iea greenhouse gas r&d programme exco papers_email.pdf · 43rd exco meeting, 8th - 9th may...

43rd ExCo MEETING, 8th - 9th MAY 2012, REGINA, CANADA

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 42nd meeting………………………………………………………………………………………………… Corrections to minutes……………………………………………………………………………………………………

3 19

Matters arising from the 42nd meeting - list of actions and status …………………………………. 20 Progress Report – IEAGHG Programme…………………………………………………………………………. 21 Membership Issues/New Members……………………………………………………………………………… 33 Financial Update 2012/13……………………………………………………………………………………………… 34 Financial Proposal 2013/14……………………………………………………………………………………………. 35 Proposed changes to IA and Annex 1 changes ……………………………………………………………… 36 Discussion Papers

COP19 Developments……………………………………..……………………………………………………. ISO Progress………………………………………………………………………………………………………….. Shale Gas Update………………………………………………………………………………………………….. CCS Costs Network…………………………………………………………………………………………………

37 40 42 48

Completed/On-going Activities CO2RISKMAN………………………….…...……………………………………..………………………………. 50 Update on Monitoring Tool………………………………………………………………………………….. 56 Developments on Incorporating Future Technological Changes in Existing Capture Plants……………………………………………………………………………………………………………………..

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CO2 Migration Mitigation Options.…..…………………………………………………………………… 64 Non CO2 Gases – A review……………………………………..……………………………………………… 75 Dehydration of CO2………………………………………………………………………………………………. 76 Biomethane and CCS……………………………………………………………………………………………. 90 Summer School 2015/16……………………………………………………………………………..……….. 96 Conference Update…………………..…………………………………………………………………………. 98

Study Prioritisation………………………………………………………………………………………………………… 99 Evaluation for Various Process Control Strategy for Normal and Flexible Operation of Post Combustion Capture ………………..................................................................

101

Energy Storage and CCS……………………………………………………………….………………………. 103 Economics of Well Stimulation with CO2 for Shale Oil/Gas Production……...…………. 105 Oxy Gas Turbine Power Plants….…………………………………………………...…………………….. 107 Public Perception of CO2 Pipelines…………………………………………………….…………….….. 109 Evaluation of CO2 Adsorption Process in Natural Gas………….……………………………... 111 Techno-Economic Evaluation of the Protential CO2 Capture Application in Pulp and Paper………………………………………………………………………………………………………………………

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Studies to be reconsidered for future voting rounds/Members Ideas for Future Studies.. 115 Update on GCCSI Programme………………………………………………………………………………………… 116 Feedback on GCCSI Activities…………………………………………………………………………………………. 120 Feedback on IEA Activities……………………………………………………………………………………………… 121 Interactions with WPFF and other IEA’s…………………………………………………………………………. 122 Feedback on Members Activities………………………………………………………………………………….. 123 Date of Next Meeting……………………………………………………………………………………………………… 124 Any other business………………………………………………………………………………………………………… 125

GHG/13/01

IEA GREENHOUSE GAS R&D PROGRAMME 43rd 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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Regina, Canada, 8th-9th May 2013

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/13/01 3) Adoption of agenda GHG/13/02 4) Minutes of 42nd meeting

Corrections to minutes GHG/13/03 GHG/13/04

5) Matters arising from the 42nd meeting - list of actions and status GHG/13/05 6) Progress Report – IEAGHG Programme incl. GHG/13/06 7) Membership Issues/New Members GHG/13/07 8) 8.1)

Financial Update 2012/13 Budget proposal 2013/14

GHG/13/08 GHG/13/09

9) Proposed changes to IA and Annex 1 Changes GHG/13/10 10) 10.1) 10.2) 10.3) 10.4)

Discussion Papers COP19 Developments ISO Progress Shale Gas Update CCS Costs Network

GHG/13/11 GHG/13/12 GHG/13/13 GHG/13/14

11) Completed /On-Going Activities 11.1) CO2 RISKMAN GHG/13/15 11.2) Update on Monitoring Tool GHG/13/16 11.3) Developments on I ncorporating Future Technological change in

existing capture plants GHG/13/17

11.4) CO2 Migration Mitigation Options GHG/13/18 11.5) Non CO2 Gases – A review GHG/13/19 11.6) Dehydration of CO2 GHG/13/20 11.7) Bio Methane and CCS GHG/13/21 11.8) Summer School 2015/16 GHG/13/22 11.9) Conference Update GHG/13/23 ITEM SECOND DAY (08.30 to 17.00) Paper 12) Study Prioritisation GHG/13/24 12.1) 43-03 Evaluation for Various Process Control Strategy for Normal and

Flexible Operation of Post Combustion Capture GHG/13/25

12.2) 43-02 Energy Storage and CCS GHG/13/26 12.3) 43-12 Economics of well stimulation with CO2 for shale oil / gas

production GHG/13/27

12.4) 43-06 Oxy Gas Turbine Power Plants GHG/13/28 12.5) 43-11 Public Perception of CO2 Pipelines GHG/13/29 12.6) 43-08 Evaluation of CO2 Adsorption Process in Natural Gas GHG/13/30 12.7) 43-10 Techno-Economic Evaluation of the Potential CO2 Capture

Application in Pulp and Paper GHG/13/31

13) Studies to be reconsidered for future voting No Paper 14) Update on GCCSI Programme GHG/13/32 15) Feedback on GCCSI activities No Paper 16) Feedback on IEA CCS unit/IEA activities No Paper 17) Interactions with WPFF and other IA’s GHG/13/33 18) Feedback on Members Activities No Papers 19) DONM Presentation on 44th meeting – Stockholm, Sweden GHG/13/34 20) AOB 21) Close of Meeting

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IEA GREENHOUSE GAS R&D PROGRAMME 42nd EXECUTIVE COMMITTEE MEETING

LIST OF ATTENDEES

Members Dr Paul Feron CSIRO Australia Prof John Kaldi CSIRO Australia Prof Kelly Thambimuthu (Chair) CO2CRC Australia Dr Eddie Chui CanmetENERGY Canada Dr Malcolm Wilson PTRC Canada Mr Tim Zulkoski SaskPower Canada Mr Peter Petrov EU Mr Eemeli Tsupari VTT Finland Dr Isabelle Czernichowski-Lauriol BRGM France Mr Jürgen-Friedrich Hake FZJ Germany Dr Ziqiu Xue RITE Japan Mr Ryozo Tanaka RITE Japan Mr Daan Jansen ECN The Netherlands Dr Klaus Schöffel Gassnova Norway Mrs Åse Slagtern Forskningrådet Norway Mr Brendan Beck 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 Mr Gunter Siddiqi Swiss Federal office of Energy Switzerland Dr Suk Yee Lam OCCS DECC UK Dr Jay Braitsch US DOE USA Mr Philip Sharman ALSTOM Mr Kevin McCauley Babcock & Wilcox Mr David Jones BG Group Mr Mark Crombie BP Mr Mario Graziadio ENEL Dr Sven Unterberger EnBW Kraftweke AG Dr Tim Hill E.ON Mr Richard Rhudy EPRI Mr Krishnaswarmy Sampath ExxonMobil Mr Steven Whittaker GCCSI Dr Jose Miguel Gonzalez Santalo IIE Mr Fumihiro Ito JGC Mr Tsukasa Kumagai JGC Mr Paulo Negrais Carneiro Seabra Petrobras Dr Reinhold Elsen RWE Power AG Mr Bill Spence Shell Dr Helle Brit Mostad Statoil Mr Dominique Copin Total

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IEA EPL Dr John Topper Mr John Gale IEAGHG Team Mr Tim Dixon IEAGHG Team Miss Samantha Neades IEAGHG Team Mrs Sian Twinning IEAGHG Team Dr Stanley Santos IEAGHG Team Mr John Davison IEAGHG Team Miss Ludmilla Basava-Reddi IEAGHG Team Dr Prachi Singh IEAGHG Team Dr Jasmin Kemper IEAGHG Team Ms Deborah Adams IEACCC Team

Observers Mr Juho Lipponen IEA France Dr Hirofumi Kikkawa Babcock-Hitachi Japan Mr Masanori Abe Japan CCS Japan Dr Mickiaki Harada JCOAL Japan Dr Yashuhiro Yamauchi NEDO Japan Dr Yasuko Okuyama AIST Japan Ms Kimiko Nakanishi RITE Japan Dr Ryo Kubo Toshiba Japan Dr Cheol Huh Korean Ocean Research and

Development Korea

Dr Jae-Goo Shim KEPRI Korea Mr Saif Al Naimi Qatar Petroleum

Apologies Mr Arthur Lee Chevron USA Dr Tony Booer Schlumberger UK Dr John Carras CSIRO Australia Dr Theodor Zillner Austria Mr Gerry Hesslemann Doosan Babcock Dr Ilkka Savolainen VTT Finland Dr Nathalie Tybaud Ademe France

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IEA GREENHOUSE GAS R & D PROGRAMME 42ND EXECUTIVE COMMITTEE MEETING

1. WELCOME AND INTRODUCTIONS On behalf of the Executive Committee (ExCo), Kelly Thambimuthu (Chair) opened the meeting and welcomed all new members, new member representatives and observers attending ExCo for the first time. Several apologies were received prior to the meeting (Arthur Lee, Tony Booer, Theodore Zilner, Gerry Hesslemann, Ilkka Savolainen and Natalie Thybaud). Ziqiu Xue (RITE, Japan) gave a short introduction, thanks and welcomed all to Kyoto. 2. MOTION ON PROCEDURE The motion for procedure at the meeting (document GHG/12/32) was adopted. 3. ADOPTION OF AGENDA Document GHG/12/33 refers. Members adopted the agenda for the meeting. 4. MINUTES OF PREVIOUS MEETING & CORRECTIONS TO MINUTES Documents GHG/12/34 and GHG/12/35 refer. Three Members requested a number of minor typographical changes or textual changes to sentences, which have been made. Members approved the minutes of the 41st ExCo meeting. 5. MATTERS ARISING FROM THE 41ST MEETING – LIST OF ACTIONS & STATUS Document GHG/12/36 refers. John Gale addressed this item, noting that the actions have been completed. Action 11 will be discussed later on at this meeting and Action 13 will be dealt with at GHGT-11 – ExCo Members are welcome to attend the meeting at GHGT and comment. 6. ELECTION OF VICE CHAIRMAN Document GHG/12/37 refers. John Topper proposed reverting to the old system of having two vice chairs rather than one and noted that the current Vice-Chair (Sven-Olov Ericson) is willing to stand again. Klaus Schoffel (Norway) proposed this, with Eemeli Tsupari (Finland) seconding. All agreed and John Topper hereby declared Sven-Olov Ericson elected as Vice-Chair. For the second Vice-Chair, Eddy Chui (Canada) proposed Gunter Siddiqi (Switzerland), with Brendan Beck (South Africa) seconding. All agreed and John Topper declared Gunter duly elected as Vice-Chair. Peter Petrov (EU) also noted his support of Gunter for Vice-Chair. 7. PROGRESS REPORT – IEAGHG PROGRAMME Document GHG/12/38 refers. John Gale presented this to Members and invited John Topper to begin with a matter of significance to the Programme. Dr Topper has had the dual roles of being director of the operating agent for both IEAGHG and IEA CCC but in the latter case with all the same day to day responsibilities for IEA CCC as John Gale has as General Manager of IEAGHG. He will be stepping down next year, to a ‘halftime role’. In spring 2013, a new General Manager will be advertised (and subsequently appointed) for the IEA CCC and in 2014 the situation will be reviewed. Until then there would be no impact or change that might affect IEAGHG as the reduction on working hours would only affect IEA CCC. John Gale noted that there has been one significant staff issue recently, with one member of staff off work for 6 – 8 weeks. John expressed his thanks to staff who have taken up this workload. In terms of dissemination activities, John explained that the Greenhouse News has a distribution of approximately 6500 copies – both paper and electronic. The production of the paper version has been reduced over recent years (currently at ~600 copies) and costs around £16-18,000/annum, so is becoming less cost effective and IEAGHG question the continuation of this. There were no comments from Members, so Kelly Thambimuthu told John to do what’s necessary from a cost perspective.

ACTION 1: General Manager

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It has been reported that the impact factor for the IJGGC publication was 5.11 in 2011, so is now in the Top 5 of Elsevier-published journals. This is adding pressure on editors, so an additional editor has been brought in to make a total of 6 associate editors. IEAGHG are pleased with how well the Information Papers (IPs) are being received. Tim Hill (E.ON) noted these have proved very timely, useful and he suspects that the volume of these will reduce in time (as many have been coming out recently). Jay Braitsch (USA) commented that there are so many things being published, the IPs do a great job of getting out quickly and straightening out the information. As of Wednesday 14th November, there were 1259 registered for GHGT-11, with registration closing on the 16th. John expressed his thanks to the Japanese sponsors and particularly to RITE who have worked extremely hard to organise the conference. GHGT-12 will be held in Austin, Texas, from the 5th to 9th October (2014). The MoU has been signed for this. The UK have withdrawn their offer to host GHGT-13, currently Norway and Switzerland are in the tender process. The Programme has regular interaction with the IEA CCS Unit and will give an update on IEAGHG activities at an upcoming IEA Working Party on Fossil Fuels (WPFF) meeting in December (2012). The General Manager is also presenting at an IEA NEET meeting in China later this year and Neil Wildgust represented IEAGHG at the IEA EOR IA meeting in Canada. Philip Sharman (Alstom) asked for clarification of ‘IEA NEET’ and John Gale noted that it is a network looking at technology transfer in developing countries on emerging technologies, with a big emphasis on renewables. John Topper noted that there is a proposal for a new Gas and Oil Technology (GOT) IA, which was first discussed formally at an IEA (WPPF) meeting about a year ago. John Topper continued with this topic and showed some slides from the GOT IA on their proposed structure and activities. The slides will be circulated to Members.

ACTION 2: General Manager The Programme was approached for comments on this potential IA (note that the deadline was very tight and so Members were not consulted in this instance – with John Topper, John Gale and Kelly Thambimuthu only responding) and the comments were generally positive. There is space for such a network on upstream activities and the only way it would impact the Programme is on our work on decarbonisation – so references to this were removed from the proposal. This new IA is likely to go ahead and a revised set of documents will be distributed for approval soon (the timeline suggests if endorsed by CERT in November, the approval is likely to be given next year). John Gale noted that they were unaware we had been doing work on EOR and commented that it is currently unclear on how the IA will be funded. Gunter Siddiqi (Switzerland) noted that when Switzerland was consulted on the GOT IA, they mentioned that they would rather anything on emissions is covered by IEAGHG. He also felt that usually the countries/contracting parties don’t communicate in their own networks –if they did issues that arise could be communicated more efficiently. J ohn Gale noted that it was originally proposed that the GOT IA will report directly to the IEA WPFF, whilst there is no requirement on the other IAs to do so – it was pointed out that this is somewhat unfair. Peter Petrov (EU) thanked Mr Gale and Dr Topper for their work on this and supported Gunter Siddiqi that we should communicate more within our countries. As a final comment, Kelly Thambimuthu stated that if the clarity is maintained between upstream and downstream, there are no issues with this new IA. In terms of oil and gas, we do need them to look at upstream and the Programme is hopeful that its comments will be accepted. The strongest comment was to remove references to ‘decarbonisation’ and instead use ‘reducing the carbon footprint’. 8. MEMBERSHIP ISSUES / NEW MEMBERS Document GHG/12/39 refers. John Gale presented this and noted that ConocoPhillips, Masdar and Eni have withdrawn, along with ScottishPower. ScottishPower didn’t tell the Programme about their withdrawal at the beginning of the year, so we are currently in discussions regarding membership and payment issues. IIE (Mexico) and Petrobras (Brazil) have now joined the Programme.

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In terms of membership issues, IEAGHG have had no success with re-establishing contact with India with regard to two out of three of the contracting parties. Kelly Thambimuthu asked Members for comments or advice on how to proceed with this issue. John Topper commented that most people here are aware that there is nothing in Indian policy that is conducive to the implementation of CCS. We could argue that there are benefits to keeping this Member, but it is a difficulty in terms of administration. Brendan Beck (South Africa) noted that this matter was discussed at length in Bergen. We need to look at how the group in question function and consider alternative methods of contact. Kelly Thambimuthu asked if they are still being included in report dissemination – John Gale confirmed that TERI are receiving reports. We h ave an active contact with TERI, but none with NTPC (who were the lead organisation). We have a h istorical contact at CEA that has never responded and the TERI contact has been very helpful with trying to find contacts for us although these contacts rarely respond. Richard Rhudy (EPRI) asked if TERI would be able to pay – John Topper noted that it is only a small amount, £6,000/year. It was suggested that TERI should continue to be treated as the member. Kelly Thambimuthu noted that TERI should continue to receive publications as they will use them wisely and recommended chasing the IEA to ask them to contact their Indian Government representatives.

ACTION 3: General Manager 9. MEMBERS’ ACCOUNTS 2011/12 Document GHG/12/40 refers. John Gale presented this item and commented on the healthy accounts with no c ash flow problems. The Programme is in a very financially acceptable position. Jürgen-Friedrich Hake (Germany) asked about the current surplus in the accounts from the GHGT conferences. John answered that members had agreed that the surplus from GHGT-10 was committed to RITE to financially support GHGT-11. If this money is not fully spent or a surplus arises from GHGT-11 he will bring to the members attention at the next ExCo. Jay Braitsch (USA) asked if there is a target of how much money is in the accounts at any one time, to which John noted that there is no target but there is usually ~£2 million in the bank, which represents nominally 1 year of turnover. John also commented that a lot of money has been put into fixed-term bonds to improve rates of interest (~2 – 3%). Peter Petrov (EU) asked if there was any possibility that this financial report could be sent to Members earlier – unfortunately John sends this out as soon as he can, noting that it is difficult as we have to wait for the accountants and auditors. John Topper confirmed this, commenting that the UK financial year is April to March – the audited accounts are never received before September, which then needs to be finalised. Bill Spence (Shell) recommended keeping the surplus until needed and Philip Sharman (Alstom) agreed, noting it is a very healthy amount and we should resist the temptation to spend it on more studies. Jürgen concurred that if it is only a ‘buffer’ for one year’s work then it is important to keep it there. 10. SWOT / SCENARIO PLANNING UPDATE – FEEDBACK SINCE LAST MEETING 10.1 Proposed Changes to IA and Annex 1 Changes Document GHG/12/43 refers. John Gale presented this to Members. John noted that the Programme is proposing that the Chair, Vice-Chairs and General Manager should go through the IA documents with the IEA Office of Legal Counsel to identify what needs updating. The revised documents will then be circulated and taken to the ad hoc committee, then brought back for approval at the next ExCo meeting. Peter Petrov (EU) commented that is difficult to approve any change in an IA, as it’s considered an international agreement requiring a h eavy approval procedure. Peter proposed to abstain from voting at this time, following the proposal to consolidate all of this into the next ExCo. Peter also asked if it would be possible to do voting outside of the ExCo meetings, i.e. by video-conference. John Gale told him currently only comments are taken into account, but there is the potential to use a remote voting process – but the IA needs to be changed to allow this to work. 10.2 Update on Signposts/Scenarios Activity Document GHG/12/41 refers. John Gale presented this, commenting that there were a number of actions from the last meeting regarding the SWOT activity – one being on programme operations. A note was circulated to the Ad Hoc Committee Members on current staff time/deployment, to which

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little feedback was received (none that was negative). It is proposed that we maintain the current activity distribution but the General Manager will review as appropriate, depending on workload in different areas. Feedback received from members of the Ad Hoc Group on the activities was:

• The GHGT series should remain the focus (reducing other conference activities if necessary). • The research networks are a core activity, • The Summer School is very highly regarded and now in its second phase – so the future will

need to be discussed soon.

