010). Tang et al (2012) carried out a study analysing the indigenous microorganisms in coalbeds to see if this is feasible. The study, while focused on the Ordos basin, China compared with other sites worldwide. The bacterial community was more diverse than those in coals reported so far and the existence of an intact methanogenic microbial community was revealed in low-ranking coal. In contrast, the bacterial diversity decreased remarkably in the presence of sulfate reducing bacteria with no methanogens detected in coal with high coalification levels. An analysis of the microbial community showed it to be very site specific and more diverse in some areas and less so in others.

Figure 2: Schematic representation of microbially enhanced storage (Mitchell et al, 2010)

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4. Monitoring of Microbial Activity

Monitoring of CO2 storage has tended not to focus highly on microorganisms, though there have been several studies related to various sites. At Ketzin, however a particular effort was made to conduct an analysis on the subsurface microbial community from pre-injection to post injection.

One of the major challenges was to account for any microbial activity that would have been introduced externally through the drilling fluids. A tracer-based method for determining the infiltration of drilling mud and technical fluids into rock cores and fluid samples was applied (Wandrey et al, 2010), using a fluorescent dye, Na-fluorescein to be added to the drilling fluids. It was found that outer core regions of mildly permeable sandstone sections were significantly infiltrated with drilling mud, though the tracer concentration in the inner core was below the visual detection limit. To make sure that inner core samples are not affected by drilling mud in the future, the fluorescein concentration of any samples will need to be quantified.

Microbial monitoring was then able to take place using fluorescence in situ hybridisation (FISH), (Morozova et al, 2010). This is one of the most used nucleic acid techniques to study microorganisms in their natural environments. FISH coupled with rRNA-targeted oligonucleotide probes allows direct visualisation, identification and localisation of bacterial cells from selected phylogenetic groups in environmental samples. This showed the microbial community to be strongly influenced by CO2 injection. Before CO2 arrival, up to 6 x 106 cells/ ml were detected by DAPI staining (epifluorescent microscopy) at a depth of 647 m below the surface. The microbial community was dominated by the domain Bacteria that represented approximately 60% to 90% of the total cell number, with Proteobacteria and Firmicutes as the most abundant phyla comprising up to 47% and 45% of the entire population, respectively. Both the total cell counts as well as the counts of the specific physiological groups revealed quantitative and qualitative changes after CO2 arrival. The study revealed out competition of sulphate-reducing bacteria by methanogenic archaea. In addition, an enhanced activity of the microbial population after five months of CO2 storage indicated that the bacterial community was able to adapt to the extreme conditions of the deep biosphere and to the extreme changes of these atypical conditions.

All current methods of microbial monitoring and observation are from samples taken from observation wells. In Otway a U-tube was used which isolated formation water from sources of contamination, while maintaining the formation pressure (Mu et al, 2011). From this, DAPI staining highlighted abundance of filamentous cells ranging from 5 to 45µm. The microorganisms found to be resistance to CO2 are currently being investigated.

5. Conclusions

There has been much work carried out on microbial activity in the subsurface, though there is limited information regarding the effect on CO2 storage. There are however, several research projects and studies underway looking into this topic.

CO2 can have a large effect on microbial activity, with the majority of microorganisms having a fatal reaction to supercritical CO2. Microorganisms likely to thrive in a CO2 environment are those with thicker cell walls and those that are able to produce a biofilm. Microorganisms that can survive CO2 injection are being identified and studied through laboratory experimentation and observation at current CO2 storage sites. Models are also being developed that will be able to take account of reactions and changes caused by microbial activity.

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Microbial activity can potentially have negative effects, such as bio-corrosion in the wellbore and potential pore blocking, which may affect injectivity, though there was not much information found relating to this area specifically.

There has been and is current research on the potential utilisation of microorganisms to enhance storage security by enhanced mineral and solubility trapping, such as through microbially enhanced ureolysis or just by their presence of crystalline surface layers that can act as nucleation sites. Biofilms can also act as a hydraulic barrier to prevent flow of the CO2 plume, which may be particularly useful as a mitigation method. Laboratory experiments show high resistance of biofilms to starvation of the microorganisms as well as supercritical CO2, making it a potentially viable solution.

6. Recommendations

This topic is becoming increasingly significant as more demonstration projects start to take place. Microbial activity may need to be part of any site characterisation and the effects may need to be taken into account in the risk assessment phase. Knowledge regarding bioengineering is also increasing.

It is therefore recommended that IEAGHG should consider commissioning a full study documenting the effects of and on microbial activity on geological storage of CO¬2 when it feels there is a sufficient body of knowledge to do this.

References

Cappuccio, J. A., Pillar, V. D., Lui, G. V., Ajo-Franklin, C.; 2011; Microbial Surfaces and their Effects on Carbonate Mineralization; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Colwell, F. S., Lavalleur, H., Verba, C., O’Connor, W., Fisk, M. R.; 2011; Microbiological Characterization of a Basaltic System Targeted for Geological Sequestration of Carbon; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Ebigbo, A., Helmig, R., Gerlach, R., Cunningham, A. B., Phillips, A.; 2011; Modelling Microbially Induced Carbonate Precipitation and its influence on CO2 and water flow in the subsurface; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Freedman, A. J. E., Peet, K. C., Franklin, J. B. A., Ajo-Franklin, C., Cappuccio, J., Thompson, J. R.; 2011; Characterisation of Microbe-Mineral Interaction under Supercritical CO2: Possible Roles for Bacteria during Geologic Carbon Sequestration; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Gerlach, R., Mitchell, A. C., Ebigbo, A., Phillips, A., Cunningham, A. B.; 2011; Potential of Microbes to Increase Geologic CO2 Storage Security; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Gulliver, D., Gregory, K.; 2011; CO2 Gradient Affects on Deep Subsurface Microbial Ecology during Carbon Sequestration; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

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Kirk, M. F., Santillan, E., McGrath, L. K., Altman, S. J.; 2011; Variation in Hydraulic Conductivity with Decreasing pH in a Biologically-Clogged Porous Medium; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Jones, E.J.P., Voytek, M.A., Corum, M.D., Orem, W.H.; 2010; Stimulation of methane generation from nonproductive coal by addition of nutrients or a microbial consortium; Applied and Environmental Microbiology 76, 7013–7022.

Krumholz, L.; 1998; Microbial Ecosystems in the Earth’s Subsurface; ASM News Vol. 64, No. 4

Mitchell, A. C., Phillips, A. J., Hiebert, R., Gerlach, R., Spangler, L. H., Cunningham, A. B.; 2009; International Journal of Greenhouse Gas Control 3: 90-99

Mitchell AC, Dideriksen K, Spangler LH, Cunningham AB, Gerlach R.; 2010; Microbially enhanced carbon capture and storage by mineral-trapping and solubility-trapping; Environ Sci Technol. 2010 Jul 1;44(13):5270-6

Morozova, D., Wandrey, M., Alawi, M., Zimmer, M., Vieth, A., Zettlitzer, M., Würdermann, H.; 2010; Monitoring of the Microbial Community Composition in Salin Aquifers by Fluorescence in situ hybridisation; International Journal of Greenhouse Gas Control 4: 981-989

Mu, A., Billman-Jacobe, H., Boreham, C., Schacht, U., Moreau, J. W.; 2011; How do Deep Saline Aquifer Microbial Communities Respond to Supercritical CO2 Injection?; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Onstott, T. C.; 2005; Impact of CO2 Injections on Deep Subsurface Microbial Ecosystems and Potential Ramifications for the Surface Biosphere; Chapter 31 Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO2 Capture Project, Geological Storage of Carbon Dioxide with Monitoring and Verification, Vol. 2

Onstott, T. C., Colwell, F. S., Kieft, T. L., Murdoch, L., Phelps, T. J.; 2009; New Horizons for Deep Subsurface Microbiology; Microbe Magazine, American Society for Microbiology, Nov. 09

Onstott, T. C.; 2011; Thermodynamic Considerations of CO2 Injections Deep Subsurface Microbial Ecosystems; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Peet, K. C., Freedman, A. J. E., Hernandez, H., Thompson, F. R., 2011; Genomic Insights into Growth and Survival of Supercritical CO2 tolerant bacterium MIT0214 under Conditions Associated with Geologic Carbon Dioxide Sequestration; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Santillan, E. F. U., Franks, M. A., Omelon, C. R., Bennett, P.; 2011; Microbes under Pressure: A Comparison of CO2 stress Responses on Three Model Organisms and their Implications for Geologic Carbon Sequestration; Abstract from AGU Fall meeting 2011 session: Microbiology of Geologic Carbon Sequestration Posters

Takai, K., Moser, D., DeFlaun, M., Onstott, T. C., Fredrickson, J. K.; 2001; Archaeal Diversity in Waters from Deep South African Gold Mines; Applied and Environmental Biology, Dec. 2001 p. 5750-5760

Tang, Y. Q., Ji, P., Lai, G. L., Chi, C. Q., Liu, Z. S., Wu, X. L., 2012; Diverse Microbial Community from the Coalbeds of the Ordos Basin, China; International Journal of Coal Geology 90-91 (2012) 21-33

Wandrey, M., Morozova, D., Zettlitzer, Würdermann, H.; 2010; Assessing Drilling Mud and Technical Fluid Contamination in Rock Core and Brine Samples intended for Microbiological Monitoring at the CO2 Storage

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http://www.ncbi.nlm.nih.gov/pubmed?term=%22Mitchell%20AC%22%5BAuthor%5D

http://www.ncbi.nlm.nih.gov/pubmed?term=%22Dideriksen%20K%22%5BAuthor%5D

http://www.ncbi.nlm.nih.gov/pubmed?term=%22Spangler%20LH%22%5BAuthor%5D

http://www.ncbi.nlm.nih.gov/pubmed?term=%22Cunningham%20AB%22%5BAuthor%5D

http://www.ncbi.nlm.nih.gov/pubmed?term=%22Gerlach%20R%22%5BAuthor%5D

http://www.ncbi.nlm.nih.gov/pubmed/20540571

GHG 12/16

Site in Ketzin using Fluorescent Dye Tracers; International Journal of Greenhouse Gas Control 4 (2010) 972-980

West, J. M., McKinley, I. G., Palumbo-Roe, B., Rochelle, C. A.; 2011; Potential Impact of CO2 Storage on Subsurface Microbial Ecosystems and Implications for Groundwater Quality; Energy Procedia 4 (2011) 3136-3170

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Bergen, Norway, 9th – 10th May 2012

BARRIERS TO IMPLEMENTATION OF CCS:

CAPACITY CONSTRAINTS Draft Overview

Background to the Study

As part of its on-going work programme, the IEA Greenhouse Gas R&D Programme (IEAGHG) has undertaken a number of studies to assess potential barriers to the implementation of CCS. In the latest study in this series looking at potential barriers the IEAGHG looks to explore whether there are supply and capacity constraints associated with equipment and services for CCS plants that might cause issues with CCS implementation. A related earlier study by the IEA clean Coal Centre for new build coal fired power plant identified that there are potential areas of supply constraints in key components like castings for gas turbines and basic raw materials like steel and cement for plant construction. This study aims to build upon this earlier work by looking at the CCS components for new build plant to see if there are any additional critical component issues.

The IEA Technology Roadmap for CCS provided the reference framework for the study because it proposes an aggressive deployment strategy for CCS up to 2050. This roadmap envisaged that 100 CCS projects need to be deployed by 2020 and suggested that by 2050 alone, up to 150Gt of CO2 will need to have been captured and stored if CCS is to make the required contribution towards achieving temperate rise at 20C by 2050. To achieve such targets CCS will be ramping up production rapidly and issues may arise regarding materials/equipment and services supply that need to be identified early to ensure that these issues do not represent barriers to the implementation of CCS.

A contract for this study was awarded to Ecofys, B.V. of the Netherlands.

Scope and Approach Taken

The study considered the full CCS chain, i.e. capture, compression, transport and storage of CO2. The focus was on current state-of-the-art technologies, including pre-combustion, post-combustion and oxyfuel combustion technologies. Second generation capture technologies were not considered in the study. The sectors considered were: industry, power generation and upstream oil and gas. The upstream sector includes fuel and gas processing and is regarded as a sector with many opportunities for low-cost capture. Components needed in the actual thermal power plants equipped with CO2 capture facilities were not within the scope of this study, as this was covered by the IEACCC report. For CO2 transport the study focused on transport by pipeline. Other transport mediums such as ship, truck and train were not

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considered. CO2 storage capacity assessment was not included in the supply chain; this subject is covered in IEAGHG report no. 2011/11 Prior to undertaking the detailed analysis the contractor first considered the scale of construction implied by the IEA CCS Road Map and compared the rollout of the technology to prior developments in the power, industry and oil and gas extraction sectors. The aim of this exercise was to determine whether supply constraints will arise depending on, amongst other factors, the deployment rates considered in the IEA CCS Roadmap. Supply constraints were divided into those relating to Equipment & Materials and those relating to Services & Skills. The figure 1 overleaf outlines the considered supply chain. Figure 1 shows that the operation of power plants with CO2 capture requires human resources and raw materials (e.g. chemicals or metals). In essence, all parts of the supply chain(s) that are necessary to plan, design, construct and operate a (part of the) CCS chain require human resources and raw materials or sub-components from other industries or from the natural environment. In each part of the chain, a supply constraint may occur. This can be a scarce natural resource or limited production capacity of a component.

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Figure 1 Graphical representation of the supply chains for CCS technologies. Horizontally the CCS

chain is shown. Vertically the supply chain is shown for the three parts of the CCS chain.

It was considered impossible to assess all components in a CCS chain (i.e. to the level of bolts and screws), so the contractors limited themselves to the main components in CCS installations. In each case an equipment list was drawn up and from this the contractor selected components, using a qualitative screening assessment process, which is detailed in Chapter 3 of the main report. For human resources, the contractor considered job profiles that are needed for capture, transport or storage activities. Each individual component identified is then assessed in detail in Chapter 5 of the main report

Results and Discussion

With regard to the envisaged technology roll out suggested in the IEA CCS Road map; the following points were noted:

• The comparison with the power sector shows that historical deployment rates of power plants are comparable, or greater than, what is necessary for CCS. This indicates that a dramatic capacity increase for EPCs is not needed (although the expertise required will be different). High construction rates for nuclear power plants, wind and solar PV in the

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IEA BLUE Map scenario indicate that the total capacity of the supply chain for power technologies must increase substantially.

• In the industry sector, approximately 65% of the current emissions should be captured

by 2050. Between 2020 and 2030, the average annual growth of CCS in the industry should be 23% (in terms of MtCO2).