Peter Petrov (EU) asked whether CCUS should be included in the scope of the IA. John recalled that utilisation is part of the main scope of the new strategic plan and will therefore flow into the revised IA. The Information Papers (IP’s) are being used to track the developed scenarios. A new scenario has been developed to consider in this activity which is ‘CCS in a gassy world’. Jay Braitsch (USA) gave a short presentation on the scenario framework for 2012 – 27, looking at the idea of ‘CCS in a gassy world’. Richard Rhudy (EPRI) commented there had been some discussions on this issue in EPRI and noted that the cost of natural gas in different parts of the world differs greatly – hence will this really be a worldwide concept, or primarily a US-based scenario. Jay Braitsch (USA) commented that an ARI study looked worldwide; showing a few countries in South America, Europe, Australia and China, and looking at formations which have barely been explored in some cases, showing there is global potential. John Kaldi (CSIRO) commented that in Australia there is a lot of effort going into coal seam and shale gas, with the Gladstone plant in Queensland looking to make LNG from coal seam gas, with shale gas as a likely contributor. Kelly Thambimuthu noted that there is huge potential for this in China, but there is a potential policy to privatise this which will need to be taken into account. Many Asian countries import coal at a h igh price and some produce gas domestically. There is huge resource potential in fields here and looking at the price of international coal and gas, gas with CCS is more cost-competitive than with coal – it is certainly an area to watch and can be considered as a potential emerging signpost. Bill Spence (Shell) commented that the scenarios identified were valuable; it’s difficult to put one part of the world into one quadrant – a comment which was agreed with by Philip Sharman (Alstom). Helle Brit Mostad (Statoil) noted that she didn’t think this taskforce took into account the full scope of shale gas and welcomed this inclusion. Richard Rhudy (EPRI) commented that the given scenarios are four different worldwide ones and different regions are looking at different parts of the scenarios. Dominique Copin (Total) suggested looking at the difference in terms of the infrastructure side – you’ll need twice as much CO2 in a coal world compared to a gassy one – and the size of the source will too have an impact. Brendan Beck (South Africa) remarked that as a currently coal-dominant country considering using their large reserves of shale gas, South Africa often looks at the US and sees what it has done for reference for their energy mix and CO2 emissions. 10.3 Revised Communications Plan Document GHG/12/42 refers. John Gale presented this updated plan to Members and Tim Hill (E.ON) noted that there was a q uestion on the timeliness of report publication, with the IPs and technical reviews being a solution to this. John agreed that the reviews can be more timely but are done in-house – which may mean delays – so a potential solution would be to do such reviews externally. This needs to be looked into more.

ACTION 4: General Manager Philip Sharman (Alstom) commented that we need to consider what is meant by key influencer groups. There are a few possible areas to add people in, for example in the technical community research organisations could be regarded as a key group (e.g. UK CCS Research Centre). Other industry groups (e.g. CCSA) are also good to regard and organisations broader than CCS (e.g. UK Energy Knowledge Transfer Network) could be useful to ensure the right messages are passed

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through and onwards. Peter Petrov (EU) also remarked that the Energy Research Alliance would be an appropriate group to include and Bill Spence (Shell) suggested looking into what is being done in wind/nuclear technologies and to perhaps work more closely with such groups to be seen as part of the integrated solution. John agreed, IEAGHG will pick these up and look into this further. ACTION 5: Programme Team John Kaldi (CSIRO) mentioned in Australia especially groundwater issues are a h ot topic and suggested they are included within the communication plan. It may also be useful to have an assigned team to respond quickly to issues like this. John Gale agreed and confirmed groundwater would be included – release issues and ecological impacts will also be considered. Brendan Beck (South Africa) commended the IP on seismicity after the Zoback paper and asked if there was a way of monitoring the impact of the communication strategy, or if there is any way to quantify this. John noted that the team will look into this, hopefully this is possible.

ACTION 6: Programme Team 11. COMPLETED / ON-GOING ACTIVITIES 11.1 Feedback on Social Research Network (SRN) Meeting Document GHG/12/55 refers. Tim Dixon presented this summary of the meeting, held in April this year. Kevin McCauley (Babcock & Wilcox) asked whether there have been any identifiable issues with the capture plant, which could be miles away from the storage site, and Tim told him that at the meeting there was nothing that research here showed, as the SRN is focussed on storage. If there is a need for it, we could prompt capture to be included. Mónica Lupión (Spain) praised the work being done in the SRN but noted there is still a gap between social research and implementation. Even when following guidelines, it can be too general and the necessity of an engagement plan should be emphasised to industry. Kelly Thambimuthu (Chair), who attended this meeting, agreed with Mónica and commented that public engagement is very site-specific. Brendan Beck (South Africa) echoed Monica’s comments and suggested expanding the network from ‘SRN’ to a public engagement (etc.) network, bringing in academics to add information. 11.2 Key Messages for Stakeholders Document GHG/12/45 refers. Tim Dixon presented this paper on behalf of Toby Aiken (IEAGHG). Gunter Siddiqi (Switzerland) asked if there was any intention to put these notes into other languages, this perhaps could be useful. John Gale noted that as a policy we haven’t translated anything before and there has been some discussion with GCCSI on this. Mónica Lupión (Spain) explained that in ZEP, members volunteer to translate some reports – and kindly offered to contribute and translate the papers here into Spanish. It was suggested by Brendan Beck that communicating with a base set of images could be very useful and would then not need translating. Jay Braitsch (US DOE) asked who this activity is aimed at – Tim explained that there are brief papers for those willing to spend 20 minutes reading and then notes for those who want to spend 5. The papers would be used by key stakeholder groups. Peter Petrov (EU) commented that it is important to generate messages that members can disseminate, written in plain language to be understood by the public and politicians – those with perhaps no CCS knowledge. This briefing note is a good idea but needs to be communicated appropriately. There was time for questions and comments on all communication activities, so John Gale began by asking if there was any feedback from members on future prioritisations that should be made. Philip Sharman (Alstom) remarked that he thought the current balance was right, but the target audience could perhaps be tweaked to move forward. Phil added that a major challenge for CCS implementation is public perception and acceptance, placing more of a burden on the Programme to tailor communications to anticipate this need for good public information. He noted that this doesn’t necessarily make this a p riority but could shift the focus slightly. The SRN is very important and should continue as it goes a long way in this debate against CCS deployment.

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Jürgen-Friedrich Hake (Germany) mentioned that to add more value we need to consider what decision makers (for example) take out of what we produce and look at what issues should be addressed, considering barriers to our work etc. and potentially weighting our efforts differently. Kelly Thambimuthu suggested that alongside the usual technical summary for reports, a ‘policymaker’s summary’ should be produced. John Gale remarked this has been considered and discussed with the IEA CCS Unit, but unfortunately hasn’t happened yet. Steve Whittaker (GCCSI) remarked that the Programme philosophy is to stay away from policy, writing such summaries could be too much of a shift away from that philosophy. Richard Rhudy (EPRI) observed that information produced by the programme is disseminated to Members and suggested that they should pass on to policy makers. Peter Petrov (EU) remarked that in terms of messages to policymakers, we are all aware that the Programme is not intended to be policy-prescriptive, something that doesn’t have to change. It is useful to have the IEA and IEAGHG brand on some of the messages. Perhaps we should encourage more documents for a political audience, but keeping the content technical and the IEA could be asked for comments on such items. Philip Sharman noted that we must respect the role of the IEA CCS Unit, GCCSI, CSLF etc., ensuring our work doesn’t duplicate others and be sensible in deciding which organisation is best to do what. In this sense, policy summaries of our technical output don’t make sense. Peter agreed that duplication is not needed here, but some studies done by the Programme do contain political messages and perhaps a summary of the technology status each year would be valuable. Steve Whittaker (GCCSI) observed that the strengths of the Programme are being a technical voice but not an advocate – something that may be diminished if policy documents start to be produced – and producing high quality technical summaries should be preserved. John Gale agreed that IEAGHG should not produce policy messages directly, but that the Programme could produce a short section on “key technical messages” from each study that could be taken on board by policy makers. We could start this with the next reports to be produced and review at the next ExCo. This was agreed by the Chair.

ACTION 7: General Manager 11.3 Induced Seismicity Document GHG/12/46 refers. Mille Basava-Reddi presented this recent study to Members. Richard Rhudy (EPRI) noted that some magnitudes given (6-7) in some graphs throw up concerns in terms of presenting this to minimise the impact of the figures. If taken out of context, the data could be misrepresented. Millie agreed and remarked that this has come up in some reviews, suggesting there could be more discussion on the bias of the data. Jay Braitsch (USA) noted that if injection and pressures are managed well, the induced seismicity probably won’t happen. Gunter Siddiqi (Switzerland) also cautioned the use of the charts giving these high magnitudes and noted he hoped the methodology section explains thoroughly. Isabelle Czernichowski-Lauriol (France) would like to add a knowledge gap to the provided list – geochemical effects, which can be very specific to CCS storage activities. Millie commented that we can ask them to include that as the final report has not yet been received. Jürgen-Friedrich Hake (Germany) asked what the Programme’s perspective is on the summarised National Academies report – John Gale noted that this is an internal review of their report. Steve Whittaker (GCCSI) remarked that the Zoback and National Academies reports should be referenced. John commented that this study was ongoing at the time the Zoback paper was published and asked all to note that these higher magnitude earthquakes were associated with extraction activities, not injection. He also remarked that as the study was undertaken by seismologists, the potential impact of the report probably wasn’t considered by them, something which can be included in the overview. R ichard Rhudy noted he was not comfortable with the graphs in question being published (and wasn’t sure if the National Academies report had similar ones) and Gunter echoed this, commenting that the plots are fine if there is a sound basis with it, which in this case is lacking. Millie confirmed that the plots could be removed from the overview but they will still be in the report – these comments will be taken back to the contractors. Kelly Thambimuthu (Chair) remarked that there is a

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bit of residual doubt on how the data was extracted, care should be taken with this. The key here is to put it into the right context and ensure it is interpreted correctly. 11.4 Implications of Gas Production on Shales and Coals Document GHG/12/47 refers. Millie Basava-Reddi presented this paper. Richard Rhudy (EPRI) requested a copy of this report which Millie will send as soon as possible. John Kaldi (CSIRO) asked if the coal studies indicate if CO2 injection was supercritical or gaseous and Millie answered that she though it was gaseous as the formations were shallow. Tim Hill (E.ON) asked if there was any discussion on the effect of a fracking process on layers above and below a storage project, Millie explained that it does talk briefly on reducing the extent of the fractures. John Gale added that this was an issue with the shale gas study as well, not much information has been found in the public domain about the propagation of fractures. Steve Whittaker (GCCSI) commented that such an environment is seen in North America, where there is a shale with lots of overlying well reservoirs and underlying saline aquifers that are unaffected. This suggests you’re safe technically, but fracking can go further vertically than anticipated, sometimes over 100s of metres. 11.5 Subsurface Resource Interactions Document GHG/12/48 refers. Millie Basava-Reddi presented this paper. Richard Rhudy (EPRI) commented that the intention here seems to be an overarching organisation looking at all of this. Millie answered that they are trying to do that in the Gippsland Basin – it is aimed at the policymakers who will need to make the decisions. John Gale remarked that there is an aspect here of what has happened historically – this is if you are looking at certain regions, how you may look at this. Malcolm Wilson (PTRC) noted that in the Alberta regulatory review process, you will see the same kind of thinking and those recommendations have gone forward to government, so you do not get sterilisation of resources and to maximise the benefits. The Alberta process is a good model. John Kaldi (CSIRO) commented that the Australian government have to release 5 areas specifically for CO2 storage. How this decision was made and whether it was in consultation with industry. It is worth noting that Victoria and Queensland also have legislation for specific CO2 storage. John then questioned Gorgon being referred to as a waste disposal area and Millie clarified it meant brine disposal (so pressure management). Brendan Beck (South Africa) observed this seems to go into recommendations for policymakers, who will look at this type of thing on a case-by-case basis. This is a useful overview study, but as decisions are site-specific it’s difficult to see how the study could be taken forward. 11.6 Incorporating Future Technological Change in Existing Capture Plants Document GHG/12/49 refers. Prachi Singh presented this to Members. Philip Sharman (Alstom) remarked that it was disappointing that Imperial College have not produced what was specified and asked for care to be taken when describing first/second/third generation activities. First generation is probably that which will come in before 2020, second is an evolution of this and will likely come into play in 2025-30 and third generation are probably post-2030, radically different and new designs. Jay Braitsch (USA) made a general point that much of the content of the paper is understandable, but perhaps more explanation is needed when looking at very technical things at a meeting of mixed backgrounds. Reinhold Elsen (RWE) remarked that if he were to look at this from an investor’s point of view, he would need a clear economic assessment of the options given. Prachi agreed and noted this was part of the original scope, commenting that if it were of interest to Members, some in-house cost evaluation may be possible – with the input of some Members’ expertise. John Gale noted that this study did not finish what it was meant to, including the economics. Prachi concluded that some follow-up work will be done internally and the team will look at the most efficient way of covering the costs issue. 11.7 Post Combustion Capture Scale-Up and challenges Document GHG/12/50 refers. Prachi Singh presented this. Kevin McCauley (Babcock & Wilcox) asked why (on the conclusions slide) the steam generator ‘barrier’ was marked red for costs. Prachi explained that there is some modification required and so there will be extra costs in the beginning when such generators are in the market, confirming that the cost will be higher in the initial phase

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before decreasing. Philip Sharman (Alstom) noted that when the proposal was first discussed, the OEMs and utility companies were unsure as to what strategies would come out of the work. He felt that the insights here are not new and already being worked on by OEMs. It is a reasonable engineering approach but is nothing revolutionary, agreeing that the report may however add to the overall thinking whilst noting that the study has backed away from actual scale-up steps. Kelly Thambimuthu (Chair) remarked this is an area where the technical community knows what it is doing. The report adds to the confidence-building and it lends credibility to put such a report out. Reinhold Elsen (RWE) asked for clarification on the absorber, with Prachi explaining that the concrete was chosen as it was cheaper (so more cost efficient for bigger plants) and in terms of dimensions it was 28 metres high with 7 x 7m cross-sections. Reinhold also asked about the loss in efficiency in the retrofit of existing plants. Prachi explained they didn’t look so much into this, but estimated a loss of 20 – 30% efficiency, noting that more work was done on the issues related to scale-up, focussing on the design. It was not in the scope to look at different technologies but the contractors have highlighted some. Malcolm Wilson (PTRC) noted there is a lot of work already being done on this. Prachi noted that there is no real technical challenge in scale-up; it can be done in chemical and power plants. 11.8 Feedback on Geological Storage Network Activities a) Joint Network Meeting (JNM) Document GHG/12/51 refers. Tim Dixon presented this network report. Bill Spence (Shell) noted that he was impressed by the horse power IEAGHG were able to pull together for this – perhaps it would be a good idea to do this again with hot topics, asking who would identify such topics and who could be invited. Tim noted that the first step would be for Members to alert IEAGHG of any topics they feel are worthwhile. The natural core of expertise is in the Steering Committees and membership base of all networks. Teleconferences can be held and network members could be invited. Tim also noted that the discussions on Zoback at the JNM were possibly not as comprehensive as they could have been, but led onto further discussions. John Gale remarked that the Programme has various response mechanisms, but are somewhat case-specific. In the case of Weyburn, we heard about it very quickly and were immediately in contact with PTRC, putting out something fairly quickly on this and acting as a focal point for members. The team can address any hot topics from the Members through IPs (although these are not rapid-response), do a small literature review and pull in experts if needed. b) Environmental Impacts Document GHG/12/52 refers. Tim Dixon presented this paper. Kelly Thambimuthu noted he was uncomfortable with the proposed network name and suggested changing this to ‘Network on environmental assessment/research into CO2 storage’. Tim Hill (E.ON) congratulated IEAGHG on the network meetings this year, positive feedback was given from the E.ON representatives that were able to attend meetings. Tim Hill asked if the objective of the 2013 meeting would be to report on more results, e.g. the QICS project, to which Tim noted the agenda is not yet developed but there will be more actual results. At the QICS project there were some issues with monitoring (the equipment being in the wrong place) and Tim Hill remarked that those present at the meeting relayed confidence that any leaks could be managed, but to translate this into things that can actually be done (in terms of economics and feasibility) is not the case – perhaps this is a challenge that could be looked into. John Kaldi (CSIRO) commented that here it states the Shell Quest project was the first environmental assessment undertaken in a real project – asking for credit to be given to the Gorgon project who carried such an assessment out a while ago. Tim Dixon agreed but noted that in terms of what was needed in regulatory world, Shell produced the most detailed assessment. Reinhold Elsen (RWE) noted the connection to the waste disposal community and Tim concurred, noting that in Switzerland there was a project that brought together the two communities, something that IEAGHG is looking into. Steve Whittaker (GCCSI) remarked that the Reuters article on Sleipner came across somewhat onerous rather than positive, with Tim agreeing that this article was more negative than had been previously expected. Steve also asked if there were any public communication strategies at projects covered in the network that explain why the experiments are being done and Tim explained that such activities are important for controlled release projects such as QICS. This project is a success in these terms; they engaged the local community so few concerns were raised. Tim Hill noted that with the

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ECO2 project and communications, the angle that Reuters took on this was not what the original press release suggested and remarked that IEAGHG’s involvement on t he advisory board for QICS and being asked to review some ECO2 work is a good opportunity for the Programme. Jürgen-Friedrich Hake (Germany) noted that to add on to the nuclear versus CO2 storage comparison, there is an ongoing research project in Paris, addressing geology, monitoring, regulatory aspects and legal issues. This report will be published soon and Jürgen noted this would be interesting. Jürgen advised ensuring that the network name includes ‘IEAGHG’ – all agreeing that it is important to keep the brand of IEAGHG mentioned where possible. Kelly Thambimuthu agreed and noted we should ensure all networks follow suit and become a little more brand-conscious. 11.9 Feedback on Solid Looping Network Meeting Document GHG/12/53 refers. Jasmin Kemper presented this. Jay Braitsch (USA) noted there is a question on how fast this is actually moving, with challenges ahead it sounds as if they’re not as worried about 50 M W power plants – will this be a commercial technology by 2030? John Gale commented that there is a degree of optimism on this technology; scale-up processes show there are many technical issues to resolve first. Jasmin then relayed comments to Members from the network, which stated they don’t want to consider this technology for large scale project, just small to medium (up to 500 MW). Kelly Thambimuthu agreed there is a learning curve and optimism is high, but there is a lot to be done. Philip Sharman (Alstom) remarked that the application of solid looping in industrial capture technologies is interesting, with the technologies coming through quickly. There is a lot of movement on industrial and chemical looping, as well as the hybrid concept – they could all come through and surprise us! Peter Petrov (EU) commented on the size of demonstration plants for this technology. From what he understands, they can be quite versatile and looping technology could be combined with a cement plant – potentially in the range of 50 MW which is a good size for such a technology. This could be why they’re concentrating on s maller sized plants. Peter then asked for clarification on the CaOL and CLC technologies combined, mentioned on the final slide – is this a new technology? Jasmin explained this was a new technical possibility presented at the network meeting where 3 reactors are used instead of 2. 11.10 Feedback on Summer School 2012 Document GHG/12/54 refers. Tim Dixon presented this paper to Members. There were very few comments on this presentation, with Mónica Lupión (Spain) expressing her sincere congratulations to the IEAGHG team in charge of the Summer School, especially this year as t he logistics were particularly challenging. Kelly Thambimuthu echoed Monica’s positive comments. 12 DISCUSSION PAPERS 12.1 UNFCCC and London Convention and ISO Update Document GHG/12/44 refers. Tim Dixon presented this paper. Malcolm Wilson (PTRC) noted that today (16th November) in Canada the CSA 27 standard was released, a voluntary standard from the CSA. The process is on-going and there will 5 sub-committees working with the ISO group. PTRC and SaskPower are involved in Canada. Tim Hill (E.ON) remarked that IEAGHG could probably in some way influence some of the outputs of the standards committees. Tim then asked if the Programme has considered the sort of things that may want to be pushed through as points of priority. Tim Dixon answered that the Programme will wait to see as the work programme develops and bring anything to ExCo Members that the team feel necessary, at meetings and in between meetings if needed. Philip Sharman (Alstom) commented that Alstom feels that developing standards in this area is too early but they want the right standards to come out, noting that CSLF have also applied to be a category A organisation in ISO 265. T im concurred, noting that the IEA CCS Unit has also successfully applied and the IEAGHG role will likely be to ensure nothing goes through that isn’t sensible. Following a question from GCCSI, Tim commented that CO2-EOR projects are not excluded in the CDM, but it was deliberately kept out of discussions – but there is nothing in the modalities and procedures that exclude them. Every project must demonstrate there is a greenhouse