• In the CCS Roadmap, by 2045, more CO2 will be captured annually than the current

volume of the annual oil and gas production combined. In the IEA BLUE Map scenario, global hydrocarbon fuel demand will decrease, although demand for oil and gas in China and India will increase. However if oil and gas exploration grow then this will cause additional problems for deployment of CCS. The comparison of the amount of CO2 that has to be stored with the current production of hydrocarbon fuels is an indication that severe competition for CCS activities will come from oil and gas production activities.

An overview of the risks of supply chain constraints for the assessed equipment and services and skills, is given in Figure 2. Note: the main risk factor is given at the right of the diagram. The high risks are mainly related to storage and transport: pipelines, drilling rigs, petroleum engineers, geo-scientists and (large) compressors. For capture, supply chain risks for hydrogen gas are high. Other low to medium supply risks are for catalysts, absorption towers, ASUs, and advanced flue gas treatment.

Figure 2 Schematic overview of identified supply chain risks for the different steps in the CCS

chain, the main risk factors are given at the right.

For capture, supplier concentration is the main risk

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Some components, such as advanced flue gas treatment, solvents and hydrogen turbines are still under development. There is a risk that the ‘winning’ technology results in a high supplier concentration; this makes it attractive for EPC contractors to vertically integrate their supply chain. Vertical integration in the chain may result into large conglomerations/joint ventures across the supply and value chain. One tipping point in the chain may result in constraints across the whole chain. For example, if one company offers a capture block and the preferred supplier is not able to meet demand, then the whole capture block faces longer lead times. It reduces risk for parties involved, but may create supplier dominated market conditions and result in inflexible markets. An historical comparison with the deployment of flue-gas desulphurisation showed that technological developments and knowledge diffusion can be realised within a relatively short time if sufficient demand-pull (via regulations/obligations/standards) is in place. Differences in supply chain constraints for the various capture technologies

Based on the analysis undertaken, no firm conclusion can be drawn on which capture technology has the most significant supply chain constraints. All three capture technologies have components that may form a potential risk and may be a barrier for large scale deployment of CCS. For pre-combustion it is the gas turbine; for oxyfuel it is the flue gas treatment and boiler; and for post-combustion it is expected to be the large scale absorbers and perhaps ‘monopolized’ solvents. Based on the methodology used in this study and current data availability it is not possible to firmly conclude on what the effect of any of these supply chain bottlenecks occurring would be on the deployment and market share of the three capture technologies.

Detailed data (i.e. below the level of EPC, large technology providers) on the CCS supply chain are in many cases difficult to collect, because of three main reasons. The first is that the supply chain of the large EPC contractors entails a large number of suppliers and sub-contractors which would require a more extensive study to map these all. The second reason is that competitive reasons limit the disclosure and thus an overview of all suppliers and sub-contractors in the supply chain to the EPC contractors. The third reason is that a detailed overview of the supply chain is mostly relevant for the short term (typically <5 years). Long-term dynamics in the full supply chain are extremely difficult to assess on a detailed level. Meeting global demand for compressors and large scale CO2 pipelines will be challenging task

CO2 compressors are mature for lower pressure ranges but require R&D for the high pressure ranges often necessary for offshore CO2 transport. All CCS projects would require compressors and it therefore faces high demands. Together with competition for (natural gas) compressors needed in the oil and gas industry, this may lead to shortage in supply capacity. Pipe laying capacity faces competition with the oil and gas industry and the current market for laying very large scale pipelines is small. The scale and amount of pipelines needed for CCS may temporarily fill order books of pipeline laying companies and increase prices and lead times.

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Oil and gas extraction will compete severely with CCS activities

For storage exploration, skilled engineers are needed, who are now mainly working in the oil & gas sector. In the BLUE Map scenario, oil and natural gas demand is expected to decrease 23%, respectively 12% by 2050, so part of the capacity (equipment and staff) could be employed for CCS. Already between 2020 and 2030, CCS activities require equipment and staff, not only to construct capture installations, but also to assess and explore reservoirs and drill wells. The oil & gas sector already experiences difficulties with staffing, and because of the specific skills and experience that is needed, suitable staff can hardly be recruited from other sectors. The most critical part is the data collection on CO2 storage reservoirs: on-side measurements, modelling and monitoring will require knowledge of skilled geo-scientists. But not only upstream (e.g. oil drilling) knowledge is concentrated in the oil and gas industry, also downstream (e.g. petrochemical refining) that relates to knowledge on CO2 capturing process is partly concentrated in the oil & gas sector. When oil prices peak; a shortage of staff and equipment might cause problems, particularly for offshore drilling. This may then result in shortages and higher costs for offshore CO2 wells. Because of their knowledge, oil companies (and their contractors) are likely to become critical facilitators for CCS, in both exploration of reservoirs and in constructing capturing installations. This means that, in times of labour shortages, oil and gas companies may have to choose between CCS and oil and gas extraction activities. As the revenues from oil activities are likely (also in the BLUE Map scenario) to be higher than CO2, there is a severe risk that CCS activities will become understaffed and underequipped, i.e. the cost of equipment and staffing increase.

Expert Review Comments Expert review comments on the draft report were received from five reviewers. The comments provided were detailed and constructive, enabling the study contractors to respond accordingly in preparation of the final report. A recurring theme in the general comments was the subjective nature of some of the views expressed in the report. Whilst it was applauded that ranking of the importance of issues had introduced some objectivity and structure, arbitrary opinion without detailed analysis remained in many cases. In the absence of the discovery of clear showstoppers it is inevitable that the essence of the report is subjective opinion. The point was made that the title “Capacity Constraints” could lead to confusion with CO2 storage volumetric capacity, which was outside of the scope of the study.

Conclusions

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The study has concluded that there are no insurmountable obstacles to the implementation of CCS at the rate of the IEA CCS roadmap were identified. However the scale of CCS implementation to match the IEA CCS roadmap would be large

• In the power sector the construction rate of power plants with CCS would be lower than historical power plant construction rates;

• In the industry sector approximately 65% of current emissions would be captured by 2050;

• In the oil and gas sector more CO2 would be captured annually than the current volume of annual global oil and gas production.

The most significant risk to rapid CCS deployment comes from competition with oil and gas exploration activities for drilling equipment.

The pre-combustion and oxy-fuel capture technologies contain elements that are not yet mature. The post combustion capture technology may become constrained by availability of materials.

Shortages of technically skilled personnel are most likely to appear, particularly for job profiles that are also required for oil and gas extraction; i.e. Petroleum engineers and geo-scientists

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Recommendations

The report formulates the following recommendations to mitigate the impacts of barriers to the implementation of CCS.

1. Reduce risks for upfront investments, particularly for reservoir exploration and CO2 transport infrastructure. For early operation of CCS installations upfront assessment and design of the transport and storage component is essential. Advance investment in CO2 storage facilities requires a level of certainty of a (long term) supply of captured CO2.

2. Mitigate competition with oil and gas extraction activities via education. Students should be encouraged to view a career in CCS technologies as complimentary to a career in the oil and gas industry, requiring the same training and skill development.

3. Investigate in detail the knowledge and expertise needed for storage assessment. A knowledge gap is identified in the area of geological CO2 storage assessment.

4. Promote international data exchange. Consistent and accurate estimates of storage capacity are needed in most world regions at an early stage of CCS deployment to prevent the storage component becoming a constraint, as well as the optimally utilise the available (human) resources.

5. Stimulate diversity of suppliers in R&D and in demonstration and pilot projects. In order to avoid later constraints of a suppliers market, diversity at the RD&D stage should be encouraged.

6. Encourage recycling and optimization of materials that are likely to be in short supply. Recognition at an early stage of the intrinsic value of critical materials should help to reduce constraints as CCS activities rapidly expand.

7. Build up institutional knowledge. Specialist knowledge will likely be pulled towards the active industries. However, technological knowledge is needed in regulatory authorities and other institutions to coordinate and design national and international CCS deployment.

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GHG/12/18


CO2 CAPTURE IN THE IRON AND STEEL INDUSTRY

This study has been undertaken by the SWEREA MEFOS Consortium. The initial results from the baseline costing work on the reference steel mill were presented to members at the 40th ExCo meeting. A draft overview will be prepared shortly and circulated to members separately for member’s comments and approval at the 41st ExCo meeting.

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OPERATING FLEXIBILITY OF POWER PLANTS WITH CCS

This study has been undertaken by Foster Wheeler Italiana. The final report, which takes account of reviewers’ comments, has been received. An attached draft overview has been prepared for member’s comments and approval at the 41st ExCo meeting.

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OPERATING FLEXIBILITY OF POWER PLANTS WITH CCS

Background to the Study Most assessments undertaken by IEAGHG and others have assumed that power plants with CCS will operate at base load. It is now becoming clear that in many cases CCS plants will need to be able to operate flexibly because of the variability of electricity demand, increased use of variable renewable energy sources such as wind and solar and poor flexibility of some other low-CO2 generation technologies such as nuclear. However, relatively little work has so far been published on this subject. IEAGHG has commissioned Foster Wheeler Italiana to carry out a study to review the operating flexibility of the current leading power generation technologies with CCS and to assess performance and costs of some techniques for improving flexibility.

Scope of Work The study assesses the flexibility, performance and costs of several examples of power plants with CCS but it is recognised that there are many other potential design options with different degrees of flexibility. The study covers the following leading technologies for power generation with CCS:

• Ultra-supercritical pulverised coal (USC-PC) with post combustion capture using solvent scrubbing

• Natural gas combined cycle (NGCC) with post combustion capture using solvent scrubbing

• Integrated coal gasification combined cycle (IGCC) with pre-combustion solvent scrubbing

• Pulverised coal oxy-combustion The study makes use of baseline plant performance and cost data from earlier IEAGHG studies, taking into account cost inflation that has occurred since those studies were undertaken. The following techniques for improving flexibility and increasing peak power output were assessed:

• Turning off CO2 capture • Storage of CO2 capture solvent • Storage of liquid oxygen and air • Storage of hydrogen • Storage of CO2 or solvent to provide a constant flow of CO2 to transport and storage

Results and Discussion Operating flexibility of power plants without CCS Typical flexibilities of power plants without CCS are summarised in Table 1. It should be noted that actual flexibilities of power plants depend on the plant design and the preferences of vendors and operators.

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Table 1 Typical operating flexibilities of power plants without CCS NGCC USC-PC IGCC Minimum load, % 40-50 30 50 Hot start-up time, hours 0.75-1 1.5-2.5 6-8 Ramp rate, % per minute

4-6 (40-85% load) 2-3 (85-100% load)

2-3 (30-50% load) 4-8 (50-90% load) 3-5 (90-100% load)

3-4

The flexibility of NGCC plants has improved substantially over the years as suppliers continue to respond to customers’ requirements for greater flexibility. Modern NGCCs are typically capable of fast start-up, shut–down and load cycling. The minimum operating load is usually determined by the increasing environmental emissions at low loads. USC-PC plants are also characterised by low minimum operating loads and good cycling capabilities and start-up times. In contrast, IGCC plants have relatively low cycling capabilities, high minimum load and long start-up times (depending on the type of gasifier) although faster start-up may be possible if an auxiliary fuel is used in the gas turbines. Operating flexibility of power plants with CCS There is currently relatively little information in the public domain on operating flexibility of CO2 capture processes and more practical research and dynamic modelling is needed. This report provides illustrative information on CCS plant flexibilities but it should be recognised that flexibilities depend to some extent on the needs of the operators and there is a trade-off between flexibility, costs and efficiency, which is explored to some extent in this report. The characteristics of electricity systems in future may be significantly different to those at present, so it is important that there is a dialogue between CCS process developers and electricity system planners, modellers and operators to ensure that CCS processes are designed to have the appropriate degree of flexibility. One of the general constraints on part load operation of CCS plants would be the CO2 compressors which would typically be limited to around 70% turndown. Higher turndown could be achieved by recycling compressed CO2 but this would impose a significant energy penalty, as the compressor would still be operating at 70% load even when the power plant was turned down further. It would therefore be advantageous to have multiple CO2 compressors, which may be required anyway due to size limitations, particularly in multiple train power plants. This report is based on power plants that include one or two power generation units. Larger plants with multiple units and common air separation and CO2 compression may provide improved part load performance. NGCC and USC-PC with post combustion capture The introduction of post combustion CO2 capture may impose additional constraints on the start-up and fast load changing of a power plant but techniques are available to overcome these constraints. In an NGCC plant the gas turbine starts up more rapidly than the heat recovery steam generator (HRSG) and the steam turbine. The regenerator in the CO2 capture plant requires steam from the HRSG or steam turbine and the regenerator needs to be heated to its operating temperature. To avoid constraints on start-up time and to avoid CO2 emissions during start up, the CO2 absorber could be operated using lean solvent from a storage tank and the CO2 rich solvent from the absorber would be stored and fed to the regenerator later. This would enable an NGCC or USC-PC plant with CO2 capture to start up and change load as quickly as a plant without capture.

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Oxy-combustion The main constraint on flexibility of a pulverised coal oxy-combustion plant is the air separation unit. The minimum operating load of the cold box is around 50% while the minimum efficient load of the main air compressor is around 70%. At lower loads, part of the compressed air would generally be recycled to the compressor feed, which imposes a substantial efficiency penalty. This could be avoided in a multi-train plant in which one or more of the compressors could be shut down. The maximum ramp rate of the ASU is typically 3% per minute but the boiler can typically ramp at 4-5%. The difference between the ASU oxygen supply rate and the boiler demand for a 50%-100% ramp is less than 10 tonnes for a 500MWe plant and this can be satisfied by using stored liquid oxygen (LOX). The LOX storage tank can be refilled during times of reduced power plant load. Around 200 tonnes of LOX storage would typically be included in the plant for the safe change-over from oxygen to air firing and in case of a ASU trip, so no additional LOX storage would be needed to satisfy the ramp rate. IGCC As mentioned earlier, the flexibility of IGCC plants without capture is relatively poor but the addition of capture is not expected to significantly affect the flexibility, except for the reduced part load efficiency of CO2 compression discussed earlier. Part load efficiencies The efficiencies of power plants with CO2 capture at part load were assessed and the results are shown in Figure 1.

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The part load efficiency reduction for NGCC and IGCC depends mainly on the performance of the gas turbine and the data in this report are based on a model of gas turbine that has a relatively high part load efficiency loss. In recognition of the increasing importance of plant flexibility some gas turbine vendors are introducing turbines that have significantly improved part load performance, as illustrated in the main report. The data points in Figure 1 for NGCC at 50% load and IGCC at 56% load are for operation with both of the gas turbines turned down. The data point for IGCC at 48% load is for operation with one of the gas turbines shut down and the other operating at 100% load, which is significantly more efficient. This operating mode could also be used for NGCCs but it was not analysed in this study. Assessment of techniques for improving flexibility Turn off CO2 capture Plant flexibility could be improved by shutting down or reducing the load of the CO2 capture and compression units and emitting raw flue gas or CO2 to the atmosphere. The ability of a plant with capture to ramp up power output could actually be better than that of a plant without capture if the load of the capture unit was reduced at the same time as the load of the power generation unit was increased. Turning off capture would increase emissions of CO2 to the atmosphere so regulations would have to permit CCS plants to emit more CO2 during times of peak power demand. This would for example require emission performance standards to be assessed over long periods such as a year. To comply with performance regulations it may be necessary to capture a higher percentage of CO2 during normal operations to compensate for the extra emissions when the capture plant is turned off. The feasibility and costs of doing this have not been assessed in this study. Turning off post combustion capture would reduce the plant’s internal consumption of electricity and the low pressure steam that would otherwise be consumed by the capture unit could be used to further increase the power output, provided the plant was built with extra low pressure turbine capacity. In plants that have been retrofitted with capture this extra steam turbine capacity would already be present and even in new power plants that have been built with capture, extra turbine capacity may have been included to enable the plant to continue to operate efficiently during outages of the CO2 capture, transport and storage equipment. Turning off capture in IGCC plants is less straight forward than in plants with post combustion capture because the CO2 capture unit is an integral part of the acid gas removal (AGR) unit which also removes sulphur compounds from the fuel gas. Two cases were assessed in the study, one with a modified AGR and one in which CO2 from the AGR is vented, after passing through a clean-up unit to reduce the H2S and CO levels to environmentally acceptable concentrations. The modified AGR plant case has the higher peak power output and efficiency and the lower cost. Turning off capture in oxy-combustion plants was not assessed in this study because the ability to do so and operate in ‘air-firing’ mode at full power output may involve more substantial design changes. The results of the analysis are summarised in Table 2. It can be seen that having the capability to turn off capture increases the capital cost of the plant (per kW of normal power output), mainly

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because of the need for greater steam turbine capacity, but the cost per kW of peak power output is lower. The net capital cost per kW of extra peak power generation capacity is relatively low, probably less than the cost of other types of peak generation capacity such as open cycle gas turbines but the specific emissions of CO2 per kWh of extra peak power generation are high, particularly for IGCC. Including the ability to turn off capture reduces the net efficiency of the plant during normal operations because the low pressure steam turbine is oversized to enable it to use the extra low pressure steam that is available when capture is turned off. The turbine therefore operates at non-optimum conditions when the capture plant is operating. To avoid this efficiency reduction a separate steam turbine could be installed to use the low pressure steam that is available when capture is turned off. This approach was adopted in the solvent storage cases described later. Table 2 Turning off CO2 capture NGCC PC IGCC Increase in power output with no capture, % 15.9 27.4 6.4 Thermal efficiency, % Reference plant with capture 50.6 34.8 31.4 Plant with capability to turn off capture 50.2 34.2 31.1 Plant with capture turned off 58.6 44.3 33.5 Capital cost Change in cost per kW of normal output, % +5.8 +3.9 +0.5 Change in cost per kW of peak output, % -8.7 -18.5 -5.6 Cost of extra peak power capacity, €/kW 354 322 213 CO2 emissions Tonnes CO2 per MWh of extra peak power 2636 2944 10450 The economic viability of turning off capture would depend on the carbon emissions price, the number of hours per week that capture is turned off and the peak electricity prices during the time when capture is turned off. The relationship between these factors for a base load PC plant is shown in Figure 2. For example, the carbon emission cost is €147/MWh at a cost of €50/t CO2. The overall cost increases as the number of hours of venting per week is reduced because the other fixed costs (Capex and O+M) are attributed to a lower number of MWh of peak power.

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Solvent storage Solvent from post combustion capture can be stored during times of peak power demand for regeneration during times of lower power demand. This reduces the requirement for other peak generation capacity. The extra generation during peak times would have low CO2 emissions, unlike the alternatives of by-passing CO2 capture as described earlier, or using peaking plants such as open cycle gas turbines without CCS. Solvent storage in IGCC was not assessed in this study because the Selexol solvent would have to be stored at high pressure and it was expected that the costs would be excessive. Foster Wheeler discussed the practicality of CO2 solvent storage with some leading technology suppliers, including MHI, Aker Clean Carbon and Alstom. These companies all confirmed the technical feasibility of storing solvent, provided the temperature of CO2-rich solvent is maintained at or slightly below the absorber bottom outlet temperature to avoid degassing. High rates of degradation are not expected, degradation would be mainly due to the reaction with oxygen so nitrogen or CO2 blanketing would always be considered. MEA-water solution that would be stored in capture plants is not flammable but solvent is toxic and the stores are potentially large, as discussed later, so it may not be acceptable at all locations. Regeneration of stored solvent could take place during times of ‘base load’ operation or during times of low power demand when the power plant is operating at part load. The operating mode of the plant would determine the required capacities of the solvent storage tanks and the solvent regeneration and CO2 compression equipment. If the plant is required to operate only at ‘base load’ the solvent regenerator and CO2 compressor would need to be oversized to cope with regeneration of the solvent from ‘peak load’ operating hours. If the plant is expected to operate for some of the time at reduced load, the stored solvent could be regenerated during these times and the regenerator and compressor would not need to be oversized. If a plant is expected to regularly operate at substantially reduced load at night and at weekends, the solvent regenerator and CO2 compressor could be undersized, i.e. they could be made smaller than in a normal base load power plant, thereby reducing capital costs. However, such a plant would not have the ability to operate at base load for long periods of time and this may not be attractive to the plant owner. Two operating scenarios described below were assessed in this study as an illustration but it is recognised that in reality power plant operations will depend on many external factors which may change during the operating life of a plant. PC plants were assumed to be operated at higher load factors than NGCC plants at night and at the weekend because their lower marginal operating costs would put them higher up the operating ‘merit order’. The ‘weekly’ and ‘daily’ scenarios involve different amounts of solvent storage and peak load operation.

1. Daily storage scenarios a. PC plant: Operation at peak load for two hours during the weekday day-time,

normal full load for the remaining 14 hours of the day-time and 50% load for 8 hours of night-time and all weekend. Stored solvent is regenerated during the night-time.

b. NGCC plant: Operation at peak load for two hours during the day-time, normal full load for the remaining 14 hours of the day-time and shut-down during night-time and weekend. Stored solvent is regenerated during normal day-time operation.

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2. Weekly storage scenarios a. PC plant: Operation at peak load for 16 hours during weekdays and operation at

50% load during 8 hours of night-time and all weekend. Stored solvent is regenerated during the night-times and weekend.

b. NGCC plant: Operation at peak load for 16 hours during weekdays and shut-down or operation at the minimum load required for solvent regeneration during night-time and weekend.

In the weekly scenarios the ‘peak’ times are almost half of the total hours. For the PC plants, if solvent regeneration was completely switched off during peak times the regenerator would have to be substantially larger than in the reference plant and it may be difficult to provide sufficient steam for the regenerators during the off-peak times when the plant is operating at 50% part load. In the scenarios assessed in this study the solvent regeneration was therefore reduced by only 25% at peak times. Two alternatives were assessed:

1. Reduced regenerator size. The regenerator is about 85% of the size in the reference plant, which enables all of the stored solvent to be regenerated during off-peak times

2. 100% regenerator size. There is no reduction in the size of the regenerator, which would enable the plant to operate for long periods at 100% load if required. To minimise the capacity of the storage tanks the regenerator is operated at full capacity during the weekday night times, and it is operated at lower throughput during the weekends.

The lower capital cost of storage tanks and stored solvent in alternative 2 is greater than the extra cost of a larger regenerator. This lower capital cost and the greater flexibility to operate at full load means that alternative 2 is preferred, so results for this are presented in this overview. In the NGCC weekly scenario no CO2-laden solvent is produced during off-peak times so it is possible to store 50% of the solvent during peak times without having to oversize the regenerator. Solvent is regenerated at off-peak time by operating one of the two power plants at minimum load. As with the PC plant, the lowest cost and most flexible option is to have a 100% sized regenerator. In the daily operating scenario solvent regeneration is shut down completely during the 2 hours of peak operation and all of the CO2–rich solvent produced during this time is stored. In the PC plants the stored solvent is regenerated during the night time when the plant is operating at 50% load. In the NGCC plants the stored solvent is regenerated during the remaining 14 hours of daytime operation, which requires the regenerator to be over-sized by about 14% compared to a capture plant without solvent storage. The NGCC plants are fully shut down overnight and at weekend. Solvent storage has very little effect of the thermal efficiency except for the NGCC weekly scenario, in which the plant has to operate at low load at low efficiencies at off-peak times to regenerate solvent. The solvent storage tanks are conventional sized tanks as used at oil refineries but they are nevertheless substantial, particularly in the weekly scenario. As an example, in the NGCC daily scenario three tanks each of which is 27.4m diameter and 12.8m high are required.

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Table 3 Storage of post combustion CO2 capture solvent Power plant type NGCC PC NGCC PC Storage scenario Weekly Weekly Daily peak Daily peak Hours per week of peak output 80 80 10 10 Increase in power output at peak times, % 6.2 4.8 12.1 22.2 Thermal efficiency, % Reference plant efficiency, 100% load 50.6 34.8 50.6 34.8 Reference plant time weighted average efficiency 50.6 33.6 50.6 33.6 Storage plant time weighted average efficiency 45.3 33.5 50.5 33.6 Capital cost Change in cost per kW of normal output, % +19.6 +6.1 +9.3 +5.8 Change in cost per kW of peak output, % +12.6 +1.2 -2.6 -13.5 Cost of extra peak generation, €/kW 3116 2891 752 589 Solvent storage Quantity of solvent storage, 103m3 215 151 23 34 The overall economics of solvent storage are complex because there are substantial changes in the electricity output at various different times. An electricity price profile at different times is needed, which is beyond the scope of this study. However, an initial assessment of the economics can be made by comparing the capital cost of solvent storage and alternative means of generating peak load electricity. In the weekly scenario the capital cost per kW of additional peak generation capacity is greater than the cost of the reference power plant, which indicates that this scenario is unlikely to be attractive. In the daily scenario the capital cost per kW of additional peak generation capacity is less than the cost of the reference plant but it is probably higher than the cost of the leading alternative technology for peak load generation, namely simple cycle gas turbines. Solvent storage may be attractive in this scenario, depending on fuel prices, carbon emission costs and the electricity price profile. This study was based on the use of MEA solvent. The economics of solvent storage would be less favourable for alternative solvents that are more expensive because the solvent inventory costs would be higher. Liquid oxygen and air storage Storage of liquid oxygen (LOX) in oxy-combustion and IGCC plants can provide a boost to the peak power output by reducing the power consumption for oxygen production. During the times of peak power demand the power plant is operated at full load, the air separation unit (ASU) is operated at minimum load and the rest of the oxygen required by the power plant is taken from a LOX store. The LOX is vapourised by condensing liquid air which is then stored. During off-peak times the power plant is operated at part load but the ASU is operated at a higher load to enable the LOX store to be re-filled. Performance and cost data for PC oxy-combustion and IGCC plants with oxygen storage are shown in table 4. An alternative that was evaluated in the report but which is not shown in this overview involves having a smaller capacity ASU which is operated at constant load. This option would reduce the capital cost and oxygen storage requirement but it would give a smaller boost to the power output at peak times. The plant would also not have the flexibility to operate at full load for long periods of time, similar to the post combustion cases with a reduced size solvent regenerator mentioned earlier. The minimum efficient turndown of an ASU air compressor is 70% and the minimum turndown of the cold box is around 50%. In IGCC, turndown of the main ASU air compressor to 70%

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would give only a marginal increase in net peak power output. The ASUs are therefore configured to have two smaller air compressors, one of which is turned off during the time of peak demand and the other is operated at 70% load. Having multiple compressors increases the capital cost but provides greater opportunity for high peak generation. Half of the compressed air for the ASU in the IGCC plants is provided by extraction from the gas turbine, which earlier studies and practical experience has shown results in relatively high efficiency, good operability and low costs. When the power plant is operating at part load, less air is available to the ASU from the gas turbine compressor. To operate the ASU at full load more air has to be provided by the ASU’s own air compressors, so an additional compressor is provided for each ASU. In the oxy-combustion case shown in table 4 there are two 60% capacity ASUs, one of which is turned off at peak times. In the oxy-combustion plant only liquid oxygen and liquid air need to be stored but in the IGCC plant liquid nitrogen also has to be stored, as nitrogen is required for the gas turbine. Nitrogen accounts for more than half of the total storage volume. Table 4 Storage of oxygen Power plant type PC-oxy IGCC PC-oxy IGCC Storage scenario Weekly Weekly Daily Daily Hours per week of peak output 80 80 10 10 Power output Increase in output at peak times, % 5.3 7.7 5.8 10.5 Thermal efficiency, % Reference plant efficiency, 100% load 35.5 31.4 35.5 31.4 Reference plant time weighted average efficiency 34.0 29.5 34.0 29.5 Storage plan time weighted average efficiency 34.8 30.0 34.3 28.9 Capital cost, €/kW Change in cost per kW of normal output, % +2.5 +2.7 +0.9 +1.4 Change in cost per kW of peak output, % -1.5 -4.6 -4.6 -8.2 Cost of extra peak generation, €/kW 1573 928 381 336 Storage of liquid oxygen, nitrogen and air Quantity stored, 103m3 12.1 24.0 0.8 3.4 The volumes of storage are much smaller than in the solvent storage cases but vessels have to operate at cryogenic temperatures. The capital costs of peak generation are relatively low because unlike the earlier cases no additional power generation equipment has to be installed, instead the increased peak power is achieved by reducing the plant’s ancillary power consumption. Although the capital costs per kW of normal power output increase, the costs per kW of maximum peak output decrease, particularly for the daily storage scenarios. The capital cost of the extra peak generation capacity in the daily storage scenarios is competitive with alternatives open cycle gas turbines and the storage option has the advantage that extra peak generation has low CO2 emissions. This preliminary analysis indicates that oxygen storage should be an attractive option for providing additional peak generation. Hydrogen co-production and storage The flexibility of IGCC plants could be improved by storing surplus hydrogen-rich fuel gas produced during off-peak times. The stored hydrogen could be used to generate electricity at peak times or it could be supplied to other energy consumers. This would have the practical and economic advantages of enabling the gasification plant to continue to operate at full load at all times. The leading option for hydrogen storage would be underground salt caverns, which are a