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gas benefit and decisions are made on a project-by-project basis. Kelly Thambimuthu asked if there was any feedback on C hinese attitudes to EOR in the CDM, with Tim explaining that this wasn’t discussed as it could have polarised views, causing problems. Kelly noted there is a study involving Indonesia and Japan, where there are no preconceptions – an interesting space to watch. Peter Petrov (EU) remarked that the European Commission is supporting 2 projects which will work in the field of assessing CO2 impurity in transport and storage and will be trying to engage with ISO to provide data for this. Peter asked if IEAGHG can provide them with a link to get such data, to which Tim answered yes – we can get information through to them through the national committees or directly from IEAGHG as we’re formally included. Juho Lipponen (IEA) commented briefly on ISO, noting that the IEA, IEAGHG, GCCSI and CSLF are all involved, suggesting it could be useful to establish a chain of informal emails around these groups to coordinate ourselves. Åse Slagturn (Norway) noted that Norway is one of the ratifying countries for the London Convention and would like to encourage other countries’ involvement in this. Tim noted there were no time limits to ratify (open-ended) and the figure currently stands at 27 countries, with more parties signing on. N orway was the first to actually propose the amendment. Kelly commented that there was definitely room for the IEA and GCCSI to encourage the countries to ratify, with Juho explaining there is currently no m ovement within the IEA to do this but perhaps should be discussed at a high level. Steve Whittaker (GCCSI) questioned the opinion of those countries not involved in this and asked if the Programme had any plans to discuss the issue with those countries not involved. Kelly Thambimuthu remarked the Australian Consortium thought it was premature for this to move ahead, adding it would be interesting to watch as it goes ahead. IEAGHG are not actively soliciting involvement in this. 13 STUDY PRIORITISATION Document GHG/12/56 refers. Tim Dixon presented this paper to Members. Operating Flexibility of CO2 Storage and Transport Document GHG/12/57 refers. Millie Basava-Reddi presented this paper. Kelly Thambimuthu (Chair) suggested buffering capacity in terms of cost and operating flexibility should be included. Krishnaswamy Sampath (ExxonMobil) suggested utilising experience from the oil and gas industry as they have been looking at this issue for decades. Kelly suggested that in most cases operational experience is 1:1 and it was agreed that the first part of the study should look at the literature to define what the issues are before considering solutions. Bill Spence (Shell) agreed and objected to some of the phrasing about identifying problems and solutions and that there could be more of a practitioners’ guide and the intent of the report should be solutions. Reinhold Elsen (RWE) said that the problem needs to be defined first and wanted to know if offshore storage and intermediate storage would be considered as the value to RWE would mostly be in offshore storage. Philip Sharman (Alstom) supports this study and suggestion of inclusion of how dynamic flexibility is affected by impurities. John Gale commented that this would be outside of the scope of this study, but some of this will be included in the next study presented. Helle Brit Mostad (Statoil) agreed with the others from the oil and gas industry in that there is already much experience in this area and that this should be drawn upon if possible, and that there should be more focus on intermediate storage. Richard Rhudy (EPRI) supported this study, though it should be noted that much of the experience and information mentioned may not be available. EPRI are conducting a project looking at storage in a saline aquifer and will share experience here if it is possible. Helle suggested a publically available SINTEF report supported by Statoil and Sampath suggested a Kinder Morgan study as a g ood source. Tim Hill (E.ON) was keen for this study to go ahead although does not think intermediate storage should be a priority, but is interested in how impurities will affect dynamic flexibility. Kelly summarised that this study will go ahead with comments taken into account. Impact of CO2 Impurity on CO2 Compression and Transportation Document GHG/12/58 refers. Prachi Singh presented this paper. Tim Hill (E.ON) expressed a few concerns – there is currently much R&D in this area, such as ex perimentation to improve multicomponent equations of state and is not sure if this is the right time to carry about this study as it may be a repetition of other work. Prachi agreed that there is much work, but that the idea of this study is to review the information available and look at what are the realistic scenarios in terms of

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impurities. Kelly Thambimuthu agreed that this is a good time to review what work is available and Tim Hill agreed that it may help remove certain myths related to impurities. Peter Petrov (EU) advised that there are a couple of projects supported by the EC due to be finished in 2-3 years, though some work will be published before this. Kelly pointed out that this would be a long time to wait. Brendan Beck (South Africa) suggested looking at case studies on coal to liquid plants. Richard Rhudy (EPRI) suggested not limiting the study to power plant streams and that the numbers be realistic. Prachi agreed that it is important to talk to operators when defining scenarios. John Kaldi (CSIRO) suggested the Pipeline CRC in Australia as potential contractors. Philip Sharman (Alstom) supported this study and thinks it important as it may feed into future pipeline standards, which will become more important as we move to multiple source scenarios. Kelly suggested that the study go ahead, but first a quick review on information available on thermodynamic properties should be done, any identified showstoppers may be worth knowing. John Gale suggested as part of this, to connect with the other studies to find out when information will be available. Eemeli Tsupari (Finland) asked if ship transport will be included, with Prachi advising that this can be included. Kelly summarised that this study may go ahead following a quick review of current work. Quantifying and monitoring emissions reductions from CO2-EOR Document GHG/12/59 refers. Tim Dixon presented this paper to Members. Krishnaswamy Sampath (ExxonMobil) brought up the subject of breakthrough, which if it does occur will be re-captured and used, due to the cost of CO2, however much remains in the ground. Malcolm Wilson (Canada) advised that they have already carried out much of this work, which is currently available. Juho Lipponen (IEA) remarked he is happy for this study to go forward as it reflects the IEA CCS Units interests and Kelly Thambimuthu suggested that it would be useful to put existing work into a credible framework and so is worth doing. Steve Whittaker (GCCSI) also agreed that it is worth redoing some of this work, especially in terms of the CDM. Gunter Siddiqi (Switzerland) pointed out that this is a particularly policy relevant study, noting the issues with the credibility of CCS when linked to EOR which needs to be addressed. Brendan Beck (South Africa) suggested that incremental oil not be included in the methodology, though it can still be discussed. Tim advised that this needs to be included as it is in the CDM rules to account for incremental oil. Bill Spence (Shell) agreed with the topic going forward but noted it is important to differentiate between EOR in the CDM and otherwise, as in other situations the emissions from the oil should be accounted for by the purchaser. Richard Rhudy (EPRI) remarked that if EOR is already being carried out it is not a new emission, it just depends on where the CO2 is source, i.e. anthropogenic or natural. Brendan Beck agreed with this and noted the importance of including baseline data, which Tim confirmed would be included. Kelly pointed out that it is important to have robust information and that the current politics should be discussed. The CDM rules were crafted without CCS in mind and should evolve over time. David Jones (BG Group) supports this project and wanted to make sure that we differentiate between onshore and offshore sites – and what we do and don’t know. Sven-Olov Ericson (Sweden) said that this is interesting as will be a life cycle analysis and it is important to allocate flows, even if it is not possible to quantify. Krishnaswamy Sampath suggested that this could be a technical review instead of a full study. John Gale suggested IEAGHG write the technical specification and then circulate to Sampath, Malcolm Wilson, David Jones, Steve Whittaker, Brendan Beck and Bill Spence to check that the scope covers everything as requested.


Techno-economic evaluation for Different Post Combustion Capture Process Flow Sheet Modifications Document GHG/12/60 refers. Prachi Singh presented this paper. Kelly Thambimuthu clarified that the scope covered new builds and not retrofits. Prachi agreed that retrofits could be looked at as well and that a sensitivity analysis would be a good idea. Philip Sharman (Alstom) advised that Alstom are uneasy about this study as it may reach into the realm of commercial activities and that no information will be forthcoming from OEMs meaning this study with end up v ery generic. Kevin McCauley (Babcock & Wilcox) suggested that as a path to commercialisation, it could be misleading or confusing, as a g eneric solvent will be used and as each case is solvent specific, it may lead to incorrect conclusions. Helle Brit Mostad (Statoil) suggested this will be a very site-specific study.

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Richard Rhudy (EPRI) agreed with the above comments, noting that the study may come up w ith things that are not commercially viable and may not bear a relationship to how a concept may be utilised. Tim Hill (EON) advised that EON were positive about this proposal, though thought that there may be information from utilities. Prachi suggested that this study will focus on process integration. Kelly noted that he understands the comments, but feels that there is value in the study if it is not solvent specific. Reinhold Elsen (RWE) remarked that from an engineering point we want to understand how flow sheets behave and would recommend this be taken as a generic study indicating R&D needs. Sven Unterberger (EnBW) agreed with a generic study looking at R&D needs and Jay Braitsch (USA) advised that these studies are good to establish a baseline. Tim Hill suggested potential contractors; Gary Rochelle and SINTEF. Kelly advised having OEMs in the review process. Philip still has concerns with this; it will need to be a generic study as there will be no information available, which may not be valuable. Richard Rhudy agreed and remarked he does not see a generic study as u seful, though is happy to act as a r eviewer. Helle had similar concerns and suggested rephrasing the study and putting it through voting again. Reinhold Elsen also shared these same concerns. Kelly suggested that John Gale and Prachi discuss the scope with Statoil, Alstom and Babcock & Wilcox, and that the study should go forwards.


Understanding the cost of Retrofitting CO2 Capture in Oil Refineries Document GHG/12/61 refers. Stanley Santos presented this paper. Peter Petrov (EU) noted his support of this study as it is important in the industrial application of CCS, although some caution should be taken on the scope as this is a complex area and we need to be careful as to what details/ complexity is included. Funding partners should be decided by what information can be shared. Stanley advised that he will aim to look at government agencies for funding so the report can be public. Kelly agreed such a joint activity including industry will bring a greater chance of getting the message out and noted that a d egree of freedom is needed. Steve Whittaker (GCCSI) advised of similar work in Regina and that we may want to try to share information. Mark Crombie (BP) advised that CCP3 has been carrying out some similar work which will be published next year; Mark will talk to Stanley about this offline. Kelly summarised that this study should go ahead, though made members aware that this will take longer than an average study to get started and it will be budgeted differently. Cost components for Storage of CO2 in association with Enhanced Oil Recovery Document GHG/12/62 refers. Samantha Neades presented this paper. Steve Whittaker (GCCSI) was not sure who the intended audience is and noted that it might be useful to consider costs for optimising storage; otherwise it appears oilfield-targeted. Juho Lipponen (IEA), who proposed the study, thought initially of it being a resource to the IEA CCS Unit and that it may need to be re-evaluated. Richard Rhudy (EPRI) asked if it could include the price of CO2 needed to make EOR work, this could include a range of costs. Sam advised that this could be included. Jay Braitsch (USA) advised that the US DOE have carried out work in this area, so will be able to contribute and will talk to Sam offline. John Kaldi (CSIRO) suggested that oil companies are not likely to reveal cost data, so it may be difficult to obtain such information. John Gale agreed but noted that there is data from US DOE along with work from UK DECC and Herriot Watt, though they may not all be consistent. Krishnaswamy Sampath (ExxonMobil) advised that it is important to define what is meant by optimising CO2 – is this the maximum amount stored; as cost data changes with time, meaning it is difficult to pin down a number so ranges might have to be used. Philip Sharman advised liaising with the CSLF when looking at moving from CO2-EOR to permanent storage and noted that the taskforce is led by Stefan Bachu. Bill Spence (Shell) advised that EOR will not work in every field and part of the project should show the cost and where it can work. Sam advised this can be included. Richard Rhudy advised including long-term liability as well. Kelly Thambimuthu summarised that this study will go forward. 14 STUDIES TO BE RECONSIDERED FOR FUTURE VOTING Please note there is no paper for this section. Tim Dixon presented this to Members, beginning with a summary from the Study Prioritisation section, above. To reiterate, all of the 6 studies presented will

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go through. For other proposals, all Members were happy for all study ideas to go back into the voting round. Helle Brit Mostad (Statoil) had a comment from Tore A. Torp (also Statoil) regarding study 42-11 (CO2 storage wells/site abandonment), noting that the current CO2CARE project (ending December 2013) will cover some of this. John Gale agreed there should be little duplication, so the team will communicate with the CO2CARE project team and look at their outputs. Dominique Copin (Total) remarked they were the originator of this idea and agreed checking with CO2CARE would be beneficial. From Total’s point of view, the issue with wells and site abandonment is very important (technically and for public acceptance) and John Kaldi (CSIRO) also noted his organisations’ hope this would be kept in. Peter Petrov (EU) remarked that CO2CARE is endorsed by the EC and has 7 international partners – Peter offered to provide the point of contact for the project. Kelly Thambimuthu (Chair) concluded that the study will be kept in, subject to some interaction between the Programme and our Australian colleagues. Gunter Siddiqi (Switzerland) commented that 42-08 (techno-economic evaluation of the potential CO2 capture application in pulp and paper industry) is an attractive idea and this Programme is the ideal body to carry out such a study. Stanley Santos explained that this won’t be a huge study, but valuable nonetheless as t his could potentially be a n egative emission technology (if negative emissions are accounted for in the ETS). John Gale remarked the Programme is hopeful this will be picked up in the future. Peter Petrov asked whether there was a limit for the number of studies that can be reconsidered for future voting and John Gale informed him that it is usually about 12 – 15. John then asked for the flexibility of being able to knock the 6 studies with the lowest votes off the list to be able to include new ideas at the next voting round. Bill Spence (Shell) remarked that 42-17 (closing the water loop) would be a important study to look at as we will soon be approaching ‘peak water’. Richard Rhudy (EPRI) agreed, asking if this study could be combined with 42-16 (comparison of the water usages of low-CO+ power generation technologies) as this is also about water. John noted he didn’t think this would be possible but will look into this. Helle echoed Bill and Richard but feels that the best approach would be to keep them separate. Tim Dixon noted that this study (42-16) was brought in by EnBW and Sven Unterberger (EnBW) added that they were particularly interested in public acceptance when looking at fracking and chemicals.

ACTION 10: General Manager Philip Sharman (Alstom) noted that the whole topic covered in 42-06 (evaluation of CO2 adsorption process in natural gas production) is interesting, in terms of processes and materials issues. Alstom would like to see this kept in. In conclusion, all studies from ‘Other Proposals – 1’ will be kept in (42-01, 42-11, 42-08, 42-02, 42-04 and 42-05). In terms of the second list (slide ‘Other Proposals – 2’), there was some discussion about how to move forward with these. It was decided that studies on this slide (42-17, 42-06, 42-12, 42-16 and 42-15) would be dropped; Kelly invited Members to resubmit/email written submissions if they strongly feel a particular study should be put back in for voting. Richard Rhudy asked if a technical review could possibly be done on utilisation (other than EOR) as there is a lot of current interest in this. Tim Dixon noted that GCCSI has a report out on this which brings together current thinking on CCUS options – perhaps it would be best to look at this first. 15 UPDATE ON GCCSI PROGRAMME Document 12/63 refers. Tim Dixon presented this paper to Members, outlining our activities on behalf of the Global CCS Institute since the last ExCo. Steve Whittaker (GCCSI) remarked that the Institute have always been happy with their collaboration with the Programme, in particular with the Summer School. Steve noted they are looking to maintain this collaboration and extended thanks on behalf of the Institute to Tim.

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16 FEEDBACK ON GCCSI ACTIVITIES There was no paper for this presentation which Steve Whittaker (GCCSI) gave to Members, but a document was circulated to all prior to this ExCo meeting, detailing the Institute’s activities. There were few comments but John Topper remarked that he feels the annual status on CCS that the Institute publishes every year is valuable, with Steve noting that GCCSI would welcome any comments on this publication, especially on defining projects. 17 FEEDBACK ON IEA ACTIVITIES Juho Lipponen (IEA) presented this brief summary of the IEA’s recent activities, which has no paper. Tim Hill (E.ON) asked if a paper could be produced on the suggestion that carbon particulates have the potential to reduce CO2 in the atmosphere, with John Topper remarking that the IEA Clean Coal Centre (CCC) are currently working on a study on black carbon which will be publicly available soon. Helle Brit Mostad (Statoil) asked what Juho thought was the most important different message from the IEA’s last ETP report. Juho explained that they’ve had various people do the ETPs so they are not necessarily standard all the way through. Much of what the ETP does is to update the technology status across the board, so there are no updates on this really. 18 FEEDBACK ON MEMBERS’ ACTIVITIES 18.1 Japan Masanori Abe (JCCS) gave this presentation to Members, looking briefly at the Tomakomai CCS System and demonstration project. Steve Whittaker (GCCSI) noted this was impressive work and asked if cores were taken from any of the wells. Masanori explained they took cores from 2 wells and are planning to take more from the reservoir wells, commenting that there is a gas and oil field just east of the project area, so the volcanoclastic rocks make a good reservoir. 18.2 Shell Bill Spence (Shell) gave a brief overview on the Quest project (Canada). Peter Petrov (EU) asked if the project team are looking at the EU network for knowledge sharing, Bill commented that they are as this is critical. Shell need to get through two demonstration stages to get deployment by 2020. Suk Yee Lam (UK) asked about the target audience of the knowledge sharing and Bill explained that a vast amount of information will be put on the public website – the only items that won’t be on here is the proprietary/commercial information. Suk Yee then asked if there would be a co mplimentary workshop and Bill remarked that there are no plans for this formally but that it’s a great idea. Philip Sharman (Alstom) noted that this is a CSLF-recognised project and asked if this will play a role in the knowledge transfer. Bill answered positively, saying this is likely the best connection with the North American audience. 19 DONM Document GHG/12/64 refers. Sian Twinning presented this paper. The dates of the 43rd ExCo meeting are set as the 8th and 9th of May 2013. Presentation on 43rd ExCo meeting – Regina, Canada Document GHG/12/64 refers. Sian Twinning presented this item on the next Executive Committee meeting, which will be held in Regina and hosted by PTRC on the 7th-10th May 2013 (ExCo meeting plus a site visit and CCS seminar). Kelly Thambimuthu asked for all Members to consider hosting a future ExCo meeting and noted that the meetings in Autumn 2013 and Spring 2014 are currently without hosts. John Gale remarked that this will default to the UK if there are no of fers. Isabelle Czernichowski-Lauriol (France) mentioned CO2GeoNet may be able to host in 2014, but will have to check and confirm at a later date. 20 AOB Malcolm Wilson (PTRC) noted that the Best Practice Manual from the IEAGHG Weyburn-Midale Project is being printed. If Members would like a copy of the BPM, please email Malcolm or John Gale and they will distribute. By the next ExCo meeting, there should be a supplementary edition of IJGGC available as well. 21 CLOSE OF MEETING Kelly Thambimuthu thanked the Japanese hosts for welcoming all of the ExCo to Japan.

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CORRECTIONS TO MINUTES

No changes were requested by members. Members are asked to formally approve the minutes.

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LIST OF ACTIONS

Action

No. On Action Status

1 General Manager Make necessary changes to Greenhouse News distribution to make cost effective

Complete

2 General Manager Circulate GOT IA slides to members Complete 3 General Manager Chase IEA to contact India re membership On-going 4 General Manager Look at option to have technical reviews done

externally Underway

5 General Manager Build relationships with key influencer groups identified by members

On-going

6 General Manager Monitor impact of communications plan On-going 7 General Manager Look at producing “key technical messages”

document for each report published Complete

8 General Manager Produce technical Specification for GHG/12/59 circulate to interested parties before tendering

Complete

9 General Manager Discuss technical scope of GHG/12/60 with Statoil, B&W and Alstom

Complete

10 General Manager Look at feasibility of combining 42-17 and 42-16

Complete

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PROGRESS REPORT

Introduction This report provides a summary of activities completed since the last ExCo meeting (42nd) held in Kyoto, Japan November 2012. The report covers a 5 month period which included the Christmas holiday period. IEA Environmental Projects Ltd Succession at IEA Clean Coal Centre New GM appointed at IEA Clean Coal Centre At the last ExCO members were informed that the situation pertaining to John Topper, Head of Service IEA CCC and CEO at IEA EPL was about to change. In the first half of 2013 John will reduce his activities to work half-time. This will encompass his existing activities for the IEA Greenhouse Gas Programme (typically averaging 0.5 days/week) i.e. no change; and leaves him working the balance of time in a reduced IEA CCC role. He will retain overall responsibility as CEO of the Operating Agency for both services but most day-to-day activities of the IEA CCC will be managed by a new General Manager – the same arrangement as for IEA GHG. The new General Manager at IEACCC is Prof Andy Michener OBE, who will take up his position as of 1st July 2013 IEAGHG team • Staff Issues. Ameena Camps left IEAGHG in Feb 2013.Toby Aiken will leave in June

2013 to become self-employed. Ludmilla Basava-Reddi will leave at the end of September 2013 to start a PhD at Bristol University. At the time of writing this report a proposal is under preparation on how to accommodate/reorganize to overcome these departures. This will be reported to members at the ExCo meeting.