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proven and relatively low cost technique for large scale hydrogen storage. Some liquid nitrogen would also be stored to satisfy the needs of the gas turbine. Performance and cost data are given in Table 5. The increase in peak power output per unit of gas turbine capacity is relatively small (3.3%) but the increase per unit of gasification plant capacity is greater (26.0%). The overall capital cost per kW of peak capacity is 8.5% lower than the reference IGCC plant. The capital cost of the extra peak generation capacity is negative because the capital cost of the plant is lower and the peak output is higher, although it should be noted that the plant would be unable to operate at continuous full load because of the under-sized gasification plant. Table 5 Storage of hydrogen Power plant type IGCC Storage scenario Weekly Hours per week of peak output 80 Increase in power output at peak times, % Per unit of gasifier capacity 26.0 Per unit of gas turbine capacity 3.3 Thermal efficiency, % Reference plant efficiency, 100% load 31.4 Reference plant time weighted average efficiency 29.5 Storage plant time weighted average efficiency 29.7 Capital cost, €/kW Change in cost per kW of normal output, % -5.5 Change in cost per kW of peak output, % -8.5 Cost of extra peak generation, €/kW negative Storage of hydrogen and nitrogen Quantity of hydrogen stored, 103m3 working volume 100 Quantity of liquid nitrogen stored, 103m3 7.2 The hydrogen storage volume is relatively small for a typical modern salt cavern store, for example about 5% of the capacity of a hydrogen storage cavern being built in Texas. This study focussed on coping with sort term (up to a week) variability in electricity demand. The relatively low cost of underground hydrogen storage means that this technique could also be cost effective for smoothing out longer term seasonal variability in electricity demand. Another case was assessed in which the gasification and CCS is operated at continuous full load, a constant flow of high purity hydrogen for other consumers is maintained at all times and some of the hydrogen rich gas from the CCS plant is stored at off-peak times. Details of this case are provided in the main report. Constant flow of CO2 to transport and storage Variation of the throughput of a CO2 capture plant would result in variation of the flowrate of CO2 to the transport pipeline and storage site. Little information is currently available on the ability of dense flow pipelines and storage wells to accept variable and intermittent CO2 flows and the effects may be site specific. Providing a constant flow of CO2 may have some have some practical and economic advantages. Two techniques for providing a constant flow of CO2 were assessed:

1. Buffer storage of compressed CO2 2. Buffer storage of CO2-rich solvent, combined with a reduced solvent regenerator

capacity

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In Case 1 it was assumed that CO2 would be stored in cylindrical pressure vessels. If longer term storage was required and suitable geology was available near the power plant site it may be worthwhile considering an underground temporary buffer store. Providing CO2 buffer storage for the NGCC and PC plants with the ‘weekly’ operating scenario described earlier (in the section on solvent storage) would increase the plant capital cost by €30-40/kW. This cost could in principle be offset by a reduction in the size and cost of the CO2 pipeline (and injection wells), for example in the NGCC case the cost savings for a 100km dedicated CO2 pipeline would more than offset the cost of CO2 storage. However if a small pipeline was built the plant would not be able to operate at continuous full load for long periods of time. The modest extra cost of installing a full capacity pipeline may be considered worthwhile to maintain the option to operate the plant at high load factors if required. Case 2 with a reduced solvent regenerator capacity and buffer storage of CO2 capture solvent was found to be substantially more expensive than Case 1 with storage of CO2.

Expert Review Comments Comments on the draft report were received from seven reviewers who have expertise in the power industry, oxygen production, IGCC project development, and research on post combustion capture and CCS plant flexibility. IEAGHG and the contractor reviewed the comments and various detailed changes were made to the report. The contribution of the reviewers is gratefully acknowledged. In general the reviewers thought the report was of a high standard. Some reviewers emphasised that many operational issues still need to be considered in detail and more dynamic modelling and optimisation of the control of power plants and capture units is needed. This was emphasised more in the report. Some reviewers expressed concerns that the load profiles originally assumed for the flexibility assessments may not be optimum as they resulted in excessive amounts of solvent storage, which raises economic, safety and regulatory concerns. To address these comments, additional cases involving short term peaking operation and substantially lower quantities of solvent storage were evaluated. More part load operation cases were also assessed and the oxygen storage cases were modified to also include liquid air storage, to address reviewers’ comments.

Conclusions • CCS may impose additional constraints on the flexible operation of power plants but,

depending on the specific characteristics of the power plants, there are ways of overcoming these limitations. A plant with CO2 capture may even be able to ramp up its net power output more quickly than a plant without capture, using the techniques considered in this study, because parts of the CO2 capture unit could be ramped down at the same time as the power plant is being ramped up.

• The efficiency penalties for part load operation are expected to be somewhat greater for

plants with CO2 capture than plants without capture, for example around 3 percentage points at 50% load for a pulverised coal plant with post combustion capture compared to around 2 percentage points for a plant without capture.

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• Increasing the power output by turning off the CO2 capture unit could be an attractive

technique for short periods, depending on the peak power price and CO2 emission cost. Regulations would need to allow the resulting increase in CO2 emissions, for example by averaging emission performance standards over a long period. Some additional equipment, particularly steam turbine capacity, would have to be installed to obtain the full benefit from turning off the capture unit, which would increase the capital cost. Turning off capture would increase the power output by 27% for a pulverised coal fired plant and 16% for a natural gas combined cycle plant.

• Storing CO2–rich solvent and regenerating it at a later time could be attractive as a way of

increasing power plant ramp rates and for increasing the net power output during short term peaks in power demand. However, the large quantity of solvent that would have to be stored would mean that operating at peak output for longer periods of time would not be attractive. Plants could be built with a wide range of storage volumes, solvent regenerator sizes and peak power generation capacities. Selecting the optimum would be a difficult commercial decision.

• Liquid oxygen and air could be stored in oxy-combustion and IGCC plants to improve

flexibility and peak generation capacity. From an economic perspective this is expected to be an attractive option for short term peak power generation.

• Hydrogen produced in IGCC plants with pre-combustion capture could be stored for

example in underground salt caverns, which is a commercially proven technique. This would enable the gasification and CCS equipment to operate at continuous full load while providing a variable power output from the combined cycle unit, and it would provide faster ramp rates and lower capital costs for non-base load power plants. Underground hydrogen storage has a relatively low specific cost so it could provide longer-term as well as short term storage. This would be useful in electricity systems that include large amounts of variable renewable generation such as wind generation, which may remain low for several days.

• Compressed CO2 could be stored at capture plants to reduce the variability of flows of CO2

to the transport and storage equipment, if this is deemed to be necessary. Buffer storage of CO2 would enable a smaller capacity CO2 pipeline to be built but this would constrain the ability of the power plant to operate at continuous full load, which may not be commercially attractive.

Recommendations • The requirements for CCS plant flexibility in future electricity systems need to be

determined using electricity system dispatch modelling. This is not a core expertise of IEAGHG and system modelling depends on many local factors. It is therefore recommended that IEAGHG should collaborate with other organisations that are undertaking modelling of electricity systems that include CCS and other low CO2 technologies in a range of different countries. IEAGHG could contribute its expertise on CCS plants, including the results of this study.

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• The ability of CO2 transport and storage systems to accept variable flows of CO2 should be assessed

• IEAGHG should continue to monitor work on CCS flexibility and produce reviews and new

study proposals when appropriate.

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CO2 CAPTURE AT GAS FIRED POWER PLANTS

This study has been undertaken by Parsons Brinckerhoff. The contractor’s final report will be received during the last week of March. A draft overview will then be prepared and sent to members, for discussion at the 41st ExCo meeting.

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IEA GREENHOUSE GAS R&D PROGRAMME

41st EXECUTIVE COMMITTEE MEETING

FINANCIAL MECHANISMS FOR LONG-TERM CO2 STORAGE

Background to the Study Liability is the legal responsibility that one has to another or society, enforceable by civil remedy or criminal punishment. Post-closure (long-term) liability for CCS is largely related to potential migration (within the subsurface) or potential leakage (to the surface) of the stored carbon dioxide. The IPCC Special Report on Carbon Dioxide Capture and Storage (2005) describes potential pathways for such leakage to take place: for example via poorly abandoned wells (the most likely), through pores of low-permeability caprocks, or migration through faults. Such could result in environmental risks (groundwater contamination and risks to the ecosystem), subsurface trespass and climate effects. Potential CO2 leakage must also be considered in terms of emissions accounting liability. It must be recognised that the containment of carbon dioxide should become safer over time due to geophysical and geochemical processes that can act as trapping mechanisms for the stored CO2. However, emissions accounting liability under an emissions trading scheme (ETS) can be accumulative and uncertain as to scope and ETS value, which can create great uncertainty for operators and authorities. During the operational phase of a CCS project until closure (short-term) it is logical to apportion the liability to the operator of the site as they are most able to manage the risk of any leakage occurring. For the ongoing post operational phase (long-term) however, it is unlikely that the former operator of the site will be able to be held accountable over much longer timescales and the general expectation is that liability will transfer to the state. A major issue on the liability of CO2 storage is when to set the shift from ‘short-term’ to ‘long-term’.

There are numerous existing regulations and emerging CCS-specific regulations that need to be considered when investigating long-term liability mechanisms. The European Commission adopted a Directive (2009/31/EC) in 2008 to enable environmentally-safe capture and storage of CO2 in the EU. The Directive has been accompanied by European Commission (EC) Guidance Documents, which; though will not be legally binding; provide guidance on risk management, site characterisation, monitoring, corrective measures, transfer of responsibility and financial security/contribution. These Guidance Documents consider different types of liability – strict liability on the operator under the Environmental Liability Directive, financial liability to buy emission credits under the EU ETS and potential liability in negligence. The US EPA rule on CO2 storage (2010), requires financial support from the operator until the end of post-injection site care and monitoring (suggested as 50 years). Financial instruments allowable include trust funds, surety bonds, letter of credit, insurance, self insurance, corporate guarantee and escrow account. In the EU, allowable financial mechanisms (described in EC Guidance Document 4) include funds (or deposits), trust funds, escrows, bank guarantees, irrevocable standby letters of credit, and bonds issued by a bank. Financial mechanisms for long-term liability will be responsible to either the operator or competent authority, depending on the regulations of that specific region. Zurich Insurance have developed a number of insurance policies for CCS although currently they do not cover long-term liability. At the time of the

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development of the EC and EPA regulations it was viewed that there was a need for information and assessment of such financial instruments and their applicability to CCS projects.

Scope of Work The study aimed to review existing and emerging CCS specific regulations, in different regions of the world and under different legal frameworks, concentrating on long-term liability aspects. The primary work of the study was to investigate and assess the various potential financial mechanisms for supporting CO2 liability, including an assessment of their applicability and practicality to all parties concerned, and provide recommendations based on the findings. As well as discussion on important issues such as when and how transfer of liability to the government should occur, and what these liabilities could be, the study focuses primarily on how this liability can be supported. The specific objectives for this study were as follows:

• Review current CCS and non-CCS regulations in different regions of the world with a focus on financial mechanisms for long-term liability, including government assumption of liabilities.

• Investigate and assess potential financial mechanisms for long-term CCS liability and provide recommendations based on the findings. Clearly explain the strengths and weaknesses of potential financial mechanisms to address facilities’ long-term CCS liability concerns.

• Assess liability transfer issues such as when and how transfer of liability to the government can occur, what these liabilities could be, and how liability transfer can be supported financially.

It was ensured that the contractor for this study had a thorough understanding of appropriate liability, insurance and financial mechanism sectors globally, as well as an understanding of the liabilities associated with CCS.

Findings of the Study The financial challenge for private and public entities is to make provisions for paying in the future for stewardship responsibilities and compensatory liabilities after CO2 injection has ceased, which is when the geosequestration facility’s revenue stream may be much less. The financial challenge is complicated by the uncertainty of whether any compensation claims will arise, when they might appear, and what their magnitudes might be. Stewardship obligations have two elements that require funding – a steady low-level of inspection/monitoring with another element of higher costs (e.g., for remediation of leaks) triggered by physical events affecting the storage facility. Uncertainty affects the financing of both compensatory liabilities and stewardship liabilities, which may continue into perpetuity.

Of particular concern to stakeholders is the lengthy and indefinite timeframe of possible long-term stewardship and compensatory liability at CCS storage facilities. Stakeholders are seeking clarity about how, if at all, regulatory frameworks will incorporate financial requirements for long-term stewardship and compensatory liabilities; which financial mechanisms will regulatory frameworks allow to be used to satisfy financial requirements; and how those options will work (including cost and availability).

This study was conducted because little information of general applicability that responds to these concerns, needs, and beliefs is available to CCS stakeholders.

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In general, for facilities posing potential environmental safety and health risks, financial requirements typically apply to one or more of the following liabilities:

• proper closure/decommissioning • remediation • aftercare • rehabilitation/reclamation of affected land for another use • compensation of bodily injury and property damage/loss to private parties • compensation of damage/loss to the public’s natural resources

According to the EC, the liabilities associated with CCS projects include the following:

• Monitoring. • Corrective measures, including measures to protect human health, in the event of

leakages or significant irregularities. • Surrender of emission allowances due to inclusion of the storage site under the ETS

Directive. • Sealing the storage site and removing the injection facilities. • Operating the site, after the government withdraws the storage permit, when the

government decides to continue CO2 injection temporarily until a new storage permit is issued.

• Making the required financial contribution (FC) for post-transfer liabilities available to the government prior to transfer of responsibility. The EC recommends that the FC obligation be covered by a financial mechanism commencing during the operations period.

According to the US EPA, the liabilities which have to be covered by the financial instruments must cover the following:

• corrective action, • injection well plugging, • post injection site care and site closure, • emergency and remedial response, • address endangerment of underground sources of drinking water, • coverage must include at a minimum cancellation, renewal, and continuation provisions.

Financial Mechanisms A financial mechanism refers to one of many instruments that can be used to ensure funding for long-term liabilities. This report identifies and describes eighteen types of financial mechanisms, choosing the ones most likely to be accepted as complying with government financial requirements for CCS. The report describes the strengths and weaknesses of each type of financial mechanism, including an assessment of its applicability and practicality to all parties concerned. The description of the mechanisms is provided below, with the summary of the analysis of each for their applicability and practicality in relation to long-term CCS obligations. More detail on the analysis of each is provided in the main report.

Third-Party Mechanisms

Irrevocable Trust Fund: Independent trustee accepts property from owner/operator to manage as a fiduciary for a particular purpose on behalf of a beneficiary (e.g., government regulatory agency).

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Trustee is a bank or other financial institution that is regularly examined and regulated by an independent financial oversight entity. Once accepted into the trust fund, the property ceases to be owned by the owner/operator, is outside its control and beyond the claims of its creditors. The trust is considered irrevocable because the owner/operator cannot unilaterally terminate the trust and reclaim the property.

Applicability: Trust funds are well suited to provide financial security over the long-term as they are “irrevocable” and protected from claims of creditors.

Practicality: Trust funds are practical for CCS long-term liability because they have low administrative burdens and are available to all operators, regardless of credit-worthiness.

Escrow Account: Agent of the owner/operator manages funds set aside for an explicit purpose. Unlike the trustee for an irrevocable trust fund, the escrow agent does not owe the government beneficiary a fiduciary duty. Instead, the escrow agent is responsible to the party placing funds into the escrow. Funds in escrow remain the property of the owner/operator, and are subject to the control of the owner/operator and the claims of creditors. Escrows are revocable.

Applicability: Escrow accounts offer less security compared to other mechanisms due to their revocability and lack of protection from claims of creditors of the owner/operator.

Practicality: Escrow accounts have not traditionally been used to finance long-term obligations and so may not be practical given limited experience.

Bank Demand (Payment) Guarantee, Irrevocable Standby Letter of Credit, Surety Bond (Payment Bond): All three of these mechanisms involve a third party (i.e., bank or surety company) guarantee of payment, up to a specified limit, to the beneficiary (e.g., government) on demand if specified conditions are met. The owner/operator is responsible to reimburse the third-party guarantor. Issuers must be financial institutions that are regularly examined and regulated by an independent financial oversight entity.

Applicability: Well-suited to provide assurance over long time-periods because they can be “irrevocable”, automatically renewed, and the amount is easily adjusted.

Practicality: Able to secure high amounts. Financial institutions generally do not expect to incur significant risks from these mechanisms and offer them only to creditworthy parties.

Surety Bond (Performance Bond): Surety company guarantee that it will satisfy the owner/operators obligations as specified in the surety agreement, if the storage site owner/operator fails to perform. Unlike a surety payment bond, the performance bond gives the surety the option to perform the owner/operators obligations.

Applicability: Well-suited to provide assurance for obligations that can be performed such as stewardship.

Practicality: They are “irrevocable” and automatically renewed. Financial institutions generally do not expect to incur significant risks from these mechanisms and offer them only to creditworthy parties

Prepaid Insurance Policy for Assurance of Closure & Post-closure Monitoring: Insurer guarantees costs of performing closure and post-closure monitoring upon the insured’s prepayment of the required premiums. Issuers must be financial institutions that are regularly examined and regulated by an independent financial oversight entity.

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Applicability: A prepaid insurance policy can be used for post-closure monitoring, is nearly irrevocable, and places the secured funds beyond the control of the CCS operator, making it an applicable mechanism for long-term CCS liability.

Practicality: The limited availability of prepaid insurance policies to cover CCS post-closure liabilities may make this an impractical mechanism at the current time

Liability Insurance Policy for Payments Due to Losses or Damages: Insurer guarantees payment for losses or damages incurred by others. Scope of liability insurance typically addresses damages or losses to parties other than the owner/operator, including losses/damage to publicly-owned resources. Terms, conditions, definitions, and the like may restrict coverage to defined amounts, perils (causes), losses, parties, and the like, which may result in insurance that does not fully address financial requirements. Issuers must be financial institutions that are regularly examined and regulated by an independent financial oversight entity. These policies are not irrevocable.

Applicability: Liability insurance might not be available to provide coverage for long-term stewardship and other first-party liabilities such as corrective measures.

Practicality: The limited availability of liability insurance products for CCS long-term liability makes insurance not a practical mechanism for CCS at this time

Corporate Guarantee from Non-affiliated Corporation Based on (Annual) Financial Test: A company neither owned by nor having a common owner with the storage facility owner/operator guarantees the owner/operators obligations. The financial test must be met by the non-affiliated corporate guarantor and may include requirements for net working capital, total assets, tangible net worth, and/or credit ratings.

Applicability: Generators of CO2 that are not affiliated with the operator can provide guarantees if they can pass the financial test.

Practicality: Corporate guarantees from non-affiliated companies are low cost financial mechanisms for CCS long-term liability.

Third-Party Administered Mutual Industry Pool: Third-party (neither the government nor an owner/operator) manages collective fund into which multiple industry members contribute. The fund is available to pay for long-term stewardship and/or compensation either as a primary funding source or as a back-up if contributors fail to meet their obligations. As a collective fund, industry members do not have individual accounts that limit payments from the fund to the sum of an individual’s contributions plus interest. The fund could be organized as a mutual insurer, a group captive, a risk retention group (in the United States), or otherwise.

Applicability: Pools require a number of relatively homogenous members facing independent financial risks. If CCS operators are not likely to be active and viable during the period after closure in which long-term liabilities could arise, mutual industry pools might not have enough resources to properly address financial requirements, and thus are a poor financial mechanism to assure long-term liabilities associated with CCS.

Practicality: Until there are enough active CCS operators, mutual industry pools will not be a practical option to adequately address long-term financial requirements.

First-Party Mechanisms

Security Interests in Property: Creation of a claim on owner/operator assets to guarantee the performance or payment of an obligation. The government beneficiary of the security interest has

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preferential rights, usually the right to seize and sell the property in the event that obligations are not met. The ownership and control of the property remains with the owner/operator and is subject to the claims of other creditors.

Applicability: Security interest in property would not be applicable for recurring stewardship liabilities.

Practicality: Security interests in property would be a high-burden, high-risk, inflexible mechanism for long-term CCS liabilities

Charge over an Operator’s Bank Account: Creation of a claim on an owner/operator bank account to guarantee the performance of an obligation. The government beneficiary of the charge has preferential rights, usually the right to access funds within the bank account in the event that obligations are not met. The ownership and control of the property remains with the owner/operator and is subject to the claims of other creditors.

Applicability: A charge over a bank account can last only as long as the account, so this mechanism would not be able to outlast the operator. In the event that liabilities arise after the CCS operator has gone out of business, the government would need to use public money to take on those obligations.

Practicality: Industry could easily establish and maintain this mechanism at low added cost, given existing bank accounts. High burden on the government to continuously oversee the charge makes this mechanism impractical

Corporate Guarantee from Affiliated Company Based on (Annual) Financial Test: A company affiliated (as parent, subsidiary, or having a common parent) with the site owner/operator guarantees the owner/operators obligations. In this case, the financial test must be met by the affiliated guarantor. A guarantee from a subsidiary of the owner/operator does not provide an independent source of funding.

Applicability: Like CCS operators, affiliated companies that make corporate guarantees are unlikely to remain both active and viable for the duration of long-term liabilities. Corporate guarantees set aside no actual funds and may not offer a fully independent a source of funds due to intercorporate affiliations. Accepting corporate guarantees from an affiliated company based on (annual) financial tests is a controversial choice for assuring CCS long-term liability.

Practicality: Corporate guarantees from affiliated companies based on financial tests would provide low-cost, financial mechanisms for long-term CCS liability. Affiliated companies may be financially strong and relatively independent of the financial condition of the operator

Self-Guarantee Based on Annual Financial Test: Owner/operator demonstrates ability to pay for obligations using a financial test, which may include requirements for net working capital, total assets, tangible net worth, and/or credit ratings. Not an independent source of funding.

Applicability: Self-guarantee provides no additional financial resources beyond what the operator can raise. CCS operators unlikely to be both active and viable for the potential duration of their long-term liabilities.

Practicality: Government regulators may not have skills and interests required to assess whether the operator’s finances pass the financial test

Self-Guarantee with Internal Account Reserve (Instead of Financial Test): Owner/operator guarantees satisfaction of obligations by designating an internal account for that purpose. The ownership and control of the funds remains with the owner/operator and is subject to the claims of creditors. Not an independent source of funding.

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Applicability: Because CCS operators are unlikely to remain active and viable during the period after closure in which long-term liabilities could arise, internal account reserves provide very little financial security for long-term liabilities.

Practicality: Internal account reserves provide a financial mechanism with low cost for a CCS operator to establish and maintain.

Government Mechanisms

Deposits of Cash or Cash Equivalents to Government Authority (GA): The government agency accepts cash or cash equivalent deposits directly from owner/operator to be used later to satisfy owner/operator obligations. GA may create a special account on behalf of the owner/operator or may turn the funds over to the government treasury.

Applicability: A deposit to a GA can last as long as necessary, which makes this mechanism well suited for long-term CCS liabilities.

Practicality: A deposit to a GA may not be a practical mechanism for operators without sufficient assets or cash flow

Government-Administered Pooled Funds: Government manages pooled fund. Contributions may be received directly from owners/operators or indirectly as fees on injection, electricity use, or fossil fuels purchased for power generation. The fund can be designed either as a primary funding source or as a back-up available to reimburse the government if an owner/operator fails to meet certain obligations and the government becomes responsible to satisfy owner/operator obligations.

Applicability: Government-administered pooled funds can assure coverage for long-term CCS activities, with a sufficient number of financially viable participants and if the funds are protected from being appropriated for other uses. Urgent, non-CCS-related scenarios may arise that result in diversion of funds.

Practicality: Government-administered pooled funds are difficult to set up and maintain. Risk-based fees likely to be more controversial than per unit fees.

Government Guarantees: Government agrees to guarantee payments to claimants for specified liabilities as a back-up. A guarantee is a promise to answer for the debt, default, or other liability of another. A government guarantee about CCS could mean that the government will pay for third-party damage/loss that the responsible owner/operator fails to pay. The payment goes not to the owner/operator (as for indemnification) but from the government to the party that the owner/operator has not paid. Because the guarantee is a duty owed to a claimant and not the owner/operator, the guarantee can outlive the owner/operator.

Applicability: Government guarantees are considered secure and likely to last longer than mechanisms provided by private-parties.

Practicality: Government guarantees are commonly used in jurisdictions to foster infrastructure development and industrial activity. This mechanism could be used in countries where the government and its finances are stable enough to guarantee payments over the long timeframe of post-closure CCS activities

Government Assumptions of Liability: Government takes primary responsibility away from the site owner/operator for specified liabilities if pre-determined criteria have been met. Also referred to as “transfer of liabilities”.

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Applicability: Governments are considered more likely to be active and viable in the long-term than industry. The government could require that an operator fulfill certain safety requirements prior to the govenrments assumption of liabilities to minimize the risks and magnitudes of long-term liabilities assumed by the government.

Practicality: Government assumption of liability would be an attractive option for operators who may be wary of entering the CCS industry due to the indefinite time-frame and uncertainties of long-term CCS liabilities.

Government Indemnities: Government agrees to reimburse owner/operator for payments made for specified liabilities. Not a primary funding source. The indemnification payment goes to the owner/operator from the government, unlike for government guarantees where the payment from the government goes to the creditor of the owner/operator. Because indemnification is a duty owed to the owner/operator, that duty ceases if the owner/operator is defunct. Applicability: Government indemnities can be applied to CCS long-term liability. Because governments are more likely to be active and viable in the future than operators, government indemnification can provide long-term financial security for CCS long-term liabilities.

Practicality: The implementation of government indemnities could involve many government departments and legislation, resulting in a high administrative burden. The public and government are unlikely to be willing to take on liabilities in uncapped amounts

Approaches for transfer of long-term liability. The report identifies and analyzes key generic aspects of frameworks for transfer of long-term CCS liability to the government. These aspects are: threshold technical requirements; financial requirements related to liability transfer; post-transfer cost recovery provisions; specification of which and whose liabilities may or must be transferred. For the purposes of summarising the assessments of options of liability transfer frameworks, the following comments are made on the evaluative criteria. Costs to Industry and Government/Taxpayer. Transfer of liability frameworks serve to re-allocate costs of long-term CCS liabilities away from industry and onto government. Part of the rationale for such transfers is that government bodies are more likely than businesses to endure over long time periods. In addition, there may be a net cost savings to society by having government take primary long-term responsibility for CO2 storage sites, given that the alternative is for industry to have primary responsibility with government exercising oversight.

Incentive Effects. Much of the necessary expertise for large-scale underground CO2 storage is found in industry. Transfer of liability frameworks are intended to make industry more comfortable with playing a large role in CO2 geosequestration. Thus, options for liability transfer frameworks have been assessed in terms of their implications for industry participation in CO2 geosequestration. In addition, the provisions of liability transfer frameworks might affect industry incentives for performing siting, injection, closure, monitoring, and the like, given that liability transfer frameworks are thought to create moral hazard: by transferring long-term liability to government, industry may not perform at the same level that would occur if industry retained subsequent liabilities. It is thought that requiring an owner/operator to retain some long-term liabilities reinforces incentives for proper injection and storage of CO2 prior to facility transfer. This arrangement may reduce concerns about

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moral hazard because it creates a disincentive for the owner/operator to perform its technical responsibilities poorly.

Effectiveness of Protection of the Public/Environment. Requiring that facilities achieve high performance standards as a precondition of liability transfer should help reduce future threats to the public and the environment as well as reduce the need for future mitigation or remediation costs to be borne by industry or government. In addition to clear, objective standards (e.g., for closure) that can be assessed and verified prior to transfer of liability, an explicit post-closure period prior to transfer can assure that the responsible owner/operator has properly closed the site and that it is not leaking CO2 either to the atmosphere or to underground formations where proper controls may be lacking.

Duration. Liabilities associated with CO2 storage may persist for hundreds of years, possibly outlasting lifetimes of businesses. This extended duration must be considered in designing a liability transfer framework in order to ensure that liability remains with an entity capable of fulfilling long-term liabilities.

The report does not seek to recommend any one liability transfer framework option, as this is up to the host country and their national interest and policy situation, but the report does describe two examples of frameworks which show different balances between the evaluation criteria above.

Expert Review Comments Expert comments were received from 5 reviewers, representing industry (corporate sponsors of IEAGHG) and academia. The feedback was constructive and supportive of the work that had been carried out, noting the material was overall comprehensive and detailed. Following the expert review process, improvement to the report was made primarily in particular areas. The scope was extended to explain more what should be covered when considering liabilities and what such liabilities may be (using examples). More conclusion/summary paragraphs were added throughout the paper, in particular after lengthy tables of information, making the report easier to read and understand key points. The contractors also added some additional key references, as recommended by the reviewers, to back key ideas and improve accountability.

Conclusions Government financial requirements primarily protect the government/taxpayer from the risk of the operators failing to fulfil its obligations, although some acceptable financial mechanisms also may serve as a funding source for the operator. On the other hand, for the benefit of shareholders/owners, an operator may take a variety of positions regarding its exposure to long-term CCS liabilities, ranging from use of a financial mechanism to self-insurance without a financial mechanism.