• Office/Operational Changes – Demolition/construction has continued on the site but has not directly affected IEAGHG otherwise nothing to report

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 42nd and 43rd meetings, studies that will be underway at the time of the 43rd meeting and studies that are outstanding are summarised in the tables below and overleaf.

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Table 1 Technical Studies published since the 42nd ExCo meeting Title Contractor Report

number Publication date

Operating Flexibility of Power Plants with CCS

Foster Wheeler

2012/6 July 2012

Gaseous Emissions from Amine Based Post Combustion CO2 Capture Processes and their deep removal

CSIRO 2012/7 May 2012

CO2 Capture at Gas Fired Power Plants Parsons Brinckerhoff

2012/8 July 2012

Barriers to Implementation of CCS: Capacity Constraints

Ecofys 2012/9 August 2012

Financial Mechanisms for Long-Term CO2 Storage Liabilities

ICF International

2012/11 September 2012

Ethical Attitudes to CCS UMIST 2012/13 October 2012 CCS at Iron and Steel Plants MEFOS 2012/14 December

2012 UK FEED Study Analysis IEAGHG 2012/15 October 2012 Table 2 Studies being reported Title Contractor Publication date CO2RISKMANs DNV June 2013 Update on Monitoring Tool BGS On web site, Incorporating Future Technological Change in Existing Capture Plants

IC Consulting July 2013

CO2 Migration Mitigation Options CO2GeoNET June 2013 Non CO2 Gases – A review IEAGHG August 2013 Dehydration of CO2 AMEC July 2013 Key Messages For Communication Needs For Key Stakeholders

Univ. Edinburgh/CSIRO

May 2013

Table 3: Studies underway Title Contractor Draft Report date Xtl to Liquids SGEA consulting January 2013 CO2 Test Injection Development Process CO2CRC February 2013 Assessment of costs of capture at baseline coal power plants

Foster Wheeler Italia

July 2014

Evaluation of reclaimed waste disposal for CO2 Post Combustion Capture

Trimeric Corporation

July 2013

Biomass CCS – guidance on a ccounting for Negative Emissions

Carbon Counts May 2014

Comparing Approaches to Managing Storage Resources *

BGS October 2013

Barriers to CCS in Cement Industry * ECRA October 2013 CO2 Pipeline Infrastructure Review * Ecofys October 2013 CO2 storage efficiency in aquifers EERC December 2013 Monitoring Selection Tool BGS December 2014 Techno Economic Evaluation for Different Post Combustion Capture Process Flow Sheet Modifications

Univ. Texas April 2014

*GCCSI funded

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Table 4: Studies out to/awaiting tender Title Proposal number Impact of CO2 Impurity on CO2 Compression and Transportation 42-09 Understanding the Cost of Retrofitting CO2 Capture in Oil Refineries 42-07 Cost components for Storage of CO2 in association with enhanced oil recovery

42-14

Quantifying and monitoring emissions reductions from CO2-EOR 42-13 Criteria of fault geomechanical stability during a pressure build-up 41-07 Table 5: Studies outstanding awaiting start Title Proposal number Environmental Impact Statements – Review of Gaps 41-09 Operating Flexibility of CO2 Storage and Transport 42-10 Techno Economic Evaluation for Different Post Combustion Capture Process Flow Sheet Modifications

42-03

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:

• COP-18, Doha, November-December Tim Dixon attended, working with and seconded into the UK government (DECC) to participate in the negotiations representing the EU for CCS in CDM. These addressed the two unresolved issues from Durban, of whether and how trans boundary projects should be allowed, and a Global Reserve of CERs (which would provide a backstop of CERs to be drawn upon i n the event of CO2 seepage). Five different presentations were given by IEAGHG, and IEAGHG publications disseminated through the University of Texas booth (collaborating with CCSA and ZEP) and IEA booth. A report on the outcome was sent as Information Paper 18 on the 11 December. Further details are provided in paper GHG/13/11.

• CSLF Technical Group/PIRT. No-one was able to attend the CSLF Policy and Technical Groups meeting in Perth in October 2012. The next CSLF Technical Group meeting is in Rome 16-19 April and IEAGHG will participate. The next CSLF Ministerial and Policy and Technical Groups meeting will be in Houston in November 2013.

• EU ZEP. IEAGHG (Tim Dixon) attended the Policy and Regulation Task Force meeting on 18 February. IEAGHG (Stanley Santos) are collaborating with ZEP on a report on CCS for industry in an advisory role and co-authorship. .

• Joint Task Force (JTF) 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 main activity has been the production of a report ‘Bio-CCS – The way forward for Europe’. IEAGHG were not able to attend the last meeting on the 23 January 2013, but input by email on related activities by IEAGHG, notably the Bio-ETS Accounting study underway. Also to note that ECN and Ecofys are undertaking a study on public perception of Bio-CCS, which had been a study proposal to 40th ExCo but not voted forward at that time. IEAGHG will aim to report back to ExCo on the ECN study when completed.

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IEA Network of CCS Regulators. IEAGHG assisted IEA to establish this Network. IEAGHG contributed to the third edition of the IEA Legal and Regulatory Review published in July 2012. All this material and information from the IEA Regulators Network is available at: http://www.iea.org/topics/ccs/ccslegalandregulatoryissues/ieainternationalccsregulatorynetwork/ .No activity this period. The next meeting will be in June 2013.

• London Convention. The annual meeting was 29 Oct – 2 Nov in London. This was its 40th anniversary of protecting the marine environment. One of the highlights mentioned was how the London Convention reacted to the threats of climate change and ocean acidification by amending the London Protocol in 2006 to allow and control CO2 geological storage for carbon dioxide capture and storage. Also to celebrate this week, the revision of the 'CO2 Specific Guidelines' to take into account transboundary migration of CO2 was completed and adopted after 3 years of work. This completes part of the work required for transboundary CCS since the CO2 export amendment in 2009. The other part to be completed regards export of CO2 for CCS. While we wait for that amendment to come into force through ratification, the remaining work will look at guidance on the permitting arrangements and agreements which will be required between countries for this export of CO2. IEAGHG has been involved throughout the London Convention’s work on CCS since 2004. IEAGHG continues to be involved, contributing directly to the work to revise the Guidelines to cover all transboundary CCS activities (working with the IEA CCS Unit). By coincidence, IEAGHG spoke in the plenary on the day of the 40th anniversary celebrations, providing its usual update on IEAGHG work relevant to CCS in the marine environment. For more information see http://www.imo.org/MediaCentre/PressBriefings/Pages/46-london-convention-.aspx

Korea is the lead of the working group on transboundary, and IEAGHG (Tim Dixon) are members and contributing in this working group. The results of the Annual Meeting were reported by email to ExCo members on 2nd November 2012 and at the 42nd ExCo and on the IEAGHG blog. Work may continue at the Scientific Group meeting 27-31 May 2013 in Buenos Aires, and will continue at the Annual London Convention meeting in London on 14-18 Oct 2013 in London.

• CCSA. IEAGHG (Tim Dixon) participates in the International Mechanisms Working Group (formerly Post-2012 Working Group). IEAGHG (Tim Dixon) is also an observer in the CCSA Working Group on R egulation. IEAGHG participated in the Regulatory WG in December 2013, specifically to learn of the ROAD project’s experiences with permitting from a technical perspective.

• EU CCS Demonstration Network. IEAGHG participated in the EU CCS Project Network Advisory Forum when it was run by DNV. The Global CCS Institute has taken this on. No activity by IEAGHG over this period.

• Clean Energy Ministerial (CEM) CCUS Action Group. From 2011 IEA and GCCSI now provide secretariat to the CCUS AG. For the CEM meeting in April 2013, a new work stream is being organised on industry CCS, involving IEAGHG and CCSA, and a proposed work stream on storage capacity assessment for developing countries and multilateral-development banks. More information can be found at: http://www.cleanenergyministerial.org/CCUS/index.html .

• ISO TC265 on CCS. In 2011 the ISO agreed to develop standards on CCS, covering the whole chain from capture to storage. There are currently 16 participating countries, 10 observer countries, and six liaison organizations. The second meeting of the ISO Technical Committee on CCS, TC-265, was held in Madrid in February hosted by AENOR. The meeting defined the scope of the work to be undertaken, and agreed the

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GHG/13/06

leadership of the five working groups as: Capture – Japan; Transport – Germany; Storage - Canada and Japan; Quantification and Verification – China and France; and Cross-cutting issues – France and China. A call for experts to populate these working groups from ISO members will be launched. It was acknowledged that the Canadian standard on Geological Storage of Carbon Dioxide (CSA Z741), which was developed as a bi-national standard with the USA, will provide a useful reference for the Storage working group. IEAGHG is a Liaison Organization to TC265, and at the meeting Tim Dixon presented an update on IEAGHG work and reports that will be relevant to the future work of TC-265, including on CCS terminology. The next meeting is likely to be in around six month’s time, possibly in Beijing. More information is available in paper GHG/13/12.

The 2013 International CCS Summer School will be hosted by the University of Nottingham, UK. The dates agreed are 21 to 26 July 2013. Work is now underway to organise this. The call for students resulted in 137 applications for the 60 places. The 2014 Summer School is due to be hosted in North America. Two American universities expressed interest, but only one provided a solid offer, and so the University of Texas was chosen to host in 2014. A formal offer of hosting was received from TNO to host the Summer School in 2015 o r 2016, on the island of Aruba in the Dutch Antilles, with a South American emphasis. This is to be discussed at the 43rd ExCo and more information is provided in paper GHG/13/22. Following the success of the CO2QUALSTORE project IEAGHG was invited to join a new Joint Industry Project (JIP) called CO2RISKMAN. 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. Sam Neades, Prachi Singh and Mike Haines provided input for IEAGHG. The Guidance is now finished and published in February 2013. A presentation will be given at the ExCo, and information in paper GHG/13/15.

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/13/32.

c) Facilitating international collaboration International Research Networks There have been no network meetings since the 42nd ExCo. Reports from the network meetings in 2012 have been published: Summary Report of the 3rd IEAGHG Social Research Network Meeting , IEAGHG 2013-01; Building Knowledge for Environmental Assessment of CO2 Storage: Controlled Releases of CO2 and Natural Releases Workshop, IEAGHG 2013-02; Summary Report of the 2nd Joint Networks Meeting, 2013-03. The presentations given at all these workshops and the reports have to date been hosted on the website: http://www.ieaghg/org.

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Practical R&D Activities. IEAGHG is no longer directly participating in any EU supported practical R&D projects. IEAGHG does provide indirect support in an advisory capacity to the Mustang, RISCS, QICS 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 has incorporated the results into a Best Practice Guide. Tim Dixon represents IEAGHG on t he management committee and Neil Wildgust was on the Technical Committee. The Best Practice Guide was published in time for GHGT-11. Communication activities Website. We now have 1968 members of the website, an increase of just over 150 new members on the 2nd We have now changed the way we contact website members, in order to avoid email blacklist issues, we now use Mailchimp to send mass communications to registered members, this allows us to offer an unsubscribe option and also to monitor bounce backs from now defunct email addresses, as a result we have been able to remove these from the website membership cleaning it up a nd giving a more accurate indication of active members During the period 21/08/2012 and 21/03/2013 we have had 26,875 visits with 81,858 , pages viewed from 16,487 different visitors, taking into account the different reporting period, this is a slight increase on the previous reported figures. 30% is direct traffic, % fro m search engines and 15% from referring sites. The average visitor spends 2.05 minutes on the site. The table below shows the breakdown of the location of our visitors.

Country/Territory Visits

Pages / Visit

Avg. Visit Duration

% New Visits

1. United Kingdom 5,055 2.82 00:02:48 59.58%

2. United States 3,084 2.90 00:01:50 67.80%

3. Canada 2,075 2.30 00:04:03 28.19%

4. Japan 1,523 3.66 00:03:14 38.80%

5. Germany 1,413 3.57 00:02:45 52.72%

6. Norway 1,263 3.29 00:02:23 40.86%

7. Australia 1,188 3.00 00:02:25 58.59%

8. France 1,112 3.79 00:03:03 50.18%

9. China 905 3.45 00:04:38 61.88%

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10. Netherlands 732 3.28 00:02:14 59.70%

A review of our website requirements and functionality has been carried out with the following issues considered. Following on from the successful re design and launch of the IEAGHG website in Jan 2011, and in recognition of the importance of the site as a communications tool, we are aiming to develop the site and continue to improve functionality and the services we can provide. The website currently uses the open source content management system (CMS) Joomla; this is subject to regular coding updates that we need to keep abreast of, with major changes every 12-18 months. Our alternative to this would be a bespoke CMS which would be an expensive initial outlay, and any updates/improvements would also be costly and has the additional risk should the company providing the CMS stop supporting the system or close we would be left having to start again. The next major release of Joomla is due in September 2013 and we plan to upgrade the website in line with this release. Updates are required as the older versions will no longer be supported and become a security risk as well as allowing us to refresh the site regularly and add new functions. We will also be able to incorporate new flexible templates that will improve the viewing on mobile devices. The website is currently hosted with Rochen on a shared server. As the amount of documentation on the site is rapidly expanding, we are now towards our limit of the 15GB space available. The solution to this is to move to a Managed Virtual Server (MVS) which will increase our space to 30GB and will also make the site more secure. This will represent an increase in costs from £55 to £95 per month - this task has now been completed In order to ensure the site complies with the new EU ruling regarding the use of cookies on the site, we will add a function to notify users on the use of cookies and allow them to decline the use – although as with most sites that have any form of login, this will render the site almost useless to any user opting out of the use of the cookies. In an effort to improve the visibility of the site, several steps are being taken to improve the Search Engine Optimisation (SEO), this includes changing page content, analysing link data and several coding changes. One important issue we have outlined for change is the use of our databases. Currently there are several task lead databases all very insular, the aim is to combine and automate these with the use of a Customer Relationship Management system (CRM), this is allow us to use the information we have more effectively and efficiently. To complete the tasks above, the Joomla update, cookie notification and CRM integration with the website will be handled by a Website Development Company, a CRM system will be purchased and IEAGHG staff will undertake the SEO work and move to MVS. As per member’s requests, all IEAGHG reports over 6 months old are now available on our website as an open source resource at: http://www.ieaghg.org/index.php?/20100119173/technical-reports.html. Greenhouse News The move from printed to electronic only copies has now been confirmed with the quarterly newsletter. The printed version in January 2013 was the final newsletter to be printed, and all future issues will be electronic only. This decision was made due to falling print numbers, and escalating print costs, which meant that the economic viability of a printed newsletter was reducing month on month.

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The electronic version will cut production timescales considerably, as well as removing several operational constraints relating to the print process. We h ope that this means the articles will be more current, timely, and we will have the opportunity of producing a newsletter more often if appropriate. Once again, 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. - For updates on our conference, please refer to paper GHG/13/23 International Journal on Greenhouse Gas Control (IJGGC). There has been a turnover of Associate Editors, Drs Ziqui Xue and Olav Bolland have left and has been replaced by Prof Paitoon Tontiwachuul, Univ Regina and Charles Jenkins of CSIRO. A sixth Associate Editor Dr Carlos Abanades of CSIC, Spain has also been added. Information Dissemination developments

• Social Networking. We continue to remain current and up to date on social media, and have maintained our blog updates, albeit to a l esser extent since GHGT-11 but this will increase again in the near future. We have established a LinkedIn group, that will allow us to publicize reports and conferences to a w ider audience, and further promote IEAGHG as an impartial source of insightful information.

• Animations & Videos. The Key Messages study is due to be published before May 2013, and once this has been sent out, then the question of animations and videos will be revisited, although it would likely need to be sourced externally to IEAGHG to maximize effectiveness..

• IEAGHG Blog. The IEAGHG Blog is making more progress, with few submitted blogs from non-IEAGHG staff. Members are encouraged to suggest ideas for the blog, and to write and submit entries for it on subjects they deem relevant. The GHGT Blog was used throughout the conference, with over 200 hi ts a day being recorded. The blog also generated comments, and was generally very well received. Toby Aiken blogged throughout the day on sessions, keynotes and other topics, and this is something that will be repeated for future conferences.

• 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.

• Information Papers – Our information papers continue to be very well received, and members are encouraged to continue to suggest topics for them.

• Annual Review – The Annual Review for 2012 has been completed, and will be circulated to members at the ExCo for comments.

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• Highlights from Weekly News in Past 6 Months

• Adverse weather and climate change: There have been more reports in the news, and not just specialist news, but general news media regarding the impact of climate change and man’s impact on the climate and the link to adverse weather conditions. In recent months, there have been devastating wild fires across parts of Australia, and of course Hurricane Sandy hitting the US East Coast, causing damage some estimates put in the range of over $1billion. The Stern review highlighted an increase in severe and extreme weather as a potential impact of unmitigated climate change, and some fear that this is now coming to pass.

• Developments and new regulations starting to be applied: In recent months, there have been numerous stories of states in the USA and other countries establishing regulations over activities such as shale gas fracking. Such moves, if successful, will likely prove pivotal in the establishment of regulations covering climate mitigation options, and could be the spur needed to incentivise many other projects and mitigation options, including CCS.

• Kyoto second commitment period: Tim Dixon of IEAGHG was present at the COP negotiations as part of the UK delegation, and although the agreement was not as strong as it could have been, the meeting in Doha did move us as a community forward, and confirmed the second commitment period between 2013 and 2020. Whilst it is true that some parties are conspicuous by their absence in this agreement, the inclusion of many developing countries is a very strong positive note to take away.

• Increased focus on public outreach and acceptance / ownership: Public acceptance of CCS has long been recognised as a key issue in project deployment, and the Barendrecht incident has been established as a case study of how not to engage with the public. Numerous activities underway in many different countries are showcasing how, with the correct engagement, the public can learn to understand the positives of CCS, and how they can support project deployment. Examples such as the QICS project in Scotland, experimenting with CO2 release under the seafloor, had wide-scale local support, and local community engagement at a project in South Africa included activities such as the local community having the opportunity to name the project, and thus taking some form of ownership of the project, and feeling of involvement engenders positive sentiment, rather than negative objection.

• CCS Project Developments: As well as ongoing developments in the more well established projects such as Sleipner and Snøhvit, there have been further good news stories for CCS projects during 2012 w ith the Shell Quest project being announced in Canada, Gorgon in Australia and FutureGen2 all sharing in the positive news. As well as these, construction work was started on the SaskPower Boundary Dam project; the world’s first integrated large scale post combustion capture plant combined with deep saline formation storage. Work is expected to complete some time in 2013, so this time next year, expect more news on this and other projects.

• Other Emissions Reductions / Novel Energy Developments: A recurring theme through the weekly news has been developments relating to other methods of emissions reductions. Novel methodologies such as Metal Organic Frameworks (and others reported in IEAGHG Information Papers) are of interest and will continue to be reported as and when appropriate. The developments in shale gas technology are also of note, with several regions / US states proceeding and even

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implementing legislation controls in order to facilitate operations. Again, these will continue to be monitored by IEAGHG and developments

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

2013

Programme Activities & Highlights (A Short Overview) IETS ExCo Meeting Stanley Santos 21 March 2013

Closure Requirements for CO2 Storage Sites in the Clean

Development Mechanism

CO2 CARE Annual Scientific

Conference, Utrecht Tim Dixon 12 March 2013

Global Status of CCS SwedSTORECO2 Seminar,

Sweden John Gale/Tim Dixon 5 March 2013

The Wider Impact and Deployment of CCS - a perspective from

IEAGHG

Westminster Energy Forum,

London Tim Dixon 28 February 2013

International Status of CCS CLIMIT Summit 2013, Sweden John Gale 25-26 February 2013

Carbon Dioxide Capture and Storage - International Legal and

Regulatory Developments and Carbon Accounting

EU and National Climate

Change Law LLM. Edinburgh

Law School.