This report identifies and describes eighteen types of financial mechanisms, choosing the ones most likely to be accepted as complying with government financial requirements for CCS. The report describes the strengths and weaknesses of each type of financial mechanism, including an impartial assessment of its applicability and practicality to all parties concerned in relation to long-term CCS obligations.

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In most cases, industry will finding that self-guarantees and corporate guarantees present the lowest after-tax costs, if these mechanisms are acceptable in the jurisdiction and if the operator or guarantor can pass the associated financial tests of eligibility.

In developing regulatory frameworks for CCS, legislators and regulators should indicate which financial mechanisms will be acceptable for long-term CO2 storage liabilities. Governments should allow use of multiple, acceptable financial mechanisms in order to provide compliance options to facility operators. Industry’s position on financial mechanisms for long-term CCS liabilities may differ when responding to government financial requirements as opposed to when managing those liabilities independently of government financial requirements. Industry may want to propose a package of acceptable financial mechanisms that might involve more than one financial mechanism for a given long-term liability. For example, a “sinking fund” approach involves two mechanisms: (1) a fund that is built up over a given time interval (e.g., 5 years) and (2) a complementary guarantee that decreases in amount as the sinking fund increases. The two mechanisms must always together equal or exceed the required amount for covering the obligation. Similarly, when an operator faces financial requirements for two or more long-term liabilities, a package of different types of acceptable financial mechanisms may allow for lower costs and a greater degree of risk-sharing with the government. For example, a package might contain a more conservative financial mechanism for post-closure monitoring combined with a potentially higher risk financial mechanism for post-closure remediation, on the theory that the remediation obligation is more unlikely to arise.

Recommendations

This report provides in one document a review of likely financial mechanisms for long-term liabilities relating to CO2 geological storage. The report does not seek to recommend any one financial instrument or liability transfer framework option, as this is up to the host country and their national interest and policy situation. Although stakeholders may disagree about what ought to be done, this study should assist stakeholders to agree on what can be done, recognizing that different approaches may be preferred in different countries and regions.

Discussion will continue to arise around long-term liabilities within the meetings of the IEAGHG storage networks, and the findings of this study should provide some more understanding of what can be done to manage and finance these.

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EXTRACTION OF FORMATION WATER FROM CO2 STORAGE

This study has been undertaken by The Energy & Environmental Research Center, in North Dakota, USA. The draft report as been received and the EERC are currently integrating the expert review comments, with the final report expected in June An attached draft overview has been prepared for member’s comments and approval at the 41st ExCo meeting.

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EXTRACTION OF FORMATION WATER FROM

CO2 STORAGE

DRAFT OVERVIEW

Background to the Study

Deep saline formations (DSF) constitute the largest potential global resource for the geological storage of CO2 and are therefore crucial to the successful up-scaling of storage from pilot and demonstration projects to commercial operations. However, there are uncertainties relating to the capacity and injectivity of DSF, with particular concerns relating to the management of pressure and potential displacement of formation brines. Extraction of saline waters from storage formations provides a potential solution to pressure management; for example the proposed Gorgon storage project in Australia includes the provision of pressure relief boreholes. The effect of pressurisation in a storage formation will depend largely on whether the system can be considered as open or closed. In a closed or semi-closed system, the pressure build-up will be determined by the boundary conditions, which include the shale permeability. Recent studies have shown that microdarcy scale shale permeability will allow brine displacement, while very low shale permeabilities on the nanodarcy to subnanodarcy scale will not. Part of the problem comes from the uncertainty in assessing brine displacement due to boundary condition uncertainty. It can be difficult to determine macroscopic scale permeability, even when samples have been obtained, due to problems with up scaling measurements as regional permeability effects also need to be taken into account (IEAGHG, 2010). Pressure relief wells can compensate for increases in pressure caused by injection, though extraction rates will depend on site-specific factors e.g. geological structure, shale permeability and heterogeneity. Heterogeneities in the storage formation may cause complexities in predicting flow rate and direction of injected CO2. If an extraction well is placed along a path of high permeability, then the rate of flow towards the well would be high, resulting in unwanted CO2 breakthrough. This may necessitate the plugging of the old well and the consequent drilling of a new pressure relief well, thereby increasing the potential cost of the project and possibly affecting the storage security. This possibility highlights the importance of a detailed site characterisation. Brine extraction could also play a part in plume management. The plume may be managed both laterally and vertically, as the CO2 will be forced to migrate towards the extraction wells. In the case of forced downward migration, the extraction wells will be towards the base of the storage formation. This will cause a larger vertical proportion of the formation to be used and the lateral extent and contact of the CO2 plume with the caprock will be reduced. Both of these effects can increase storage security. This also means that CO2 plumes formed at adjacent or nearby injection wells would be less likely to interact with each other. For large scale projects, there are likely to be multiple injection and pressure-relief wells. It is important to consider how they will interact with each other, as there will be an overlap of pressure footprints from each well.

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The water extracted from the storage formations will need to be used or disposed of in some way, for example, at the proposed Gorgon project in Australia, the planned injection of the extracted brine will be into an overlying saline aquifer. Possibilities for future sites include disposal directly in the sea, which would be dependent on the composition of the brine; alternatively the water could be utilised for other industrial processes, such as the cooling process within power stations or use as geothermal energy or it could be desalinated and used either for irrigation or drinking water. The latter options would depend on the cost and demand of water as a resource. The Energy & Environmental Research Center, in North Dakota, USA, was commissioned by IEAGHG in March 2011 to provide a thorough review of existing information and published research on the effects of brine extraction from CO2 storage sites. The study will also aim to highlight the current state of knowledge and / or gaps and recommend further research priorities on these topics.

Scope of Work

The main aim of the study would be to assess the global potential for extraction of formation waters as part of DSF storage projects. The study would comprise a comprehensive literature review, from published research and industrial analogues (e.g. brine disposal from petroleum and coal bed methane industries) to provide guidance on the following issues:

• Potential rates of brine extraction required for varying injection rates, across a typical range of DSF storage scenarios;

• Likely range in chemical composition of extracted brines; • Options for disposal of brine, either surface or subsurface, and associated potential

environmental impacts; • Onshore and offshore considerations, including treatment required for different disposal

options. • Potential for utilisation of extracted brines, e.g. cooling water for power stations, geothermal

energy, and assessment of associated environmental impacts; • Potential for surface dissolution of CO2 in extracted brine and re-injection into storage

formations; • Regulatory constraints, including for monitoring requirements, potential liability and water

quality requirements for different uses. • Potential economic implications for CO2 storage of brine extraction and the various options

for disposal/utilisation, to be illustrated by selected case studies.

The contractor was asked to refer to the following recent IEA GHG reports relevant to this study, to avoid obvious duplication of effort and to ensure that the reports issued by the programme provide a reasonably coherent output:

• Brine Displacement and Pressurisation (2010/15) • Injection Strategies for CO2 Storage Sites (2010/04) • Impacts on Groundwater Resources (2011/11)

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Findings of the Study

The approach taken in this report was to consider case studies with a wide range of geological, geographical and geopolitical conditions, which may impact the ability to implement an extracted water plan in conjunction with commercial scale storage projects. Relatively simple 3-D models were formed to test different injection and extraction scenarios and incorporate vital, heterogeneous reservoir properties, including structure, porosity, permeability, water quality, lithology, temperature, and pressure, which were obtained from published sources. When published data were insufficient to capture expected heterogeneity or did not appear in the literature, variogram ranges and property values were obtained from the revised AGD (Average Global database), which is comprised of information from hydrocarbon reservoir properties as a proxy for DSF characteristics. The AGD was compiled through use of existing US databases and an extensive literature review for other regions (IEAGHG, 2009).

The case studies selected were the Ketzin, (near Potsdam in Germany); Zama (Alberta, Canada); Gorgon (Barrow Island, Australia) and the Teapot Dome (Wyoming, USA) projects. These projects were selected to include a range of geological conditions and formation water quality.

For each case study a range of injection scenarios were considered as well as CO2 surface dissolution, whereby CO2 could be stored by dissolving it in extracted formation water and then injected into a geological formation.

The economic potential of the formation water from each case study site was evaluated with respect to its applicability for beneficial use. Cost estimates were provided for desalination due to a focus on beneficial use of the water. Other water treatment and disposal options were also outlined. The range of water quality represented by the four case studies is representative of a broad range of water quality that is likely to be found in deep saline formations. The type of purification process that can be applied depends on the quality of the formation water, which is taken into account for each case study.

Most of the case study sites are located in depleted oil or gas fields and, as such, are likely to contain varying concentrations of hydrocarbons, which may increase overall treatment costs and/or limit the potential for beneficial use. As described earlier, these sites function as analogues for similar and less well-characterised saline formations. Thus, the presence of hydrocarbon constituents in extracted water were acknowledged, but ignored for the purpose of the calculations.

Ketzin

This is a pilot scale CO2 injection project into a deep saline formation in Germany and so far 60 tonnes have been injected into the Triassic Stuttgart Formation. This storage formation consists of a series of fluvial channels surrounded by floodplain deposits. The confining structure is the Ketzin-Roskow anticline. The formation water quality is the lowest of all the case studies and local demand is low due to the location of the Havel River.

Ten cases (Table 1) were simulated to analyse different injection and extraction scenarios and assess differences in storage capacity and efficiency, as well as to define potential volumes of produced water for treatment or disposal. A total targeted injection of 50 megatonnes was chosen for the site, which aims to inject 2 megatonnes per year for a period of 25 years into a single vertical injection well.

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Table 1: Case Scenarios and Resulting Storage Capacities for Ketzin

Scenario Well Configuration

Gas Injection Rate/Well,

kg/day

Water Production Rate/Well,

m3/day

Boundary Conditions

Storage Capacity,

megatonnes

Case 1 1 injector 451,000 * Closed 4.12 Case 2 (base

case) 1 injector 1,430,000 * Semiclosed 13.0

Case 3 1 injector 1,980,000 * Open 18.1 Case 4 1 injector

1 extractor 2,810,000 11,800,000 Semiclosed 25.7

Case 5 1 injector 1 extractor

3,000,000 12,500,000 Open 27.4

Case 6 2 injectors 3,550,000 * Semiclosed 32.4 Case 7

(surface dissolution)

1 injector 1 extractor

* 3060 Semiclosed 0.43

Case 8 (surface

dissolution)


* 3,090 Semiclosed 0.55

Case 9 (surface

dissolution)

4 injectors 5 extractors


Case 10 (surface

dissolution)



Due to the structure, geological heterogeneity, and depositional environment at Ketzin, the modelling showed that it was difficult to obtain good connectivity between injector and producer pairs, resulting in poor improvements in plume control and storage capacity. This was evident by the highest storage capacity being obtained from two injectors rather than any scenario with an injector and producer. Surface dissolution is not a viable option in the Ketzin case because of extremely high salinities, resulting in very low storage capacities, and local heterogeneities resulting in poor communication between injection and extraction wells. These results indicate that from a CO2 storage/reservoir management standpoint, water production is not a viable option for Ketzin in any scenario, though adding more injectors will yield higher storage capacities. The formation water at Ketzin is high-salinity water and not favourable for use as source water for beneficial use. The options that have been identified for handling this water include reinjection into a geological formation or treatment with a zero liquid discharge (ZLD) method that results in a dry salt for disposal or beneficial use. Based on the flow rate of 12,400m3/day (case 4 and 5) the water treatment was estimated to be $8.02/m3 with the total capital cost of $135 million. It is unlikely that this high price for treatment and/or purification of water would be accepted or viable, therefore, deep-water injection would be the most likely management strategy for extracted water. As the Stuttgart Formation is regionally extensive and generally underpressured, it is the most likely disposal target for the site.

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Regarding regulations, it has been shown over the last few years that CCS faces obstacles in Germany. However, there are regulatory frameworks in place that allow brine injection to occur as part of other industrial activities. Zama

This is a hydrocarbon bearing structure that has been the site of acid gas injection for the simultaneous purpose of EOR, H2S disposal and CO2 storage in north western Alberta, Canada. It is a carbonate pinnacle reef structure consisting of dolomite and surrounded and overlain by a very tight anhydrite (Muskeg Formation) that acts as a caprock. The pinnacle modelled is one of 700 similar hydrocarbon bearing structures in the Zama oil field. The formation water quality is low and there are other existing local water resources, though there is the possibility of using extracted water for oil and gas production activities.

Four different cases of simultaneous acid gas injection and formation water extraction (Table 2) along with a base case (gas injection only) were tested in predictive simulation runs.

Table 2: Case Scenarios and Resulting Storage Capacities for the Zama



kg/day


m3/day

Boundary Conditions

Storage Capacity,

megatonnes

Base Case 1 Injector 310,680 N/A Closed 0.05 Case 1 1 Injector

1 Extractor 310,680 516 Closed 0.47

Case 2 1 Injector 1 Extractor

310,680 516 Closed 0.62

Case 2A 1 Injector 1 Extractor

310,680 429 Closed 0.68

Case 2B 1 Injector 1 Extractor

310,680 397 Closed 0.69

Case 3 1 Injector 1 Extractor

621,359 1144 Closed 0.49

Case 4 1 Injector 2 Extractors

621,359 572 Closed 0.60

In the base case, acid gas was injected without the extraction of formation water. Simulation results indicate that a total of 50 Mt of acid gas could be injected before reservoir pressure reaches the maximum allowable pressure limit of 22,753 kPa. Case 2A appears to be the optimum scenario. In this case, an average volumetric ratio of nearly 1:1 between extracted water and injected gas was observed while injecting acid gas at a constant rate (0.113 Mt/year) for more than 5.5 years into a closed system. It also resulted in 13 times higher storage capacity compared to base case. With over 700 pinnacle reef structures in the Zama sub basin, a careful selection of eight pinnacle structures similar to the ones modelled may provide almost 0.91 Mt a year of storage capacity and a steady stream of extracted, low quality water.

The three options for water disposal investigated were deep well injection into the overlying Slave Point Formation, treatment of Zama extracted water using a multiple-step membrane desalination

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approach such as one involving nanofiltration followed by reverse osmosis treatment and lastly using extracted water as a source of geothermal energy.

The total dissolved solids (TDS) of the waters range from 180,000 to 223,000 mg/L, with the lower value taken as the basis for evaluating treatment options. The flow rates used from the simulations were minimum, 3734 m3/day and maximum, 5261 m3/day. The capital costs for treating associated with the case studies at Zama ranged from $5.25 million to $60 million and the energy requirements 3.7 MW to 15.7 MW. It was therefore considered highly unlikely that treatment of the extracted water at Zama would be considered as a viable option. There is limited local population and remote location, so no effort was made to identify water demands for Zama. The most likely management option is disposal into the overlying Slave Point Formation, a practice that is currently being carried out by oil and gas operators in the area.

Given the provinces’ current regulatory structure, no issues were identified that would preclude injection of formation brines into the subsurface.

Gorgon

This is a planned future project for injection into a deep saline formation on Barrow Island off the west coast of Australia. The aim is to inject approximately 3.8 million tonnes a year through 8 injection wells with 4 production wells towards the west. Injection will be into the Dupuy Formation, a turbidite sequence at a depth of 2000m; the confining structure is a north–south trending double-plunging anticline. The formation water quality is of treatable quality, though there is low local demand.

Seven cases were simulated for the Gorgon test site using the planned eight injection wells and four extraction wells (Table 3).

Table 3: Case Scenarios and Resulting Storage Capacities for Gorgon



kg/day


m3/day

Injection Period, yrs

Storage Capacity,

megatonnes

Case 1 (base case)

8 injectors 10,661,700 * 25 97.3

Case 2 8 injectors 4 extractors

10,661,700 215,120,000 25 97.5

Case 3 8 injectors 10,661,700 * 50 195 Case 4 8 injectors

4 extractors 10,661,700 334,919,000 50 196


5,330,830 396,606,000 50 97.5


60,400,000 * 25 551


69,900,000 261,802,000 25 637

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Based on the simulation results, water extraction at the Gorgon site appears to be most beneficial for pressure maintenance and plume control. Utilisation of the planned extraction wells achieved significant pressure reductions. Early breakthrough remains an issue and could require injectors to be shut in and more wells brought online. Capacity gains through water extraction are possible at the Gorgon site, although the amount of injection required to make those gains far exceeds the injection planned for the site.

Water handling scenarios considered for Gorgon were reinjection of extracted water into a geological formation (for pressure management in the natural gas field), ocean discharge, use as source water for reverse osmosis systems installed on Barrow island (ultimately for water supply on Barrow Island) and use as supply of water for mainland Australia communities.

Reinjection is considered to be the most likely scenario, though ocean discharge would be a low cost alternative, as the salinity is similar to seawater, TDS of 23,234 mg/L, as long as there are no hydrocarbons or radioactive material. The only other issue is the potential environmental impact of high temperature water, though it may be possible to cool it first if there is an issue. Water treatment is a high cost option, but may be an alternative to desalination of seawater, which is currently planned. The main cost is transportation, which becomes much greater when considering supplying the mainland.

If properly planned and implemented, use of extracted water could be considered as a source of feedwater for reverse osmosis production of purified water for operations at the Barrow Island site. Minimal transportation and infrastructure are required beyond current seawater desalinization operations.

The current regulatory frameworks considered do not provide any serious constraints to brine disposal in Western Australia.

Teapot Dome

This is a demonstration site in Wyoming, situated next to a CO2-EOR site (salt Creek). It is a stacked sedimentary sequence in an elongated anticline. The formation water is of high quality and could have many uses as there are close by populated areas and agriculture; there may also be potential for geothermal production.

The Dakota/Lakota Formation was the primary target at Teapot Dome, which was examined through seven dynamic simulations which investigated a base case and various extracted water scenarios (Table 4).

Table 4: Case Scenarios and Resulting Storage Capacities for Teapot Dome

Scenario Well Configuration Gas Injection Rate/Well,

kg/day


m3/day

Storage Capacity,

megatonnes

Case 1 (base case)

1 injector 565,128 * 5.2

Case 2 2 injectors 836,848 * 7.6 Case 3 1 injector

1 extractor 1,212,810 1657 11.1

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Case 4 1 horiz. injector 1 horiz. extractor

2,090,498 6701 19.1

Case 5 2 horiz. injectors 1,953,238 * 17.8 Case 6

(surface dissolution)

1 horiz. injector 1 horiz. extractor

* 6346

0.56

Case 7 (surface

dissolution)


* 1599

0.15

Simulations also examined the potential for surface water saturation using extracted water followed by injection of the CO2 saturated stream. Due to the low salinity fluids at Teapot Dome, it was found that this technique could result in a capacity of 0.15 megatonnes over a 25-year period utilizing vertical wells (Case 7). This value was increased by utilizing horizontal wells, resulting in storage capacity of 0.56 megatonnes (Case 6). While these numbers are significantly less than free-phase injections, they are still potential candidates because of reductions in MVA cost and increased storage security. Using the single well pairs in Cases 6 and 7, it was determined that in order to reach an injection rate of one megatonne per year using surface dissolution, that approximately 170 wells (85 injection–extraction well pairs) or approximately 44 wells (22 injection–extraction well pairs) would be required using vertical or horizontal wells, respectively. Because of the large number of wells required, it is unlikely that surface dissolution is a viable option at the Teapot Dome site.

Simulations at the Teapot Dome site indicate that water extraction can have an impact on carbon storage capacity, reservoir pressure, and plume management. Utilisation of an injection extraction well pair resulted in increased storage capacity over the use of a single or pair of injection wells. Water extraction also strongly influenced reservoir pressures and plume migration. Although the overall size of the plume was not decreased with these simulations, eastward migration of the plume was reduced over the base case. The large plume was also thinner and exerted less pressure on the overlying cap rock. It is expected that extraction could be designed to reduce overall plume size at this site as well.

Water management options considered for Teapot Dome included reinjection into a geological formation and desalination for use as a potable or agricultural water supply. Reinjection could take place into several overlying options at a minimal cost.

The TDS of the extracted water would be 9263mg/L and would contain some hydrocarbons, though this is discounted for cost calculations. Simulations of reverse osmosis based water treatment were performed using the DEEP 4.0 modelling programme from the IAEA. The purified water yield from the 10,000 mg/L TDS brine was estimated to be 83% at a feed pressure of 69 bar and a feed temperature of 40°C. The purified water was calculated to have a salinity of 260 mg/L with the product brine having a salinity of 57,600 mg/L.

The range of water price ranges from $0.97/m3 for the lowest extracted water flow rate(2600 m3/day) at the 1 million tonnes/year of CO2 injection to $0.74/m3 for the highest extracted water flow rate (59,600 m3/day) for the 8 million tonnes/year of CO2 injection.

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This was compared to local water rates, and the cost of treating the extracted water (assuming no cost for removal of hydrocarbons) is less than the standard base rate of water in this area but greater than the rate charged per unit of water above the monthly minimum.

Considering regulations, while Wyoming does not currently have primacy to regulate carbon storage through the Class VI well program, the state does have primacy to regulate Class II – Oil and Gas-Related Injection Wells. This includes disposal wells. In order to obtain a permit for brine disposal via underground injection certain conditions must be met. An injection application must include maps of existing and proposed wells, information on the injection formation, casing and testing program, injection water source and makeup, operating parameters, and an analysis of the mechanical integrity of wells within the radius of investigation. Public notice is also required.

Expert Review Comments

Expert comments were received from 7 reviewers, representing industry and academia. The overall response was positive and highlighted a significant contribution to this area of storage research. The expert reviews were summarised and EERC are currently making changes to the report; with the final report due in June. The expert reviews were summarised as below:

1. The structure of the report is good overall with the bulk of in-depth modelling information in the appendices and the main report concise and very readable. However, there could be some improvements, by having a bit more information in the report, such a simulation methods used and some of the modelling analysis and assumptions.

2. The executive summary could be clearer on the aims of the study

a. Include major assumptions

b. Include the current state of the 4 case study sites, e.g. no current brine extraction, demo scale etc.

c. Include more costing info, possibly cost/tonne

3. There needs to be more consistency with units, e.g. use tonnes throughout

4. Percentages of increased capacity are confusing and need to much clearer (this is noted by most of the reviewers)

5. Figures need to be placed in the appropriate sections – even thought the figures are in order it is not clear straight away which case study they refer to.

6. There are some inconsistencies regarding the Ketzin case study which will need to be corrected.

Conclusions

Extracting water from a CO2 storage reservoir was observed to have variable effects based on the specific nature of reservoir rock and reservoir boundary conditions, as well as operational factors such as injection/extraction management and placement of wells. While the assumption of achieving a 1:1 ratio of injected CO2 to extracted water was generally appropriate, in some situations, the volume of water which must be removed from the reservoir was much higher in order to perform the desired pressure or plume management tasks. The most influential results were found in the closed reservoir

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test performed at Zama. In this situation, extracted volumes were approximately equal to injected volumes. In other situations, it was found that the water extraction rate may be as high as four times higher than the volume of injected CO2.

Generally, the simulations conducted for this project illustrated that water extraction scenarios may well be capable of increasing storage capacity by more than double. Site-specific factors affecting local injectivity resulted in the Teapot Dome site gaining more storage from an extraction/injection well pair and the Ketzin site storing more CO2 with a pair of injection wells. Furthermore, optimizing simulations to achieve pressure maintenance or plume management generally resulted in decreased reservoir storage capacity with a significant increase in the volume of extracted water.

It is highly unlikely that any extracted water would be put to beneficial use for CO2 storage locations that are offshore or in coastal areas. The potential cost savings for use of an extracted water in place of seawater for desalination appears to be too small, even for a salinity as low as 10,000 mg/L TDS, to justify use of the extracted in place of seawater. Use of the extracted water would likely place greater uncertainties on supply, as ocean sources would be more reliable and longer-term than CO2 storage projects.

In higher TDS locations, it is also unlikely that extracted water would be purified. While technologies exist to treat brines with the range of dissolved solids, the cost associated with treatment and implementation would likely be too high to justify. Treatment and beneficial use may be feasible under certain conditions: likely a combination of low-to-moderate extracted water quality, availability of inexpensive energy and sufficient local water demand. Of the case study sites, the best candidate for treatment and use of extracted water was the Teapot Dome site, where estimated treatment costs were comparable to that of local water supplies.

Surface dissolution involving the extraction of reservoir fluid, saturation, and subsequent reinjection is unlikely to be a viable option in most situations as the capacity of produced fluids to dissolve and carry CO2 is too low. It is unlikely that this scenario will ever be able to compete with direct injection for storage of commercial-scale volumes of CO2.

Existing regulations were not found that impose a barrier to the development of water extraction as part of reservoir management operations nor for the development of procuring additional water resources, provided the water quality is fit for the intended use. If extracted water is treated and utilised, effluent will be under regulations to adhere to wastewater treatment and handling.

Despite high costs and shortcomings encountered with extracting reservoir fluids for increasing reservoir capacity and/or management, it is important to consider these options for any specific storage site in an effort to:

• Optimise the injection scenario. • Potentially alleviate costs through beneficial use. • Reduce risk and MVA costs and increase reservoir efficiency by controlling plume migration. • Manage pressure and injectivity.

Recommendations

There is yet to be any large scale demonstration of this topic and most information is currently through modelling studies. It is recommended that IEAGHG continue to follow this topic and any

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updates, through future storage network meetings, namely the modelling network and by the study programme.

A future review of this topic would be useful as data is generated by future large scale demonstration projects.

References

IEAGHG, 2009, Development of Storage Coefficients for Carbon Dioxide Storage in Deep Saline Formations

IEAGHG, 2010, Pressure and Brine Displacement issues for Deep Saline Formation CO2 Storage

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PRIORITISATION OF NEW STUDIES

Prioritisation of new studies 14 proposals for new studies were sent to members and sponsors for voting. These consisted of:

• 4 proposals re-submitted from the previous round of voting (3 from members and 1 from the Programme Team)

• 10 new proposals, 7 from members and 3 from the Programme Team. Members were asked to vote for up to five of the proposals and indicate their first choice. Votes were received from 27 of the 46 members and sponsors, representing only a 58% return of votes. The table shows the number of single votes received, the number of ‘first choices’, and the weighted number of votes, in which the first choice vote is assumed to be equivalent to 2 votes. Proposal number

Title Normal Votes

First choices

Weighted votes

Proposals selected for presentation

41-05 Assessment of costs of capture at baseline coal power plants 13 4 21

41-10 CO2 storage efficiency in aquifers 12 4 20

41-02 Evaluation of reclaimer waste disposal for CO2 Post Combustion Capture 9 5 19

41-09 Criteria of fault geomechanical stability during a pressure build-up 8 4 16

41-07 Environmental Impact Statements – Review of Gaps 13 1 15

41-13 Review of the status of non CO2 GHG emissions and opportunities for future work 12 1 14

Other proposals

41-03 Evaluation of CO2 Adsorption Process in Natural Gas Production 8 2 12

41-11 CO2 storage wells/site abandonment 10 1 12

41-08 Feasibility and costs of CO2 storage in geological strata with relatively low permeability and porosity

4 2 8

41-04 CCS for energy-from-waste plants 5 1 7

41-06 Optimization of Water Usage/Treatment in Oxy-Coal Fired Power Plant 4 1 6

41-01 Techno-Economic Evaluation of the Potential CO2 Capture Application in Pulp and Paper Industry

5 0 5

41-12 Local compensation for CO2 storage – an overview 4 0 4

41-14 Agro peat production concept 0 1 2

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After reviewing the outstanding studies waiting tendering and our current study commitments we will be able to take on up to 4 new studies depending on the costs of studies selected. It is proposed that a fifth study could be completed in house. The outline proposals for the 6 studies which received the most votes (over 14 weighted votes) have been included here for members to consider. Following the presentations of the outline study specifications, the Committee will be asked to decide:

i) Should the Programme proceed with these studies? ii) Do the outline specifications of the studies properly describe the work

required? iii) Which of the proposals not selected in this round of voting should be re-

submitted in the next round?

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ASSESSMENT OF COSTS OF CAPTURE AT BASELINE COAL POWER PLANTS

The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on the scope of the proposed study will be given at the ExCo meeting. After the presentation members will be invited to consider whether they wish to proceed with this study. Proposal It is proposed that a study should be carried out.