Tim Dixon 25 February 2013

Challenges to Demonstration - What is the Current Status to

the Development of Oxyfuel Combustion Technologies

2nd Flexiburn Workshop, Spain Stanley Santos 6 February 2013

International Legal and Regulatory Developments and Carbon

Accounting

UKCCSRC Winter School,

Edinburgh Tim Dixon 11 January 2013

CCS: A Look Ahead

UKCCSRC Winter School,

Edinburgh Tim Dixon 11 January 2013

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Title Meeting Presented by Date

2012

Study Programme Highlights 63rd WPFF Meeting John Gale 6-7 December 2012

CCS Recent Transboundary Developments

Tim Dixon December 2012

UK CCS Programme and CCS Transboundary Developments COP 18, Doha Tim Dixon 04 December 2012

Carbon Dioxide Capture and Storage in the Iron and Steel

Sector

COP-18, Doha Tim Dixon & Stanley

Santos 03 December 2012

IEAGHG International CCS Summer School Series COP-18, Doha Tim Dixon 27 November 2012

Energy Efficient Solvents for CO2 Absorption from Flue Gas:

Vapour Liquid Equilibrium and Pilot Plant Study

GHGT-11, Japan Prachi Singh November 2012

Getting science into International Climate Policy: CCS in the

UNFCCC

GHGT-11, Japan Tim Dixon/Samantha

Neades November 2012

Techno-economic study of an integrated steelworks equipped

with oxygen blast furnace and CO2 capture

GHGT-11, Japan Stanley Santos November 2012

Challenges to the Deployment of CCS in the Energy Intensive

Industries (Part2: Cement Industry Sector)

IEA-MOST Joint Workshop Stanley Santos 16 October 2012

Challenges to the Deployment of CCS in the Energy Intensive

Industries (Part1: Iron and Steel Sector)

IEA-MOST Joint Workshop Stanley Santos 16 October 2012

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http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/GHGT11_L._Hooey__S._Santos.pdf�

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/GHGT11_L._Hooey__S._Santos.pdf�

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Cement_Industry__CCS_-_Overview_S._Santos_-_IEAGHG_-_Final.pdf�

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Cement_Industry__CCS_-_Overview_S._Santos_-_IEAGHG_-_Final.pdf�

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Steel_Industry__CCS_-_Overview_S._Santos_-_IEAGHG_-_Final.pdf�

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Steel_Industry__CCS_-_Overview_S._Santos_-_IEAGHG_-_Final.pdf�

GHG/13/07


MEMBERSHIP ISSUES/NEW MEMBERS

The IEA Greenhouse Gas R&D Programme (IEAGHG) currently has 44 members. S cottishPower having dropped out as a sponsor during the year. Two further sponsor members: EoN and ENEL have informed us they will not continue as members and will their membership will end as of 31st March 2013. We were optimistic after GHGT-11 that Masdar would re-join but this has not happened and now looks unlikely. Qatar Petroleum have indicated their desire to join we are awaiting confirmation that their internal approval procedures have been completed. The position re India as reported at the last ExCo Meeting remains unchanged.

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GHG/13/08


FINANCIAL UPDATE 2012/13

To date we have received 10 sets of management accounts for the 2012/13 financial year from the accountants. Based on IEAGHG’s analysis of the financial data received we expect to make a sm all (~£50K) surplus of income over expenditure. A meeting is due to be arranged shortly to hold an end of year financial appraisal with the accountants to discuss the end of year out turn. We expect that meeting to be held ahead of the ExCo which will allow us to report to members at the meeting.

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GHG/13/09


BUDGET 2013/14

At the time of writing of the papers only an outline budget has been prepared. Between the publication of the ExCo papers and the ExCo meeting a budget will be developed, agreed with EPL and the Chair/Vice Chairs and circulated to members. The budget proposal will be presented at the ExCo meeting for member’s approval.

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GHG/13/10


PROPOSED CHANGES TO IA AND ANNEX 1

The proposed changes to the IA and Annex 1 have been identified in discussion with the Chair. The process of drafting the text to cover these changes will take place before the ExCo and the proposed revised text presented to members at the ExCo meeting.

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GHG/13/11


UNFCCC COP-18 and COP-19

COP-18 was held in Doha, Qatar, with approximately 9,000 de legates from over 194 countries. One of these was IEAGHG’s Tim Dixon as part of the UK DECC delegation. COP-18 High Level Outcomes COP-18 and CMP-8 concluded with an agreement for a second Commitment Period for the Kyoto Protocol. This will run from 2013 to the end of 2020. This entails new legally-binding emissions commitments for the developed countries agreeing to it under the Kyoto Protocol, notably the 27 EU Member States, Australia, Norway, and Ukraine. Developing countries are also included, but without emission targets. The emissions targets of 18% reduction from 1990 to 2020 a re not high enough and not on s ufficient countries to significantly reduce global emissions to avert dangerous climate change. Some major emitting developed countries will not be included, specifically USA, Canada, Japan, Russia and New Zealand. However this is still significantly better than having no second Commitment Period and no countries with any emissions targets. Whilst many think the emission targets for individual countries are set too low, this does keep the global framework for emissions reductions and emissions trading mechanism (e.g. the CDM) operational while countries make progress on t he Durban Platform for Enhanced Action (ADP) towards a legally-binding agreement for 2015 for all 194 UNFCCC countries (including USA and China). There is also some limiting of the carry-over of AAUs (hot-air). A new issue appeared in the high level negotiations on recognition by developed countries for ‘loss and damage’ to developing countries as a result of climate change . CCS outcomes Two sets of SBSTA negotiating meetings took place on t he transboundary projects and Global Reserve of CERs issue. Text was agreed that consideration of both is to be postponed until SBSTA-45 (i.e. 2016) to allow time to learn from CCS projects in the CDM. Whilst this isn't a bad result in itself for the time-being (very few wanted the Global Reserve and there were good arguments against it) it isn't as good as the initial version proposed by the Chairs which would have removed the Global Reserve permanently, recognising the adequacy provided by the existing modalities and procedures (also described as "providing robust environmental protection" by many here). Some observers expressed disappointment at the two CCS issues on t ransboundary and Global Reserve being deferred for four years, not realising that the resolution of transboundary issues was always likely to take some time. For example, the London Convention, a large treaty which moves faster than UNFCCC because of its decision-making design and its double pressure of ocean acidification as well as climate change, still took three years after the major CCS amendment to reach a legal transboundary CCS amendment and another three years to make any further progress on t he outstanding transboundary issues.

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GHG/13/11

The Decision from SBSTA on the two CCS issues was to defer any further consideration of transboundary projects and of a Global Reserve until SBSTA 45 (expected 2016). The final text adopted by CMP-8 on CCS in CDM was as follows: “Welcomes the work undertaken by the Executive Board to adopt relevant documents regarding carbon dioxide capture and storage in geological formations as clean development mechanism project activities; Decides that the eligibility under the clean development mechanism of carbon dioxide capture and storage in geological formations project activities which involve the transport of carbon dioxide from one country to another or which involve geological storage sites that are in more than one country and the establishment of a g lobal reserve of certified emission reduction units for carbon dioxide capture and storage in geological formations project activities shall be considered by Subsidiary Body for Scientific and Technological Advice at its forty-fifth session; Also decides that while carbon dioxide capture and storage in geological formations project activities which involve the transport of carbon dioxide from one country to another or which involve geological storage sites that are in more than one country would merit inclusion under the clean development mechanism, more practical experience of carbon dioxide capture and storage project activities in geological formations under the clean development mechanism would be beneficial;” Technology Mechanism The Technology Mechanism was partly operationalised, with the appointment of a consortium lead by UNEP to operate the Climate Technology Centre and Network (CTCN) for five years. It is anticipated that CCS will be included in the range of technologies assisted by this network. CCS on the side Although CCS negotiations concluded in the first week, there was a lot of other activity on CCS at this COP. There were four 'official' UNFCCC Side-events on C CS and four 'unofficial' events. IEAGHG spoke at five, specifically on the CCS Summer School, on the work on CCS for the Iron and Steel sector, on t ransboundary developments (including the UNFCCC report on transboundary issues and its gaps), and on UK Department of Energy and Climate Change policy for the UK Programme, on Science in policy making, and on knowledge transfer. By comparison at Durban there was only one 'official' Side-event on CCS (ours). The UNFCCC Side-event of CCSA/University of Texas/IEAGHG on CCS Education on the first Tuesday went well, was well attended (apparently the most of any CCS event here) and with a high level of interest. Especially interesting at other Side-events were the talks by Qatar, UAE and Saudi Arabia on their CCS project activities, with several pilot projects now in development in the region, supported by R&D programmes. Bio-CCS continues to gain prominence and interest, and the IEAGHG studies in this area are proving a valuable resource. The need for information on CCS was demonstrated both in the negotiations (e.g. where one negotiator questioned the basic risk, safety and uncertainty of CCS) and at the booths of CCS-related organisations which have been more popular than ever being visited by those seeking information on CCS. The University of Texas, CCSA and the International Energy Agency collaborated with IEAGHG in sharing our information at their booths.

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GHG/13/11

There was also a media-release by seven green NGOs (ENGOs) who, funded by the Global CCS Institute, collaborated to produce a p aper advocating actions to encourage CCS (see http://www.engonetwork.org ). CCS Outside Also in Doha, the COP-18 Reception was held at the Qatar Sustainability Expo. Of interest were several displays on CCS, including an impressive ‘CCS elevator’ by Shell and the Qatar Carbonate and Carbon Storage Research Centre (with some video content from IEAGHG). Of note was an interesting car from Saudi Aramco which is their project to capture CO2 from vehicle exhausts. Fully operational for 2,000km so far, capturing 10% of the CO2, the plan is to increase the capture rate to 60%. Conclusions The world of climate change mitigation took significant steps forward, and CCS is now embedded as a validated option to reduce emissions in both developed and developing countries. Much work is still to be done, and experience to be gained, and capacity to be built, but the building blocks for climate change mitigation are in place and prospects for CCS exist within all of them. COP-19 COP-19 will be held on the 11-22 November in Warsaw. Work will continue there on the ADP and various mechanisms and funds existing under the Kyoto Protocol 2nd Commitment Period and proposed for ADP. Whilst there will be no formal workstreams or negotiations dedicated to CCS, the UNFCCC secretariat will continue to operationalise the CDM for CCS project applications (following their survey at Doha), and it is envisaged that there will be a continuing demand for information on CCS as a significant mitigation option to be included within the various mechanisms and funds. A planning meeting for CCS activities at COP-19 will be held by CCSA in the week of 29 April, IEAGHG will attend.

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http://www.engonetwork.org/�

GHG/13/12


ISO Progress

ISO TC265 on CCS. In 2011 the ISO agreed to develop standards on CCS, covering the whole chain from capture to storage. The agreed objective for ISO/TC 265 is to prepare standards for the design, construction, operation, environmental planning and management, risk management, quantification, monitoring and verification, and related activities in the field of carbon dioxide capture, transportation, and geological storage. The intent is that the International Standards will include all aspects related to the capturing of CO2 from large stationary point sources to storing it in suitable underground formations so as to prevent it from entering the atmosphere. However excluded from the work of the ISO/TC 265 will be: ocean storage of CO2 by direct injection; mineral carbonation storage; industrial uses of CO2 not related to CCS; capture and storage by forest and forest products; and legal liability and permitting. There are currently 16 participating countries, 10 obs erver countries, and six liaison organisations. 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 2012, and went to the TC265 for approval by remote voting. TC 265 s ecretariat is provided by Canada and China, with Canada chairing. IEAGHG (Tim Dixon) participated in the first meeting of the TC265 on 5-6 June in Paris, giving a presentation on the relevance of IEAGHG to TC265. Approval by TC265 members was confirmed after remote voting on 7 September. The second meeting of the ISO Technical Committee on CCS, TC-265, was held in Madrid on 4-5th February, hosted by AENOR. The meeting agreed the leadership of the five working groups as: • WG 1 Capture – Japan; • WG 2 Transport – Germany; • WG 3Storage - Canada and Japan; • WG 4 Quantification and Verification – China and France; • WG 5 Cross-cutting issues – France and China.

TC265 considered and discussed the overall plans, overall scope, the proposed document types to be produced and the draft scopes of the work to be undertaken by each of the working groups. For WG 1 Capture, the proposed scope of work will be to produce first a Technical Report on carbon dioxide capture systems, technologies and processes. Then to work to produce standards on evaluation procedures for energy consumption and capture rate, sampling and analytical methods for carbon dioxide streams, process and waste products, on e valuation procedures for safety, on evaluation procedures for reliability, and on management systems.

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GHG/13/12

For WG 2 T ransport, the proposed scope will be based on e xisting standards for transportation of gaseous or liquid media and will define additional requirements or recommendations for CO2 transportation by pipelines. Existing pipeline standards, like those from ISO TC 67, CEN TC 234 will be considered. CO2 transportation by ship, road, or rail is excluded in this standard and will be elaborated in future work.

For WG 3 Storage, the proposed scope is for onshore and offshore storage, and is primarily applicable to saline aquifers and depleted hydrocarbon reservoirs but does not preclude its application to storage associated with enhanced oil recovery. It was acknowledged that the Canadian standard on Geological Storage of Carbon Dioxide (CSA Z741), which was developed as a b i-national standard with the USA, will provide a useful reference for the onshore considerations of WG 3. For WG 5 C ross-cutting issues, the proposed ideas for the scope of work are to cover terminology, system integration, overall HSE and risk, stakeholder engagement, reporting and crediting, mixing of CO2 streams, and CCS ready. There was discussion about duplication with other WGs and redundancy of items, and the scope is still very much under development. There was brief discussion on WG 4 Quantification and Verification, the leadership was still being decided at the meeting.

IEAGHG (Tim Dixon) attended and presented an update on IEAGHG work and reports that will be relevant to the future work of TC-265, including on C CS terminology. The next meeting is likely to be in around six months time, possibly in Beijing.

Calls for experts to populate the working groups from ISO members are being opened. WG1 Capture opened a call for experts on 13th March (no deadline). WG 2 Transport opened a call for experts on 13th March (no deadline) and announced the first meeting of WG 2 on 11-12 June at DVGW in Germany. WG 3 Storage and WG 5 Cross-cutting issues opened their calls for experts on 18 March (no deadline). Nominations have to come from a member country or a Liaison organisation. IEAGHG is considering the appropriate level of involvement in the WGs.

The public information on the work is available at http://www.iso.org/iso/iso_technical_committee?commid=648607 .

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GHG/13/13


SHALE GAS GREENHOUSE GAS FOOTPRINT REVIEW

Background A discussion note was prepared in-house in response to concern resulting from publication in the USA of an academic paper claiming that methane emissions arising from the production of shale gas could be sufficient to make unconventional natural gas from that source more greenhouse intensive than coal. This discussion note was presented at the 40th ExCo. It identified that there is a shortage of representative public domain data on the shale gas industry and conflicting claims of appropriate assumptions, and developed a simple framework for carrying out full fuel cycle analyses. It was agreed to publish this work as an IEAGHG Technical Review. This has been undertaken by Steve Goldthorpe. Since then, more work on the environmental impacts of unconventional gas has been published by others. This new work has been reviewed each time and taken-into account in the preparation of this Technical Review. The Technical Review was completed and published in March 2013, as ‘Shale Gas Greenhouse Gas Footprint Review’, IEAGHG 2013/TR1, March 2013. It is proposed to present this final report to members using a webinar. The timing of the webinar is expected to be in the summer of 2013, while Steve Goldthorpe will be working from IEAGHG offices (he is based in New Zealand). The Executive Summary of the report is provided here for information.

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GHG/13/13

SHALE GAS GREENHOUSE GAS FOOTPRINT REVIEW

Executive Summary

This analytical review was originally prepared as a d iscussion note for the executive committee of the IEA Greenhouse Gas R&D programme in response to concern resulting from publication in the USA of an academic paper claiming that methane emissions arising from the production of shale gas could be sufficient to make unconventional natural gas from that source more greenhouse intensive than coal. S uch a c laim runs counter to the conventional wisdom that converting an application from coal to natural gas invariably results in a reduction in the greenhouse gas (GHG) emission consequences of the application, particularly so for power generation.

This review has identified that there is a dearth of representative public domain data on the natural gas industry in general and on the shale gas industry in particular, with conflicting claims of appropriate assumptions. To assist with understanding the issues, a model has been developed for carrying out Full Fuel Cycle (FFC) analyses and a methodology has been developed to accommodate uncertainty. This model has been populated with illustrative data. This review has been prepared for IEAGHG as a T echnical Note to share with a wider readership with the intent of providing a framework for discussion of the impact on G HG emissions from Natural Gas production.

This issue is set against an on-going background of disagreement between environmentalists, academics and the shale gas industry, particularly in the USA. T hat disagreement is principally focused on incidents of adverse impacts on groundwater quality and community amenity attributed to hydraulic fracturing (fracking). T here are some jurisdictions, in the USA and elsewhere, that have imposed a moratorium on the use of that enabling technology pending a better general understanding of the associated environmental issues.

Although fracking for shale gas production is the focus of this study, the wider issues involved in comparing the FFC emissions from coal and gas fired power generation apply also to conventional gas production. T he recent upsurge in the global use of natural gas, particularly in the USA, has given rise to increases in Liquefied Natural Gas (LNG) transportation of gas, the application of carbon capture and storage (CCS) to gas fired power generation and concerns about the global warming potential of methane. These wider issues are considered in this report.

Findings

The only significant difference identified between shale gas production and conventional gas production from a GHG perspective arises from the additional emissions associated with the fracking process at the well-site. Those additional emissions comprise methane as natural gas losses from the returning fracking fluid and CO2 from the additional use of diesel in drilling and pumping equipment with lesser effects attributable to the liquid unloading process. The other precombustion GHG emissions associated with natural gas supply to power stations; i.e. processing losses and transmission losses, as well as the combustion emissions, are independent of the technology used to produce the gas at the well site or the geological origins of the gas.

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GHG/13/13 Using reference case default assumptions, as discussed in detail in Appendix A, the well site GHG emissions from a shale gas operation are about 39% greater than from a conventional natural gas well. The corresponding overall precombustion GHG emissions from shale gas, including processing and distribution are about 17% greater than the equivalent precombustion GHG emissions from conventional gas. Since the combustion GHG emissions are also the same regardless of the source of the gas, the FFC GHG emission for shale gas are 2.7% greater than conventional gas FFC GHG emissions.

When precombustion emissions are taken into account, the 50% saving in combustion GHG emissions attributable to selecting natural gas instead of coal for a new base load power station is reduced to a 45% saving in the case of conventional gas or to a 43.5% saving when the gas is sourced from shale with fracking. The precombustion emissions add about 8% to the combustion emissions from coal fired power generation, whereas the precombustion emissions add about 18% (conventional) and 21.5% (shale gas) to the combustion emissions from gas fired power generation. These FFC GHG emission assessments are made on the basis of the default assumptions that are detailed in Appendix A. The reference cases use the Global Warming Potential (GWP) value of 25, no transport of natural gas as LNG, a low concentration of CO2 in the source gas, minor migration of gas from wells and no application of CCS.

There is on-going debate about the appropriate GWP value for methane. The IPCC fourth assessment report defined values of global warming potential as 25 when considered over a 100 year time horizon and 72 when considered over 20 years. The IPCC also noted but did not quantify an aerosol effect, which might increase the GWP of methane to 105 over the 20–year timeframe. T able ES1 shows the impact of an elevated GWP factor on methane emissions from both natural gas production and coal mining.

Table ES1 – Impact of GWP on FFC GHG emissions from power plants

Kg CO2-eq/MWh (saving compared

with coal)

NGCC with shale gas

NGCC with conventional natural gas

Supercritical coal power plant

GWP = 25 460 (43.5%) 448 (45.0%) 814

GWP = 72 539 (39.0%) 511 (42.1%) 883

GPW= 105 595 (36.1%) 556(40.3%) 931

Conventional natural gas transmission is by pipeline. Own use of gas for booster compressors and pipeline losses are included in the assessment. However, there is increasing international trade in natural gas in the form of LNG, which incurs substantial own use of gas. Inclusion of LNG in the gas supply train would reduce the GHG emission saving from 43.5% to 36.2% for shale gas and from 45% to 37.8% for conventional gas.

If the natural gas resource contains significant CO2 its GHG footprint will increase. T he increase will normally be small, but the exceptionally high CO2 content of Natuna gas (71%) would give power generated from that gas exactly the same GHG intensity as p ower generated from coal under the default assumptions of this study.

The migration underground of gas from wells that have a loss of well integrity, resulting in methane discharges to air, is difficult to quantify and is seldom monitored. A small contribution due to migration of gas from both conventional gas wells and shale gas wells is

44

GHG/13/13 included in the default assumptions. However, emission of migrating gas at a higher rate that would not present a local environmental or safety issue could be a major contribution to the greenhouse gas footprint. T he possible contribution from gas migration is the largest component of the uncertainty assessments that have been modelled.

Complete offsetting of the GHG advantage of switching from coal to gas for base-load power generation would only occur under a worst case combination of factors. For example, if GHG emission calculations are based on the 20-year GWP of 105 (with aerosol effect) and LNG transport is included in the gas supply train then coal and gas would be equivalent when the additional unaccounted fugitive loss of gas from a shale gas well is 4% of raw gas production; or about 3% in the case of a conventional gas well. The potential impact of gas migration losses is more significant for conventional gas wells than for shale gas wells because of the longer lifetime of conventional wells.

Precombustion GHG emissions associated with upstream production of consumer fuels depend on a large number of variables that have a wide variability and uncertainty. The issue of uncertainty is addressed in this study by identifying a likely range for each of the assessment parameters discussed in Appendix A. A composite uncertainty range is then calculated as shown by error bars. Uncertainty ranges are proposed in the detailed assessments presented in Appendix A. The composite uncertainty indicates that the indicative precombustion emission estimates under the default set of assumptions are -40% to +60% for shale gas; -40% to +140% for conventional gas; and +/-60% for coal. The higher upper uncertainty bound for conventional gas is due to the possibility of higher potential migration losses.

The GHG footprint of power generation can be reduced by the installation of CCS on t he power station to reduce the combustion emissions. H owever, the precombustion GHG emissions are not amenable to reduction with CCS and are actually increased because more fuel is required to accommodate the energy penalty of CCS. Hence, when considered on a FFC basis, the application of 90% CCS to an NGCC power plant burning shale gas would result in a net FFC GHG emission reduction of 70%. In the case of conventional gas the FFC GHG emission reductions corresponding to 90% CCS would be 72%. Using the assessment basis of this study, a coal fired power plant with 90% CCS would have a net FFC GHG emission reduction of 79%.

Conclusions

The IEA World Energy Outlook states “We estimate that shale gas produced to proper standards of environmental responsibility has slightly higher “well to burner” emissions than conventional gas.” The analysis in this study quantifies that elevation in overall GHG emissions attributable to fracked shale gas as 2.7%.

The 1:2 GHG advantage of gas over coal for base load power generation is partly offset when precombustion GHG emissions are taken into account. When the gas is sourced from shale with fracking, that GHG advantage of gas over coal would be reduced to 1:1.77.

There is major variability and uncertainty in the assessment of precombustion emissions. Under a worst case combination of circumstances the GHG advantage of gas over coal for power generation might be completely lost. One example is the use gas from the of Natuna gas field, which contains 71% CO2. Another example would involve the use of a high GWP factor combined with transport of gas as LNG and about 4% of production lost as fugitive emissions at a shale gas well site.

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GHG/13/13 Precombustion emissions also adversely impact the benefit of adding CCS to power plants because precombustion emissions cannot be captured. In the case of a gas fired based load power station, the installation of 90% CCS would yield an overall reduction in FFC GHG emissions of about 70%.

References

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API/ANGA (2012b) Characterising Pivotal Sources of Methane Emissions from Unconventional Natural Gas Production – API/ANGA. Revised September 21 2012.

Conoco (2007) Ransbarger W. A fresh look at LNG process efficiency. Conoco-Phillips. in LNG industry Spring 2007.

EIA (2010) http://www.eia.gov/naturalgas/reports.cfm?t=72 EIA (2012) http://www.eia.gov/pub/oil_gas/petrosystem/us_table.html GAO (2011) GAO-11–34 U.S. General Accountability Office. EIA, Washington DC. Griffin (2007) Comparative Life Cycle Air Emissions of Coal, Domestic Natural Gas,

LNG, and SNG for Electricity Generation. Paulina Jaramillo, W. Michael Griffin, H. Scott Matthews

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Howarth (2011). Howarth R., Santaro, R., and Ingraffea, A. (2011) Methane and the greenhouse-gas footprint of natural gas from shale formations – A letter. Climatic Change,106:679–690. March 2011.

IEA (2011) Are We Entering a Golden Age of Gas? – Special Report – IEA World Energy Outlook 2010

IEAGHG (2006) CO2 Capture as a Factor in Power Station Investment Decisions. IEAGHG 2006/8

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Upsteam Natural Gas Development, Private Report, IHS-CERA, August 2011

IPCC (1995) IPCC Second Assessment Report. 1995 IPCC (2007) http://www.ipcc.ch/publications_and_data/ar4/wg1/en/tssts-2-5.html Jaramillo (2007) Jaramillo, P., A life cycle comparison of coal and natural gas for electricity

generation and the production of transportation fuels. PhD thesis. Carnegie Mellon University. December 2007.

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CCS COSTS NETWORK

IEAGHG has helped to organise two workshops on costs of CCS, which were held at IEA, Paris in March 2011 and at EPRI, Palo Alto in April 2012, as reported at the 41st meeting. To ensure active discussion, the workshops were by invitation only and were attended by about 40 experts on CCS cost estimation. The workshops were 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). In April 2013 the steering committee will discuss whether further workshops on CCS costs would be worthwhile, and if so which topics should be covered. Progress of these discussions shall be reported at the ExCo meeting. One of the actions from the two costs workshops was to set up a sub-group to work toward a common methodology for CCS cost estimation. This sub-group was headed by Ed Rubin and included some other members of the workshop steering committee (John Davison, Chris Short, Clas Ekström and Sean McCoy), together with George Booras (EPRI) and Michael Matuszewski (DOE-NETL). In March 2013 t his group completed a White Paper entitled “Toward a Common Method of Cost Estimation for CO2 Capture and Storage at Fossil Fuel Power Plants”. Each of the member organisations of the sub-group intends to publish this document in its own covers; the IEAGHG version is “Technical Review 2013/TR2”. The White Paper shows that there are significant differences in the methods currently used by different organisations to estimate the cost of CCS systems for fossil fuel power plants. Many of these differences are not readily apparent in publicly reported CCS cost estimates, and the existence of such differences hampers rather than helps efforts to properly assess CCS costs and their relationship to other greenhouse gas control measures. Given the international importance of CCS as an option for climate change mitigation, efforts to systematise and improve the estimation and communication of CCS costs are thus especially urgent and timely.

The paper recommends a path forward to harmonize the various costing methods now in use, beginning with a common nomenclature (terminology) for CCS cost elements and the method of aggregating them to arrive at the total cost of a project. The recommended approach draws on the methodologies now used by IEAGHG, the Electric Power Research Institute (EPRI), the U.S. Department of Energy’s National Energy Technology Laboratory (DOE/NETL), and the European Zero Emissions Platform (ZEP). While these methods share many common features there are also notable differences that the Task Force has worked to reconcile.

Even with a common language, however, many of the details and assumptions required for a CCS cost estimate vary from one project to another and cannot be standardised. Thus, clear communication of key assumptions is essential for avoiding confusion and misunderstanding about the context for results of a given cost study. The paper identifies key areas where communication is especially important. This includes assumptions and definitions of the project scope and design parameters; financial and economic parameters; method of quantifying various cost elements; and methods to calculate overall cost values such as the increased cost of electricity and the cost of CO2 avoided. By way of guidelines, the paper presents “checklists” developed by the Task Force of information that should be conveyed in technical reports, journal-length papers, and conference presentations.

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As part of its deliberations, the Task Force also considered whether there might be value in future efforts in two areas: (1) further refinement of methods to estimate and report the cost of technologies currently in the early (pre-commercial) stages of development; and (2) compilation of a set of case study power plant and CCS system designs and cost-related parameter assumptions that can serve as b enchmarks for future cost studies of CCS technologies. Feedback is sought from the various audiences for (and sources of) CCS cost estimates regarding the value of these or other possible future tasks to promote a common approach to CCS costing.

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CO2RISKMAN

This Joint Industry Project (JIP) has now been completed to the point of issue of a Guideline (final version published in January 2013). The JIP was undertaken by DNV.

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The CO2RISKMAN Guidance document is intended to provide a non-prescriptive knowledge source to assist CCS projects to include CO2 stream aspects within the development/implementation of their hazard management procedures. The management of CO2 stream major accident hazards is only one part of the hazard management practices that will address relevant hazards and it is intended that this non-prescriptive document can be used by those responsible for delivering a safe and responsible CCS operation to develop their own fit-for-purpose hazard management strategy for their project. I t is hoped that the Guidance will help to promote open and honest engagement within and between CCS developers, their regulators and various stakeholders.

The Guidance is structured in a pyramid of four documents, as described in Figure 1. This arrangement of the information and four documents enables efficient access to the level of information that is sought. Level 1 is the Executive summary, 2 is an overview of Levels 3 and 4, Level 3 contains generic information on the topics specified within Figure 1 and Level 4 is the CCS link-specific guidance on hazard management. For ease of use, readers can navigate through the document quickly and efficiently, locating specific information, by using the pyramid legend which is located on every page.

Figure 1. Diagram to describe the Levels of the CO2RISKMAN Guidance document

The Guidance was developed within the DNV-led CO2RISKMAN Joint Industry Project (JIP) with support and active contribution from the following organisations: Air Liquide; AMEC; Chevron; Environment Agency; E.ON; Gassco AS; Gassnova SF; Global CCS Institute; Health & Safety Executive; IEA Greenhouse Gas R&D Programme; Institute for Studies and Power Engineering; Maersk Oil; National Grid; Petroleum Safety Authority; Scottish Environment Protection Agency; Shell.

Background to the Study

The CO2RISKMAN Joint Industry Project (JIP) was initiated and led by DNV to develop industry guidance that provides a comprehensive reference source to assist the emerging CCS industry

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appreciate, understand, communicate and manage the issues, challenges and potential hazards associated with handling CCS CO2 streams.

CCS requires the integration of distinct process activities to capture CO2 at an emitter point, transport it to designated storage sites and where applicable, inject it deep underground for permanent storage. CCS operations will range in complexity from simple point-to-point chains, storage site and interconnecting pipeline, to multiple capture plants feeding CO2 into a network of pipelines from which the CO2 is supplied to multiple storage sites. It is feasible (and likely) that each link in a CCS chain will be operated by different organisations and the chain links could be spread geographically across large distances (onshore and/or offshore).

The challenge facing the CCS industry is to take existing and new technologies, experiences and best practices, ensure their suitability for use in CCS, then integrate the many links in the chain to create an efficient and demonstrably safe operation.

The stream of CO2 from a capture facility to an injection point is a common aspect of CCS operations and is the extent of what is covered within the Guidance (capture to injection only). The content of the stream will expectedly be mostly CO2, but there will usually be small amounts of impurities present, such as nitrogen, nitrogen oxides, sulphur oxides, water, hydrogen and oxygen. The impurities (and the amount of each substance) present will depend upon a number of factors such as the source of the CO2 and the capture technology being used – and impurities levels can be affected by a process upset or failure upstream. In terms of scale, the amount of CO2 that will be handled in a commercial CCS operation will be in the order of hundreds or thousands of tonnes of CO2 per hour.

Many areas of CCS have been tried and tested, but there are aspects that are new or untested. This sustainable industry is currently progressing through a steep learning curve and many demonstration projects are being delivered to continue learning, whilst making the subsequent step into commercial operations a less significant one.

Within the area of hazard management, the handing of large quantities of CO2 will be quite new to specialists in the area. Like many other substances handled in large quantities, CO2 could pose potential harm to people or the environment if a significant leak was to occur. The CO2RISKMAN Guidance tries to raise the awareness of important aspects relating to the CO2 stream that may cause or contribute to a major accident.

Although it focusses on the CO2 stream, the CO2RISKMAN Guidance is not inferring that these hazard risks are more common, more significant or more difficult to manage than the risks from other industrial hazards.

CO2 Stream Aspects

Some of the main aspects recognised by the DNV CO2RISKMAN Guidance relating to the CO2 stream that need to be considered and addressed (where appropriate) within the overall hazard management process applied across the CCS chain are described below.

Inadequate hazard appreciation: Until CCS becomes an established industry with industry-accepted design and operation standards, recommended practices and accredited competency development schemes, it is possible that actions may be taken during the lifecycle of the operation that could have a detrimental effect on the value of the hazard management of the CO2 stream. Competence

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development and the application of existing hazard management procedures will reduce the likelihood of this.

Integrity threats: The CO2 stream and any impurities in this stream have characteristics that may raise the likelihood of leaks within the system. Such characteristics include material incompatibility, internal corrosion, low temperature and solid CO2 formation and thermal expansion, described in more detail below:

- Material incompatibility may come from lubricants and materials (e.g. elastomers) used that could be broken down by CO2 (liquid CO2 is a solvent that may break down certain lubricants and CO2 can be highly invasive, capable of dissolving into some elastomers), so it is important that care is taken when selecting lubricants etc.

- The rate of internal corrosion may be increased by the presence of impurities in the CO2 stream, as CO2 in combination with free water will form carbonic acid – highly corrosive to carbon steels. The key to avoiding such corrosion is the control of the water content within the CO2 stream. A dehydration plant within the capture plant may be required and a robust inspection programme would also reduce the likelihood of a leak.

- The depressurisation of CO2 (by design or by accident) can result in temperatures (within the system or within a r elease plume) at or below -78°C, the sublimation temperature of solid CO2 . Significant quantities of solid CO2 can be formed within the systems, which may add to the low temperature issue, causing blockages within the system. The system design and operation should therefore adequately address the low temperature potential of a CO2 handling system, to avoid the formation of solid CO2 creating a hazard.

- Thermal expansion may occur as CO2 density is sensitive to temperature changes, which can lead to such system overpressurisation with a small change in CO2 temperature. System pressure relief should therefore be implemented to avoid this leading to a hazard.

Mixture phase behaviour: The presence of low levels of impurities within the CO2 stream can result in significant changes to the CO2 phase envelopes. Models used (in process and release modelling) need to be able to predict the phase envelopes for the range of mixtures that are likely.

Inhalation effects: CO2 is a normal component of blood gases at low concentrations (in humans), but if inhaled at high levels (> • • • • • • • • • an be harmful (potentially life threatening) through toxicological impact. At higher concentration levels the hazard increases further. The risks associated with hazardous mixture inhalation are well understood, and the experience of management of such risks can be used to help ensure safety.

Risk assessment: To assess the risk from hazardous leak events, frequency analysis, release modelling and harm/consequence assessment must be carried out. Risk assessment practices are well-known, but with regard to the assessment of CO2 stream leaks there are aspects which need consideration:

- Leak frequencies: As there is relatively little historical failure data for CO2 systems, data from other industries could be used to base predictions for the frequency of CO2 leaks. Aspects such as impurities, material incompatibility and internal corrosion need to be taken into account in this case.

- Release modelling: There is a great amount of data on modelling the vapour phase of CO2 releases but at the time of this publication, there is less on liquid phase releases. Certain aspects associated with liquid phase modelling need consideration, such as how to model the likely solid phase flow and the impact of impurities on phase envelopes.

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- Harm (‘impairment’) criteria: These are required to predict the harm to people and the environment from a CO2 stream leak. Criteria are currently being established that are industry and regulator accepted, which will ensure consistency within the risk assessment process.

- Propagating pipeline cracks: There is considerable experience from the natural gas (and other pipelines) industry with managing the risks associated with such a pipeline crack – experience which is being drawn upon for CO2 pipeline design. Projects should ensure the best available information is used when developing their infrastructure to minimise the likelihood that a small leak escalates to a propagating crack event.

- CO2 BLEVE: Under a remote (but credible) set of circumstances, a BLEVE (Boiling Liquid Expanding Vapour Explosion) could occur from the rupture of a vessel containing liquid CO2 . The probability of this event occurring is very low but project operators and system designers should be aware of the risk.

- Invisible CO2 cloud: A leak from a CO2 inventory is unlikely to form a visible cloud if the stream is hot (as it will not form the usual water vapour associated with the low temperature of a cold stream – CO2 vapour alone is invisible). Hazard management specialists for the CCS project must be aware that CO2 concentration within a release cannot be assessed from looking at the size of the visible cloud.

Key Messages

The DNV JIP acknowledges some key messages which summarise the issues associated with a CO2 stream:

- Major accident risks from a CO2 handling system can be low and within acceptable limits with the application of existing rigorous hazard management processes and an understanding of the properties/behaviours of CO2 .

- All commercial CCS systems will handle very large quantities of CO2 . - A significant leak from a large inventory has the potential to be life threatening to people

caught within the dispersing cloud. - The major accident hazard potential of the CO2 stream should be recognised early so that the

associated risks can be managed effectively. - It is essential that those involved in design and operation at a CCS project gain an adequate

understanding of the CO2 stream aspects. - There is a large amount of knowledge and experience from other industries that can be used

within each link of the CCS chain, with a lot of current, on-going work to reduce any gaps in knowledge.

- All CO2 stream hazards can be effectively prevented or mitigated through proper design, operation and response actions.

- There will usually be impurities within the CO2 stream – small amounts of other substances such as water, nitrogen and hydrogen – which may change the hazard potential of pure CO2. Stream impurities therefore need to be understood.

- This CO2RISKMAN Guidance: o Provides a comprehensive reference source to assist CCS projects and operation to

understand the issues and potential hazards associated with handling a CO2 stream. o Gives in-depth generic information on the stream that can be used across the whole

CCS chain. o Details specific guidance for each link in the CCS chain. o Highlights the importance of coherent and integrated hazard management in CCS.

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o Includes a comprehensive terminology section to assist in the promotion of consistent communication within a CCS project and between projects and stakeholders (e.g. the public).

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IEA GREENHOUSE GAS R&D PROGRAMME

43rd EXECUTIVE COMMITTEE MEETING

UPDATE ON THE IEAGHG MONITORING TOOL

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Update on the Web based Monitoring Decision Tool

Background

IEAGHG commissioned the British Geological Survey in 2006 to design and create a web-enabled decision support tool (DSS) to help users to select appropriate techniques to monitor a CO2 plume at a storage site.

Version 2.0a of the DSS was formally launched in June 2006, and feedback was sought from members of the International Monitoring Network during July 2006. T hat feedback was analysed and a number of improvements and added functions were included in Version 2.1 which was released in October 2006.

In the following 3 years the information was kept up-to-date and bibliographies and case studies were included and updated for each tool.

Following approval from the ExCo, the contract was renewed for another 3 years from 2011 to enable continued management and updating.

The Current Tool

The DSS has several components:

• A knowledge base that lists the techniques and their attributes.

• A hierarchical questionnaire-style interface that allows users to describe the situation they wish to monitor and input responses to questions.

• A system that selects appropriate techniques, based on the user inputs, pre-defined relationships between techniques and the attributes of each technique.

• A web-based output with links to a description of each selected technique, its limitations and applications. Case histories and references, including web links are provided.

The monitoring selection tool is generic, making recommendations based on the information supplied by the user. Site-specific conditions may preclude some of the recommended techniques from subsequent application, but encourages consideration of a wide range of techniques and dialogue both internally within a project team and between operators and regulators.

Work in the last year has focussed on updating the layout of the tool to fit in with the new website design and with the Joomla content manager. The toolbar now appears at the top of the screen and full scrolling is enabled, which increases readability greatly. It is also now more obvious how to hide the toolbar.

Next Steps

Over the next 2 years of the contract there will be regular updates to the knowledge base, which comprises the monitoring methods catalogue, descriptions, case histories, bibliography and the ratings tables. In the case where there is not enough information on tools to be able to rate them, they are not currently included in the database. There is planned to be a feature to allow emerging technologies to be documented in the knowledge base, even when there is insufficient information available to formally rate their performance.

Part of the new contract includes a presentation at the IEAGHG Monitoring Network, which will allow further feedback from monitoring network members.