RESOURCES REQUIRED Financial Project management Greater than average Average

The committee is requested to i) Approve proceeding with this study. ii) Suggest possible contractors iii) Suggest possible expert reviewers for the completed study

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Reference number 41-05 Meeting 41thExCo, May 2012, Bergen Title Assessment of costs of capture at baseline coal power plants Subject area Capture of CO2 Originator IEAGHG Description At the 40th ExCo meeting it was agreed that IEAGHG should put forward a

proposal to undertake a new study on the performance and costs of baseline coal-fired power plants with and without CO2 capture. IEAGHG has undertaken such studies in the past but those studies are now considered to be out of date. This new study will be necessary as a baseline for IEAGHG’s future studies on capture, as described below. The study will cover the following leading plant options:

• Ultra-supercritical pulverised coal plant with post combustion capture based on a high efficiency solvent

• Ultra-supercritical pulverised coal plant using oxy-combustion • Integrated gasification combined cycle plant with pre-combustion

solvent scrubbing To minimise the number of cases to be assessed in this study, recent CCS baseline studies published by other organisations will be reviewed to help to identify the optimum plant configurations. Any significant technology improvements that have been made since those studies were undertaken will be identified and taken into account. A reference supercritical pulverised coal plant without capture will be assessed as a reference case. Ideally an IGCC plant without capture would also be assessed but as it is expected that significant numbers of IGCC plants without capture are unlikely to be built, this will be an optional extra case that will only be included in the study if the cost of doing so is low. The study will assess the performance, capital and operating costs of the plants and where possible equipment lists and plant layout diagrams will also be provided. The study will focus on the type of large, possibly multi-unit, power plants which are expected to account for most of the coal fired power plants that will be built in future. The study will be based on IEAGHG’s standard European plant location and coal analysis. The contractor could also assess step-off cases of plants in other countries using other coals but this would increase the cost of what is already expected to be a greater than average cost study. It is therefore proposed that if any IEAGHG members would like to include an assessment of plants based in their own countries they may wish to fund or co-fund this work separately.

Resources required

Financial: Greater than average Management: Average

Links with other on-going or proposed studies

The study will provide baseline plant data for future studies by IEAGHG on other aspects of capture such as next generation capture technologies, operating flexibility and CCS in industry.

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CO2 STORAGE EFFICIENCY IN AQUIFERS


RESOURCES REQUIRED Financial Project management Average Average


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Reference number 41-10 Meeting 41st ExCo, May 2012, Bergen Title CO2 storage efficiency in aquifers Subject area Storage Originator Total Description The aim of this study is to build on the work carried out on the previous IEAGHG

report on the development of storage coefficients for carbon dioxide storage in deep saline formations (DSF) (2009/13). In this report storage efficiencies were calculated from local flow models, giving storage efficiency factors of between 1 and 3% at the formation level. The previous study considered only static storage capacity and more recent studies looking at dynamic capacity, i.e. how capacity is affected by factors such as the injection rate, injection pattern, timing of injection and plume development, show that a wide range of potential capacities exist for each storage site. This study would consist of a literature review to summarise work to date on storage capacity estimation and efficiency factors, followed by a modelling exercise to investigate the applicability of storage coefficients. The following approach from the modelling exercise could be followed:

• Select DSFs where key geological maps are publicly available or can be established (as top of formation, thickness, net to gross, porosity, permeability, salinity, pressure and temperature). The aquifer should be a reference in terms of storage, as Mt Simon Sandstone in Illinois or elsewhere USA for example

• Compute the effective storage capacity using the storage coefficients recommended by the 2009/13 report (or more recent follow up work)

• Model storage capacity by locating injectors in the basin and modelling the injection with realistic conditions (use a maximum pressure increase from a regional fracture pressure gradient, inject in a ~100 year period for example; define CO2 storage points with significant CO2 injection rates corresponding to industrial projects)

• Some key scenarios should be defined as: CO2 injection only vs CO2 injection and water production for pressure relief; open vs close boundary conditions; water flow through cap rock

• The results would be an optimized well pattern (location of injection sites + number of injectors per site) and the associated cumulative CO2 injection

• Compare the theoretical storage capacity and the dynamically modelled cumulative CO2 injection

Note that this study does not require high resolution data. Basin scale data (single layer approach for example) would be enough.

Resources required

Financial: Average Management: Average


Development of Storage Coefficients for Carbon Dioxide Storage in Deep Saline Formations (2009/13) Extraction of Formation Waters during CO2 Storage (ongoing)

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EVALUATION OF RECLAIMER WASTE DISPOSAL FOR CO2 POST COMBUSTION

CAPTURE The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on the scope of the proposed study will be given at the ExCo meeting. After the presentation members will be invited to consider whether they wish to proceed with this study. Proposal It is proposed that a study should be carried out.



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Reference number 41-02 Meeting 41thExCo, May 2012, Bergen Title Evaluation of reclaimer waste disposal for CO2 Post Combustion Capture Subject area Capture of CO2 Originator IEAGHG Description Post combustion capture using aqueous amine based solvents is considered to

be the most widely used technology in large scale CCS demonstration plants. Due to the presence of other gas species such as SOx, NOx, O2 and halogen compounds in the flue gas, amine degradation and formation of heat stable salts (HSS) will be expected. Typically these salts reduce solvent CO2 absorption properties and are corrosive in nature. Therefore reclaiming is required to have smooth operation of capture plant. Generally, a slip stream of amine is sent to the reclaimer, where part of solvent is reclaimed mostly by thermal distillation process and send back to the CO2 capture unit. The waste generated from the reclaimer is predominantly consisting of heat stable salts. This waste is periodically discharged to prevent any accumulation of the salts in the reclaimer. The generated reclaimer waste per tonne of CO2 captured using MEA is reported to be around 3.94kg/t CO2 and 3.47kg/t CO2 for Coal and NGCC CO2 capture case respectively [1]. Landfilling and incineration have been the traditional disposal method. In the longer term, landfilling of toxic waste will be severely restricted in many regions. Treatment of reclaimer waste can be done by traditional wastewater treatments techniques like aerobic treatment, anaerobic digestion and compositing. These techniques are more effective for dilute amine waste streams but become less efficient with concentrated waste streams like distillation bottom wastes. Amine reclaimer waste can also form problem in waste water treatment due to its low C/N element ratio. Therefore, the most appropriate treatment of the reclaimer waste is yet to be determined. Following are the scope of this study: Identify composition of reclaimer waste for post combustion CO2 capture

process for commercial solvents like MEA, Chilled ammonia/ Aqueous ammonia, Carbonate solutions (Potassium and Sodium Carbonate).

Identify toxicity level of the reclaimer waste. Identify the options to minimize reclaimer waste. Evaluating the cost benefit of disposing the reclaimer waste by

reintroducing to a boiler (i.e. co-firing and using it as a NOx reduction reagent) as compared to conventional incineration process.

Resources required



Review of gaps in Environmental Impact studies, this subject was identified as a gap in discussions between IEAGHG and The Scottish Environmental Protection Agency.

[1]IEAGHG draft report done by TNO, Emissions of substances other than CO2 from Power plants with CCS.

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CRITERIA OF FAULT GEOMECHANICAL STABILITY DURING A PRESSURE BUILD-

UP The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on the scope of the proposed study will be given at the ExCo meeting. After the presentation members will be invited to consider whether they wish to proceed with this study. Proposal It is proposed that a study should be carried out.



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Reference number 41-09 Meeting 41thExCo, May 2012, Bergen Title Criteria of fault geomechanical stability during a pressure build-up Subject area Storage Originator Total Description For any potential CO2 storage site, it is likely that there will be pre-existing

faults in the overburden. Injection of CO2 into the storage formation will cause an increase in pressure in surrounding layers, affecting the stress and strain fields and can cause existing faults to be reactivated. This is turn can open up potential leakage pathways, making it important to be able to predict at what point this may occur. Fault reactivation potential can be estimated using the fault analysis seal technology, which evaluates the increase in pore pressure required to reduce the effective stress to the point that fault reactivation will theoretically occur. This method allows integration of the in-situ stress field, strength of the fault and structural geometry in order to generate maps of the fault reactivation potential at different points on the fault surface. This and other methodologies are probably best as a first pass approximation, due to the uncertainty of criteria, such as the friction coefficient and cohesion. Fault reactivation analysis often deal with large uncertainties and in the case of fault reactivation risk, the key uncertainties are the orientation and magnitude of the in-situ principal stresses, pore pressure, fault architecture, and the geomechanical properties of the fault. In various methods the intermediate principal stress is ignored and the understanding of the role of the small structures forming a potential permeable network in the fault zone, such as foliation, cleavage, or fractures is still limited. Recent geomechanical studies for CO2 geological storage have focused on Initializing the stresses in the overburden based on all available data, modelling the impact of pressure build up on stresses in the storage formations, the cap rock and the overburden in general. A critical aspect is to establish, in some predictive way, the acceptable overpressure before a fault reactivation. This primarily relates to defining the cohesion and friction angle of a given fault. These parameters will vary along the fault, both vertically and laterally. This study would summarise how such geomechanical parameters for faults are established and analyse the effectiveness of the methodologies used.

Resources required



Caprock systems for CO2 storage (2011/01)

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ENVIRONMENTAL IMPACT STATEMENTS – REVIEW OF GAPS




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Reference number 41-07 Meeting 41thExCo, May 2012, Bergen Title Environmental Impact Statements – Review of Gaps Subject area Storage Originator IEAGHG Description This study will identify information gaps and needs in environmental impact

statements for CO2 geological storage projects. It’s primary activity will be to identify and then review the Environmental Impact Assessments / Statements (EIAs / EISs) that have been completed globally, noting differences and similarities with respect to local and national regulations’ requirements The work will build upon the IEAGHG Technical Study 2007/1 ‘Environmental Assessment for CCS’. This study, which examined EIAs for CCS, identified the following information gaps: • Modelling of CO2 releases • Effects on marine environment • Environmental criteria and standards • On-shore environmental effects of CO2 exposure. Effects on humans well

known, but gaps exist for plants, animals and ecosystems. • Effects of impurities • Monitoring of changes in ecosystems and indicator species. This proposed study will examine whether and how these gaps have been addressed in subsequent completed EIA’s, and whether new gaps have been identified, providing recommendations on how to address any such information gaps The study will also consider implementation and management of EIAs by competent authorities, and integration within project specific Risk Assessments.

Resources required



In re-assessing the gaps, use will be made of existing literature, especially the relevant IEAGHG work. The study will build on the IEAGHG Report 2007/3‘Potential Impacts of Leaks from Onshore CO2 Storage on Terrestrial Ecosystems’, and will look at the results of and work presented in the two IEAGHG workshops on environmental impacts in 2008 and especially the 2010 workshop which focussed on information needs for EIAs (IEAGHG 2008/15 and 2011/03). The study will also link with the EU FR7 RISCS, through IEAGHG’s role on the advisory body. The study should aim to assist Environmental Regulators to help close gaps in information or direct them to where information exists, that should assist environmental permitting activities and thus assist the implementation of CCS at the demonstration scale.

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A REVIEW OF THE STATUS OF NON CO2 GHG EMISSIONS AND OPPORTUNITIES

FOR FUTURE WORK The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on the scope of the proposed study will be given at the ExCo meeting. After the presentation members will be invited to consider whether they wish to proceed with this study. Proposal It is proposed that a study should be carried out.

RESOURCES REQUIRED Financial Project management Below Average Average


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Reference number 41-13 Meeting 41st ExCo, May 2012, Bergen Title A review of the status of non CO2 GHG emissions and opportunities for future

work Subject area Novel technologies and Non-CO2 GHG’s Originator IEAGHG Description In Phase 4 IEAGHG undertook a series of studies on the Non-Co2 GHG

emissions (notably, CH4, N2O, SF6,and PFC’s) from fossil fuel use in the power and major industrial sectors like aluminium/magnesium smelting etc., The study series indicated that in many sectors there were significant opportunities for near zero and low costs mitigation options that could be adopted to reduce emissions such as reduced transportation emissions from natural gas pipelines, reduced flaring of associated gas and inert anodes for aluminium smelting for example. The results from IEAGHG’s study work were utilised, amongst other data in the EMF21 modelling exercise giving global cost/mitigation data across these sectors. The aim of this review is to update the summary of the work completed by IEAGHG in Phase 4. The objective’s would be:

• Review the current sources of Non-Co2 gases and update their emissions data.

• Look at the trends in Non-Co2 GHG emissions over the years from our study to present date and assess which mitigation options have been successfully deployed.

• Review why some measures have not been introduced and assess why; issues could be costs lack of regulatory development

The review would inform members of the impact of Non-Co2 GHG emissions and put them in perspective with CO2 emission targets. One question this review could raise is that can early opportunity reductions in the Non-Co2 GHG area help to offset CO2 emissions build up in the near term from energy use. The review would also aim to look at the organisations active in these areas, such as the Methane to Markets Programme in the USA, a body similar to the CSLF. This would enable to review to consider if there are any opportunities for further work by IEAGHG on such topics that could assist deployment or address barriers to deployment. The review would therefore assist in IEAGHG’s future strategic planning activities.

Resources required

Financial: Below average Management: Average


Shale gas emissions review

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STUDIES TO BE RESUBMITTED FOR VOTING

Members are invited to suggest which studies should be considered again in future voting rounds.

NOTES

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GHG/12/30


UPDATE ON GCCSI ACTIVITIES

As part of the contract with GCCSI, IEAGHG is required to supply GCCSI with a status report and financial statement twice a year. The fifth status report was prepared in February 2012. Significant events over this period are the publishing of the reports of two GCCSI-funded studies on Effects of Impurities and on the Global Storage Gap Analysis, both reports made available on the GCCSI website, as well as being widely disseminated by presentations. Organisation is well underway for GHGT-11, and the organization of the third meeting of the Social Research Network has started. The What Have We Learnt from Large-scale Operational Projects (Activity no.8) has completed and is published, and the scope of work for Phase 2 will be discussed and agreed with GCCSI. Two activities were requested to be put on hold (updates to Projects Database and to Emissions Database) by the Institute, although IEAGHG is funding lower level activity in these areas due to pressing need for them. The Institute also requested that Activity on Key messages for stakeholders be cancelled. At IEAGHG members request this is proceeding funded by IEAGHG. In addition to these activities Tim Dixon was seconded to GCCSI part time for to assist them in building up their regulatory capabilities. This is a separate contract with GGCSI. This contract has been extended twice to include the UNFCCC meetings, the second time for a further 12 months to include the COP-17 meeting at Durban, at a reduced part-time rate (12:5%). A report of work funded by this contract is included in paper GHG/12/13. This contract has now ended in January 2012. Also under a separate contract, the General Manager is a member of GCCSI’s Technical Advisory Committee. This contract has been renewed.

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FEEDBACK MEMBERS ACTIVITIES

NOTES

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DATE OF NEXT MEETING

The next scheduled meeting will be the 42nd ExCo meeting and will be hosted by RITE, Japan 15th-16th October 2012 immediately preceding GHGT-11, 18th-22nd November. The 43rd ExCo meeting will be held in Regina, Canada Spring 2013. Offers are invited to host the Autumn 2013 and Spring 2014 ExCo with the 46th ExCo being held in Texas, USA prior to GHGT-12.

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AOB

NOTES

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