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INCORPORATING FUTURE TECHNOLOGICAL IMPROVEMENTS IN EXISTING CO2

POST COMBUSTION CAPTURE PLANTS

The work entrusted initially to the group at Imperial College London aimed to examine the likely improvements in performance which could be expected, to examine what combinations of properties of improved solvents and equipment design might deliver significant improvements and finally to assess what the nature and costs of the pre-investments which would be required to prevent “locking out” the possibility of upgrade. Whilst some of this work was completed the full scope has not been covered in the study. Furthermore there have been considerable delays in delivering even the truncated report. This may be partly due to the move of the Imperial College CCS group to Edinburgh University. IEAGHG did not consider that the report was suitable for general distribution. However the work that has been done contains some valuable intermediate results and hence this was reported to the 42nd ExCo in this paper. It was agreed to develop this further in-house and publish instead as IEAGHG Technical Review along with suitable caveats about its applicability and completeness. When considering the improvement related to the amine based solvent properties it is important to identify the relationship between different solvent property changes. Hence, a combination of solvent properties changes shall be taken for more realistic approach. One of the drawbacks from the work performed by Imperial College was that the solvent properties change evaluated are independent of each other. Moreover other process improvements such as equipment size, process heat integration, lower cost material etc. were not evaluated in the work. Therefore, a Technical Review has been developed in order to give an insight on the current stage of solvent development on their properties and critical analysis on the outcome from the work by Imperial College. This review will help in identifying the critical areas and more suitable approach which shall be taken in future when evaluating the future possible upgrades applied at amine solvent based CO2 post combustion capture process. Attached is a summary of the draft Technical Review. The full draft Technical Review will be sent to members for comments, and presented at the 43rd ExCo.

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INCORPORATING FUTURE TECHNOLOGICAL IMPROVEMENTS IN EXISTING CO2 POST COMBUSTION CAPTURE PLANTS

Post combustion capture technology will be the one of the potential CO2 capture technology that will be applied at large scale in power generation in future in order to reduce the CO2 emission. It is also one of the technologies that can supply huge amounts of CO2 to be used as flooding agent in enhanced oil recovery. Considering the cost and performance of post combustion capture technology for coal and natural gas power plants is still high around 58 a nd 80 USD/tonne CO2 avoided respectively, IEA 2011. The operational cost based on ov erall CO2 avoided cost contributes approximately 76%, Singh et al, 2003. From which 50% of operation cost comes from fuel consumption from post combustion capture unit, Singh et al. 2003. Fuel requirement is mainly from the heat required for solvent regeneration which is accounted for around 55-70%, Zahra 2009. The rest of the fuel is required for CO2

compression and solvent circulation pumps. Figure 1, shows the survey of reported energy requirement for post combustion capture process from different solvents reported in different literature, Singh et al. 2013. It should be noticed that these presented values are dependent on the specific plant design and operating conditions. Therefore, these values only give an orientation and should not be compared directly.

Figure 1, Energy consumption in the stripper from different literature sources, Singh et al. 2013. The reported numbers only give an orientation and should not be compared directly. Figure 1 s hows that there is a constant effort going on in developing more energy efficient solvents for CO2 absorption post combustion capture process. Thus it is important to demonstrate significant technological developments in CO2 post combustion capture technology such as new improved solvents which could be in future retrofitted to early CO2 post combustion capture plants. In this way the perceived risks of building early plants would be significantly reduced. Incorporating these future improvements in the technology would help to facilitate the construction of the CO2 post combustion capture demonstration plants and the tranche of second-generation CO2 capture plants which will be necessary to obtain operating experience, to improve confidence in CO2 post combustion capture technology and reduce costs through ‘learning by doing’. Thus the incremental improvements in amine scrubbing that should

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be looked at will be future improvements which could be achieved in coming 10 years. The main improvements are expected to result from use of new improved solvents, which could result in for an example: • Reduced chemical reaction enthalpy • Increased solvent net CO2 loading (solvent capacity) • Reduced temperature for solvent regeneration • Increased regeneration pressure • Greater ability to tolerate flue gas impurities • Reduced solvent losses such as volatility, degradation • Reduced corrosion of capture process equipment

In some cases there will be trade-offs between the above mentioned criteria, for example a new solvent may have significantly lower steam consumption but require an increased solvent flow rate or this new solvent might be more expensive. Other potential improvements which should be looked into will include: • Increased in equipment sizes such as larger columns, large more efficient heat exchangers • More efficient or lower cost column packings • Improved/lower cost materials of construction • More efficient heat integration of the capture unit and with power plant • Improved CO2 compressor designs The work performed by Lucquiaud et al. 2013. on ‘ Incorporating future technological improvements in existing CO2 capture plants’ focuses on s ome of the above mentioned improvements such as improvements in amine based solvent properties like CO2 absorption enthalpy, solvent heat capacity, CO2 regeneration temperature by developing an equilibrium based model in gProms software. Each solvent property changes were performed independently to the other solvent properties in this model. Table 1, show the parameters used in the power plant and base case amine solvent based CO2 post combustion capture plant. Table 1, D etails of power plant and CO2 post combustion capture process used in the work performed by Lucquiaud et al. 2013.

Process Parameters Details Power plant type Ultra-Supercritical Pulverized coal Plant life 25 Years Fuel specific efficiency 327 kgCO2/MWth Plant efficiency w/o CO2 capture 44 % (LHV) Power plant capacity w/o CO2 capture 850 MW EOP before capture technology upgrade 321 kWh/tonne CO2 Power plant capacity with CO2 capture 666 MW CO2 capture level 87.5% Mass flow rate of Captured CO2 143 kg/sec Absorber temperature 40°C Stripper temperature 120°C Solvent 30 wt% Monoethanolamine (MEA) Solvent heat of regeneration 3.2 GJ/ tonne CO2 Enthalpy of Absorption 82 kJ/mole CO2 CO2 Absorption process Model Equilibrium based model in gProms software

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The effect of these solvent properties changes were evaluated on the changes in the electricity output penalty (EOP) of the power plant (constrained regard to the changes in the hardware) with no consideration of future upgrade together with the power plant which is designed to be fully upgraded. An additional electricity output penalty of the constrained power plant is identified which gives the information on the possible performance lock-in situation for such a plant. Moreover, financial value to the investors on the option of being able to upgrade a CO2 post combustion capture process at power plant to increase the revenue from electricity sales when a new improved capture technique become commercially available was also evaluated. A specific pricing methodology based on Real Option Analysis (ROA) was used for this evaluation. Further details on this reference work by Lucquiaud et al. 2013 can be found in the Technical Review based on this work. In order to predict the incremental changes in amine based solvent properties it is important to build a model which incorporates the current state of amine based solvent properties improvement. A rate based model is preferred as it accurately predicts the CO2 removal percentage, CO2 rich loading and temperature profile in the absorber. On contrary the equilibrium stage model over-predict CO2 removal percentage and CO2 rich loading and are incapable of correctly predicting the absorber temperature profile. Moreover the reboiler duty predicted by equilibrium based model is lower than the results from the rate based model and experimental data up to 9%, Zhang et al. 2013. The reason for this is due to the over-estimating the CO2 rich loading up to 6 %, Zhang et al. 2013, which leads to under estimating the reboiler duty. In the reference work by Lucquiaud et al. 2013 the amine based solvent properties like solvent heat capacity, enthalpy of absorption, mass transfer were changed independent of each other. This approach is not very realistic although trends observed from this work are true. Thus, the values predicted from the model in the work by Lucquiaud et al. 2013, will vary when compared to that from a rate-based model in which solvent properties are dependent of each other. Therefore, the technical review is developed in order to give an insight on the current stage of solvent development on their properties and critical analysis on the outcome from the work by Lucquiaud et al. 2013. This review will help in identifying the critical areas and more suitable approach which shall be taken in future when evaluating the future possible upgrades applied at amine solvent based CO2 post combustion capture process. Main outcome and recommendations based on this technical review is discussed below. Main outcome This review shows the main focus of the current stage of research and development in the amine based solvent CO2 post combustion capture technology and process equipment. Therefore, it is necessary to evaluate these improvements on the CO2 capture process as well as on power plant performance. This work shows that the certain improvements in solvent properties will benefit the CO2 capture process performance still at the same time could create a performance lock-in situation when power plant equipment is not designed to incorporate these future improvements. Such as reduced enthalpy of CO2 absorption, solvent heat capacity can create a performance lock in situation in the steam turbine when it is not designed to generate additional electricity

Real Option Analysis (ROA) for Financial value of an upgrade Technology Learning ratio 6% Capital cost required to upgrade the capture technology plant

4% (of the total CCS capital cost)

Long term growth rate for coal and electricity price.

0%

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from the additional available steam. The options which might be required for a conventional amine based post combustion capture unit in order to incorporate 2nd/3rd generation technology or improved amine based solvent systems are additional height for absorber, change in stripper operating condition like pressure, additional space for units required from different process integrations, additional space for heat exchanger, change in compressor inlet pressure and volumetric flow in first stage etc. From this study it can noticed that it is important for a power plant to be able to operate with any level of steam extraction and electricity export which will benefit from the capacity to upgrade their CO2 capture technology with a limited cost when compared to the plant sized at fixed CO2 capture level throughout their life. The real time analysis on the financial value of option of an upgrade shows that there is certain probability of 94.8% that a capture plant will be upgraded twice during its lifetime. In other words a pre investment in the upgradability of CO2 post combustion capture plant will be beneficial in order to increase the electricity output and reduction in CO2 capture cost. Recommendations When considering the improvement related to the amine based solvent properties it is important to identify the relationship between different solvent property changes. Hence, a combination of solvent properties changes shall be taken for more realistic approach. One of the draw back from the work performed by Lucquiaud et al. 2013 is that the solvent properties change evaluated are independent of each other. Therefore, IEAGHG recommends further work in this area in which a rate based model is developed for solvent based CO2 absorption process and a combination of expected solvent properties improvements will be evaluated. Regarding to the process heat integration improvements, IEAGHG is going to commission a study which will evaluate different solvent based post combustion capture process heat integration on similar solvent and process conditions. Other process improvements such as improvement in equipment size (heat exchanger, compressor), improved column packing material and low cost construction material shall be looked into further detail when considering the future upgrade in CO2 post combustion capture process. Furthermore the CO2 capture plant lifetime costs of various combinations of improvements shall be evaluated. Increase in CO2 capture percentage shall be evaluated further on its feasibility and cost of retrofitting to an existing plant. Other emerging second and third generation CO2 post combustion capture technologies such as multi-phase solvent or phase exchange solvents, ionic liquids, solid sorbents, membrane technology etc. shall be evaluated on the basis of their feasibility of retrofitting and impact on c ost. Regarding to the analysis of a financial value of an option of an upgrade a dynamic model shall be used in future considering the operational flexibility of the power plant. References IEA Paris, Cost and performance of Carbon Dioxide Capture from Power generation, 2011 Lucquiaud Mathieu, Liang Xi, Errey Olivia, Gibbins Jon, Chalmers Hannah, Incorporating future technological improvements in existing CO2 capture plants, 2013 Singh D, Croiset E, Douglas PL, Douglas MA. Techno-economic study of CO2 capture from an existing coal-fired power plant: MEA scrubbing vs. O2/CO2 recycle combustion. Energy Conversion and Management, 2003, 44 (19), 3073-3091

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Zahra A M, Ph.D. Thesis, Carbon Dioxide Capture from Flue Gas, Development and Evaluation of Existing and Novel Process Concepts, Delft University 2009 Singh Prachi, Van Swaaij W. P. M., Brilman D.W.F. (Wim), Energy Efficient Solvents for CO2 Absorption from Flue Gas: Vapour Liquid Equilibrium and Pilot Plant Study, 2013, E nergy Procedia Ying Zhang, Chau-Chyun Chen, Modelling CO2 absorption and desorption by aqueous Monoethanolamine solution with Aspen rate-based model. GHGT-11 Proceeding, Energy Procedia, 2013

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METHODOLOGIES AND TECHONOLOGIES FOR MITIGATION OF UNDESIRED CO2 MIGRATION IN THE SUBSURFACE

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METHODOLOGIES AND TECHONOLOGIES FOR MITIGATION OF UNDESIRED CO2 MIGRATION IN THE SUBSURFACE

Draft Overview

Background to the Study

Site characterisation for each potential geological storage site is carried out to identify those where it is extremely unlikely that any CO2 leakage would occur. Extensive Risk Assessments and MMV plans will be performed and designed for each selected site. However, it is also important to have a mitigation and remediation plan in place in the unlikely event that migration of CO2 out of the storage formation occurs.

A primary role of risk management is to drive the development of the monitoring program to be best equipped to identify unexpected movement of CO2 in the subsurface, either within the target zone or beyond, but prior to any potential migration to the near-surface. A s part of the risk management structure, methods for mitigating, preventing and, if needed, remediating, adverse effects related to any unexpected behaviour will be part of the overall MMV and operating plans.

Many of the methods for mitigation span a range of specialties, and have not often been part of ongoing discussions on a spects of geologic storage; however, regulators, operators, and some laypersons are interested in methods that can mitigate unpredicted CO2 movement.

Mechanisms that could lead to migration out of the storage formation and potentially leakage to the atmosphere or seepage into potable aquifers could include equipment failure e.g. wells, fault activation due to over-pressurisation, geochemical reactions between the CO2 and the caprock and migration through weak points in the caprock. There are therefore a number of leakage scenarios that will need to be considered.

In the case o f leakage from wells, there are known methods for reparation that are used in other industries, such as the oil and gas industry, these include replacing the injection tubing and packers and plugging leaks behind the casing with cement. Mud can be pumped down an interception well in case of well blow out. Wells that cannot be repaired may be plugged and abandoned.

CO2 may also leak out of the storage formation, either from fractures in the caprock or migration through the caprock if the capillary threshold pressure is exceeded. There are a number of possible solutions to this, including reduction of pressure in the storage formation by stopping/ reducing injection or increasing the number of wells. Extracting formation water from the storage reservoir may allow steering of the CO2 plume and will reduce the pressure. The pressure could also be increased in the overlying aquifer or upstream from the leak by water injection, thus forming a pressure barrier. It may also be possible to plug a leak with low permeability materials.

In case of leakage out of the confining structure from an unknown cause, the first step would be to stop injection, then begin investigation into the source of the leak, by checking pressure and well logs and reviewing the local geology. Using this information, shallower zones can be drilled to locate the leak and migrating CO2 can be controlled by lowering the pressure in the storage zone or creating a hydraulic barrier. The leak may also be able to be plugged and the storage operation may have to be reconfigured to take account of the new information.

If CO2 were to leak into potable groundwater, any accumulations of CO2 can be removed by drilling wells to intersect and extract them. CO2 can also be extracted in the dissolved phase using extraction

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wells and aerating it. If the groundwater has been contaminated by other substances that have been mobilised by CO2, then pump and treat methods may need to be applied. Hydraulic barriers could also be used to immobilise and contain the contaminants.

Leakage of CO2 could also adversely affect the vadose zone, ecosystem and surface water all of which would need remediating. CO2 can be extracted from soil-gas by vapour extraction techniques by drilling wells. As CO2 is a dense gas, it could be collected in subsurface trenches, extracted and reinjected or vented. Acidification of the soils from contact with CO2 could be remediated by irrigation or drainage.

There also needs to be a consideration of leakage into the atmosphere. For large releases spread over a large area, dilution may occur from natural atmospheric mixing, otherwise fans could be used.

There have recently been modelling studies, looking at using extraction wells to remove CO2. Some preliminary results show that this method may work fairly well on smaller plumes, but appear less effective with larger plumes. However, remediation of larger plumes may be more effectively carried out by simultaneous CO2 extraction and injection of water.

CO2GeoNet, a consortium based in Europe, was commissioned by IEAGHG to undertake this study.

Scope of Work

The driver behind this study is to develop a report built on the on the previous IEAGHG report on methods of leakage mitigation (2007/11). The proposed study should focus on current mitigation and remediation methods that may be applied or considered in site specific conditions in the event of unpredicted CO2 migration.

Each geological storage site will have an adaptive site specific monitoring plan, based on a risk assessment. Detection of a significant irregularity may involve supplementing the monitoring program, in order to detect a possible leak and if necessary engaging mitigation measures.

A survey of mitigation methods should be provided; an example of the type of methods may include: decreasing injection rate or bottom hole pressure, drilling additional injection wells, relocating injection wells (potentially within the existing storage complex or in a separate and distinct unit), drilling pressure relief wells, performing well workovers, injecting chemical barriers, hydraulic barriers, triggering new processes within the MMV program, or cessation of injection and plugging and abandoning wells.

Certain practices including well remediation may be considered standard industry practice. However, some novel methods may be needed for mitigating unexpected CO2 migration and remediation of the effects of leaked CO2.

This will involve a review of:

• The state of knowledge of novel and standard mitigation and remediation practices • Associated costs of the technologies and methodologies needed

Following this should be a review of mitigation plans in place on current/ past/ future CO2 storage projects, where available. These can be compared and analysed to produce a recommended process to produce a mitigation and remediation plan.

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The contractor was referred to the following recent IEAGHG 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:

• Remediation of Leakage (ARI, 2007/11) • Potential Impacts of CO2 Storage on groundwater (CO2GeoNet, 2011/11) • Caprocks for Geological Storage (CO2CRC, 2011/01) • Pressurisation and Brine Displacement (Permedia, 2010/15) • Safety in Carbon Dioxide Capture, Transport and Storage (UK HSL Laboratory, 2009/06)

In addition, the following active IEAGHG projects have strong links to this study and IEAGHG will manage and encourage contact between contractors to avoid duplication of effort or unnecessary discrepancies in findings:

• Resource Interactions for CO2 Storage (CO2CRC)

Findings of the Study

This study reviewed the current available and novel technologies; considered the costs and benefits of mitigation methods; and then reviewed existing mitigation plans and regulatory guidelines.

Mitigation and Remediation Techniques

Migration from the storage formation may occur via engineered or natural pathways. Engineered pathways may be through abandoned or operational wells, either through poor completion and plugging, over-pressurisation, chemical degradation close to the well environment or by well failure. Natural pathways may be faults, fractures or more permeable zones in the caprock, which could be present before injection or caused by injection induced processes; CO2 migration may also be caused by exceed the caprock capillary entry pressure or occur at a spill point.

The choice of mitigation measure will strongly depend on the nature of the leak, with intervention of leakage from engineered pathways likely to stem from oil and gas industry experience. In other cases fluid management techniques or novel methods may be more appropriate.

Wells consist of the wellbore casing, tubing and packer (when the wellbore is active), and cement (which is also used to plug and abandon a well). For active wells, the packer represents a potential leakage pathway, though experience gained in the oil and gas industry provides good practice of designing, executing and maintaining wellbore integrity. There are various methods of intervention, which will depend on the origin of the leak. The wellhead (or welltree) may be repaired, the packer replaced; if the leak is located in the injection tubing string, the tubing may be pulled out and repaired and if leakage occurs through the casing or cemented annulus, squeeze cementing may be performed; a casing patch can also be used against casing leaks and swaging allows restoring a casing that would have been deformed. Any leakage that cannot be mitigated through the installed wellhead or welltree requires a full work over of the well: a plug is set to isolate the reservoir and the well is subsequently killed by filling it with a heavy kill-fluid to avoid a blowout.

Wells can be relatively easily monitored, whereas leakage away from the wellbore is more difficult. Such leakage could be through a fracture, or series of fractures in the caprock, which may be less well understood and thus corrective measures are likely to be through pressure management and injection operation management solutions. The first solution would be to stop pressure increase or decrease

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pressure in the storage formation, by ceasing CO2 injection and/or extracting fluids (CO2 or brine). A second solution could be the creation of a pressure barrier in the overlying geological strata to prevent or minimise CO2 migration. Enhancing non-structural trapping in-situ or ex-situ may also help decrease the risks of CO2 migration. Even if CO2 storage is planned to be permanent, an ultimate intervention is CO2 back-production, which may also be considered for small leakage plumes in overlying aquifers.

Novel technologies may also be considered. Many of these were developed for other industries, but could be applied to or adapted for CO2 storage. Geopolymer cement displays higher strength and better resistance to acid than conventional Portland cement and may be considered instead, though in many cases Portland cement may be considered adequate. Novel technologies could also be used in cases where conventional and standard technologies might not be applicable. Foams and polymer or inorganic gels have been traditionally used in the oil industry and can have several functions, such as sealants, and relative permeability or mobility modifiers. The use of nanoparticles in gels and foams or for mobility control is also under development. Biofilms have also been proposed as bio-barriers, which could help prevent migration of CO2 through the caprock by blocking leakage pathways.

While the purpose of mitigation measures is to avoid an impact or reduce its magnitude, additional methodologies could be implemented to remediate the impact and restore the environment. CO2 leakage may potentially lead to an impact on groundwater aquifers, the unsaturated zone and surface assets such as human health, ecosystems or other activities. Remediation measures specifically dedicated to CO2 storage impacts are poorly documented, but extensive data and experience on measures to remediate impacts already exist in various fields such as soil clean-up, aquifer repair and intrusion of gas in buildings treatment. Therefore, based on the analogy with impacts stemming from other activities, methods can be divided between passive methods, such as the monitored natural attenuation, and active methods. The measures that could potentially be applied to CCS are summarised in Table 1.

Table 1: Summary of proposed measures to impact remediation for CCS

Impacted compartment

Suggested measure Possible application in CCS domain

Groundwater Monitored natural attenuation - Reduction of contaminants concentration : e.g. aqueous CO2 concentration, impurities, mobilized metals and organic compounds

- Transformation of contaminants into less toxic products: e.g. impurities, metals, organic compounds

- Reduction of constituent mobility and bioavailability: e.g. impurities, metals, organic compounds

Pump-and-treat - Extraction and treatment of fluids containing dissolved CO2 or other contaminants (impurities, mobilized metals, organic compounds)

Air sparging - Volatization and extraction of dissolved CO2 and additional contaminants (with properties similar to VOCs

Permeable reactive barrier (treatment wall)

- Trapping through a permeable barrier favouring reactions of mobilized trace elements (metals, organic compounds, impurities)

Injection - extraction - Extraction of the mobile gaseous plume; - Decrease of the quantity of mobile CO2 in the

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groundwater aquifer; - Extracting the dissolved CO2 and potential additional

contaminants Remediation using microbes - adjustment of ground water pH

- mineralization of dissolved CO2 - co-precipitation of contaminant (heavy metals)

Unsaturated zone

Monitored natural attenuation - reduction of CO2 concentration in soil - Transformation or reduction of mobility of

contaminants (e.g. organic compound, heavy metals) Soil vapour extraction - extraction of CO2 (or organic compounds) from soil

pH adjustment (spreading of alkaline supplements, irrigation and drainage)

- adjustment of soil pH

Surface water Passive systems: Natural attenuation

- reduction of CO2 concentration in shallow water

Active venting system - remove dissolved CO2 in deep stratified lakes Indoor environment

Usual remediation techniques (radon, VOC…): sealing the opening, (de)pressurization, adjustment of ventilation

- lower CO2 concentrations in indoor air

Atmosphere Passive system : Natural mixing - reduce CO2 exposure in the atmosphere Air jets or large fans - reduce CO2 exposure in the atmosphere

Ecosystems Ecological restoration - restore the impacted ecosystem (if needed)

Cost Benefit Analysis

If an irregularity is detected the operator needs to decide on a series of actions, which can include further monitoring, mitigating the leak and/ or remediating adverse impacts. From an operational perspective, the maturity of a technology is essential to ensure its feasibility. Among the technically feasible measures, it is necessary to consider the efficiency (impacts avoided in a given time period) and costs (economic costs and potential environmental negative impacts of the measure). Detailed assessments of risk scenarios will need to be site specific though can be based on generic operational tools and elements.

Cost benefit analysis, Cost-Effectiveness Analysis and Multi-Criteria Analysis have been used in the decision process of environmental clean-up interventions. Cost-benefit analysis is a comparison between the costs and benefits of a scenario. In the case of mitigation or remediation action implementation, the scenario is the choice of a measure, or a combination of several measures. The cost being the direct cost of the implementation of the measure, the benefits can be defined as t he difference between the impacts avoided and the potential additional impacts caused by the measure itself. To be comparable with direct costs, benefits are formally defined as the difference in economic effects of these impacts in such analyses.

Previous studies reviewed are the 2007 IEAGHG report, the 2010 EPA report and the 2011 ZEP report. The 2007 IEAGHG report does not specify whether mitigation/remediation of old abandoned wells during the site selection and planning and construction phase are covered by the remediation cost or in the basic cost. For the USEPA, it is clear that those cost for preparing the site are incurred at

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the front-end of the project and separated from leakages developed or discovered later during operation of the injection site.

In the three studies, there are identified three different ways for estimation of mitigation and remediation. The IEAGHG study has based its calculation on input of known cost for e.g. a suite of operations (repairs, plugging of wells, new contingency wells or wells needed for remediation to create positive pressure barriers, etc.) and multiplied by an assumed expected number of occurrences in the lifetime of the storage projects. The USEPA (2010) treated it as a percentage of capital cost and new equipment cost. In addition they opted for a contribution of $0.10 per ton of stored CO2 to a remediation fund and insurance (this was not shown to be included in the results table). The Zero Emission Platform assumes a fixed value of €1.00 per ton stored CO2. They argued that “such an assumption makes the cost of liability per tonne of CO2 stored completely transparent: that element of the storage cost can easily be subtracted from the total cost and replaced by other estimates of the cost of liability as they arise.”

Several methods exist to monetise impacts. The revealed preferences approach examines actual behaviour in markets or nonmarket activity, to infer the value that people place on avoiding impacts. The stated preferences approach is a survey-based set of methods that pose hypothetical situations and ask peoples willingness to pay for avoiding specific damage to an ecosystem or to make choices across different options.

Estimating the direct cost of remediation technologies needed is also essential from an operational point of view. Few data exist in the literature; though studies have been performed to estimate the global cost of CO2 storage and present costs of potential mitigation and remediation interventions. In addition, some elements of costs have been reviewed based on the consultation of expert, for example intervention on wells since as this can be directly compared the petroleum industry. Relevant estimation of costs of other technologies is not possible to date due to the poor experience in CO2 leakage mitigation and remediation. The interventions on wells are mostly heavy, but the costs vary according to the location of the intervention. Offshore operations are much more expensive than comparable onshore activities. The country in which the action is carried out makes the price different as well. Several scenarios have thus been considered to estimate the final costs.

New calculations from IRIS in-house data and the petroleum industry are used, which show different costs associated with well remediation, Table 2.

Table 2: 1 Estimated total costs range for different mitigation methods. All costs are in M€. Offshore 1 : Norway, US Gulf of Mexico, Brazil, West Africa ; Offshore 2: UK and DK ; Onshore 1 : Europe and Middle East; Onshore 2 : USA

Offshore 1 Offshore 2 Onshore 1 Onshore 2

Low High Low High Low High Low High

Killing of a well 1.5 7.9 1.2 7.5 0.7 6.9 0.6 6.7

Wellhead and welltree repairs

1.5 7.9 1.2 7.5 0.7 6.9 0.6 6.7

Packer replacement 4.7 10.8 3.5 9.6 1.3 7.4 0.9 7.0

Tubing repair (with workover)

4.7 10.8 3.5 9.6 1.3 7.4 0.9 7.0

Tubing repair (no workover)

0.2 0.4 0.15 0.3 0.07 0.14 0.06 0.11

Squeeze cementing 2.3 8.4 1.8 7.9 0.9 7.0 0.7 6.8

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Patching casing 6.9 13.0 6.2 12.3 5.0 11.1 4.7 10.8

Repairing damaged or collapsed casing

0.5 6.6 0.5 6.6 0.5 6.6 0.5 6.6

Plugging of a well 6.0 8.0 4.2 5.6 1.2 1.6 0.6 0.8

Abandoned wells 6.7 13.3 4.7 9.3 1.3 2.7 0.7 1.3

Stopping surface blowout 20.0 53.3 14.0 37.3 4.0 10.7 2.0 5.3

Existing Plans and Regulatory Guidelines

CO2 geological storage is now implemented in several places around the world and these projects have risk management procedures which integrate mitigation techniques in case of deviation from the expected behaviour of the storage complex. Regulatory requirements are also in place and need to be followed. Several guidelines or guidance documents including mitigation and remediation measures have been issued. International standards, which are not specific to CO2 geological storage, also propose generic workflow for risk management and guidelines for the risk treatment stage.

A review of existing corrective and remediation measures plans (both in the CCS and in some non-CCS related industries) and literature on intervention plan set up has been performed. The panel (14 companies contacted, 8 participants) was constituted of operators and/or service companies in CO2 storage as well as natural gas storage. Publically available corrective measures or risk management plans have also been considered. The key messages found are:

• All mitigation and remediation plans should be site-specific and risk-based. The corrective measures plan containing risk-reduction actions is included in the risk management process and is closely linked to the risk assessment and monitoring plans. The plan is usually public, it has been reviewed by stakeholders and updated over time as new information becomes available. Formats of corrective measures plans are very diverse, which may be explained by the different legislations, which sometimes only give limited and non-detailed guidelines compared to other mature industrial fields.

• Corrective measures and methods proposed mostly involve remediation of injection or abandoned wells or are directly related to operational aspects such as reducing the CO2 injection rate. Drilling new wells or applying breakthrough technologies are seen as ultimate measures, and the development of new remediation measures on impacts is often judged unnecessary given the experience in environmental clean-up.

• Despite the importance of the initial plan, the decision protocol should be flexible in order to allow holistic decision making. The detailed intervention process cannot be included in the plan submitted during storage permit application; it will be decided by the team (operator and competent authority) in place at the time of detection of an irregularity. The contingency plan should, however, help that team to have a holistic view on the issues and to balance the technical feasibility, the benefits (avoided impacts), the economic costs and the potentially negative impacts of the measures implementation.

Expert Review Comments

This study has been through the expert review process and CO2GeoNet are currently working on the final report. Expert comments have been received from 10 reviewers; and are summarised as:

1. Executive summary:

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a. This could be shorter as some information could be left in the main body of the report. It could also start with a clear definition of leakage.

b. It would be useful if there were a graphic to show what is known about mature technologies and where there are gaps (see review 3)

2. Costs: a. It might be useful to use estimates from other industries, such as oil and gas or

more particularly from EOR operations

b. One reviewer points out several issues with the methodologies of CBA, which could be included in the report

3. Wells: While cement sheaths may degrade on contact with CO2, this doesn’t mean that the structure will fail. Also note this has been a consistent learning within the IEAGHG wellbore integrity network.

4. Use of language throughout the report: a. Some of the language used could be less negative, for example fractures and

faults in the caprock, need not be describes as flaws and defects.

b. There are some grammatical errors and in places the report does not ‘read well’, e.g. excess use of ‘the’.

Conclusions

Potential actions for avoiding, reducing or correcting impacts caused by unwanted CO2 migration have been reviewed. There is a large discrepancy between different techniques available in the literature with respect to their maturity and therefore some measures may not be operationally available at the present time. The operational feasibility of a given measure is dependent on additional criteria, especially on the balance between benefits (impact avoided) and costs (economic direct costs and potential negative environmental impacts). Elements and generic tools for such analysis have been reviewed in this study; however, any detailed assessment needs to be site specific and specific to a given risk scenario. This technical and operational knowledge is the basis for intervention strategy to be set up according to existing regulations. A literature and experience review has been carried out focusing on both the development of mitigation plans and the measure implementation in case of an unwanted CO2 migration in the subsurface.

An outcome of the study are some proposed recommendations:

Technical aspects

Gaps in technology development

Most measures come from experience in mitigation or remediation of other kinds of risks and impact, such as oil and gas industry and environmental clean-up. However, CO2 geological storage has different conditions. Therefore, there is a need for research on how measures could be adapted to the specific conditions of CO2 geological storage. For instance, remediation measures originated from the environmental clean-up field are referenced, but there has not been much research on their application to CO2 migration and potential impacts.

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Development of new measures tailored to CO2 leakage is also needed. Some theoretical concepts have been proposed, e.g. pressure management; however, their feasibility has to be proven through experimental tests or in-situ deployment following detailed modeling and simulation studies. Some breakthrough technologies are being developed; however, their development is at an early stage and therefore much effort is needed to integrate them into the portfolio of mitigation and remediation measures.

Gaps in migration knowledge and leakage consequences

Developing new measures implies knowledge of risk or impacts to be treated: up to now the risk of leakage is not well understood (e.g. the mechanisms underlying the migration of CO2 across several geological formations), and therefore the potential impacts cannot be well characterised. This gap is also due to lack of experience and feedback in the field of CCS. Research on migration processes should then be pursued.

Operational aspects

Need for accurate description of conceivable measures

Operators and regulators will need comprehensive descriptions of each measure in order to make a knowledgeable choice, not just a list of measures to be potentially applied. The purpose of the measure, time needed for implementation, associated economic costs, maturity or environmental impacts of a measure are key elements that need to be assessed. The review performed in this study gives these elements when available. However, there is a l ack of such information and therefore extensive work is needed to fill this gap.

Need for tools to assess feasibility, optimise and evaluate effectiveness

There is a need for tools to assess the achievability of mitigation measures. An adequate assessment process should be set up in order to balance benefits of one measure (impacts avoided) and its costs; this would allow implementing operationally manageable measures. This could be based on the widespread cost-benefit analysis methods. In order to improve the applicability of the cost-benefits analysis, the experience in using such tools in mitigation strategy implementation should be shared; this would allow a comparison of the methods used and of the data considered, which is essential for establishing best practices.

Tools (especially numerical) will also be needed to allow optimisation of the cost-benefit ratio. Even if the design of a measure will be highly situation-dependent, research in the development of such generic tools is needed beforehand. Processes, data and tools will also be required to evaluate the effectiveness of a deployed measure to mitigate or remediate CO2 leakage. This will be important not only for a given case, but also for building competence and experience in potential future applications of mitigation and remediation measures.

Implementation of the mitigation and remediation strategy

Mitigation plan based on the existing state of knowledge

The intervention plan should, at any given date, include technologies available according to the current state of knowledge. Selection criteria needed for a knowledgeable choice should be also part of this plan. The plan should be reviewed and updated to allow the integration of any new measures or any new information that may change the ranking list of measures or the associated information.

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Mitigation plan integrated in the global risk management process

The mitigation and remedial actions should be linked with the risk scenario selected during the risk assessment process and each measure should be related to irregularities it mitigates; in addition the methods described in the monitoring plan should be mentioned in the mitigation plan both to detect irregularities, that would induce intervention, and to assess the efficiency of intervention.

Flexible mitigation plan

Choice and design of the measure is situation dependent. The plan should be somewhat generic, proposing adapted measures to a potential situation. However, it should be able to help as much as possible the decision-making if a deficiency would occur. Therefore, the tools or processes leading to the design of the most relevant mitigation and remediation strategy could be specified in such a plan. The final decision will be made when migration occurs, taking into account the specificity of the situation and considerations of both operators and regulators. This has to be done according to specific decision-making tools that need to be developed.

Recommendations

Mitigation measures will need to be site specific for each project with a range of risk scenarios considered. Any corrective measures plan will also need to be updated as more methods become feasible.

As more projects come on line there will be more information of proposed corrective measures plans as well as more generic tools. It is recommended that IEAGHG continue to follow this topic as more information becomes available. This should be mainly through the research networks (namely the risk assessment, modelling and monitoring networks).

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NON CO2 GREENHOUSE GASES – A REVIEW

This topical review has been delayed pending the publication of two new relevant reports by the USEPA. These reports are now publically available in their final form. An initial review will be completed before the ExCo and presented to members at the ExCo for comment. The report on the review will then be completed after the ExCo following member’s comments on strategic issues that may arise re future IEAGHG activities in this area..

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EVALUATION AND ANALYSIS OF THE PERFORMANCE OF DEHYDRATION UNITS FOR

CO2 CAPTURE

This study has been undertaken by AMEC, UK. The draft report has been received and was sent out for comments to expert reviewers who have returned their comments by 20th March 2013. AMEC is currently revising the final version according to the comments.

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EVALUATION AND ANALYSIS OF THE PERFORMANCE OF DEHYDRATION UNITS FOR CO2 CAPTURE

Introduction Within the full Carbon Capture and Storage (CCS) chain the dehydration step is a relatively minor part and has been treated as a black box process in the past, paying little attention to the details of its design. However, the conventional drying technologies face a number of challenges, which need to be addressed before full scale deployment. These include the effect of impurities in the captured CO2 stream on the dehydration processes. IEAGHG has commissioned AMEC to carry out this study in order to examine the characteristics of the various drying processes and the way they can be best integrated into the CCS system.

Approach

The purpose of the study is to examine the characteristics of the various dehydration processes and the way they can be best integrated into the CCS system. The scope of work for this study comprises four main elements:

• Evaluation and characterisation of processes for the dehydration of captured CO2 • Preparation of guidance on the selection of processes to match the various requirements

for water dryness of CO2 • Evaluation of methods for the monitoring and management of water dryness • Analysis of future drying technology developments

The CO2 produced by the various combustion and associated capture processes is of different quality. It was therefore necessary to consider the different types of capture process separately within this study. The information from the different process capture types has been used to produce a set of dehydration feed gas compositions. Base case data represent the minimum and normal impurity levels. Water content of saturated gas is dependent upon the temperature and pressure of the gas stream. Test cases are used to consider the higher levels of impurities and inerts. This study investigates three different moisture levels; 550 ppm v (typically used in pipeline systems where high ambient temperatures are experienced), 50 ppmv and < 10 ppmv (required where downstream processing involves cryogenic conditions). Two different CO2 flowrates were considered: 2 million te/year, which is typical for a gas-fired power plant, and 4.5 m illion te/year, typical of a coal-fired power plant. Vendors were also asked to advise the maximum rate achievable for a single dehydration train. Pressure ranges for dehydration are based on the gas phase. Liquid and supercritical CO2 are usually produced via the gas phase, so are not considered separately. Economic and technical data is presented for the TEG (triethylene glycol) and molecular sieve dehydration units based on the limited vendor data available.

Results and discussion

Background issues Whilst several vendors (SPX Flow Technology, Frames Process Systems, Exterran (UK) Ltd, Zeochem AG, UOP Products Ltd, and Grace Materials Technologies) have assisted in this study, most others have been unable, or unwilling, to do so. This may be for several reasons, not least of which is a booming oil and gas market. Engagement in CCS as a market is very low. Several comments were received regarding the fact that vendors have provided many quotations

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for CCS projects but without any orders being placed. Within the timeframe of this study one of the vendors changed from stating at the beginning that they regard CCS as a core target area for their business and would be very happy to assist in providing data to suddenly changing tack and providing minimal data of a generic form. Re-engagement of vendors is therefore an area which should be addressed by industry bodies as a priority. Due to the lack of vendor engagement many of the conclusions presented are of a preliminary quality. Dehydration media vendors were generally more helpful, assisting with estimates of the number of beds and bed size. They were also able to assist with information on the effects of impurities on the molecular sieve adsorbent as well as side reactions which could occur under the processing conditions and during regeneration in particular. Background issues, relevant to CO2, were summarised. These indicate that:

• The presence of inerts and impurities can lead to significant changes in the CO2 physical properties and rates of corrosion. These changes are not well understood and further work is required to adequately quantify the effects.

• Equations of state need to be developed which adequately reflect the physical properties of CO2 containing inerts and impurities.

• There are limits to the extent of cooling that can be applied to the wet CO2 gas before water ice, hydrates or liquid CO2 form. This must be considered in the selection of cooling medium and wet gas conditions. The information on h ydrate, water ice and liquid CO2 formation is combined in Figure 1, thus illustrating the allowable operating area.

• There is a w ide range in dry CO2 moisture specifications used for pipelines in the literature. Although it is not the intention of this study to specify what the target moisture should be guidance is given on t he types of issues which should be considered when setting the dry CO2 moisture specification. It should be noted that this value is not merely determined by downstream pipeline conditions but also by coincident conditions which may occur within the processing plant, which may be very different to those experienced by the pipeline.

Figure 1 - Combined hydrate/water ice/liquid CO2 plot

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The effects of impurities and inerts on the dehydration systems were investigated and summarised. Where available, the maximum allowable concentrations have been advised. In the case of solid desiccant several approaches can be taken to deal with impurities:

• Additional amounts of desiccant can be added to cater for the effects. • Acid resistant desiccant can be used, which can better withstand the impurities. • Protective layers of activated alumina or silica gel that are better able to withstand the

impurity can be added as guard layers to the top of molecular sieve beds. In some cases regeneration of the bed has the effect of regenerating the guard layer, but in some cases the bed is sacrificial, in which case the whole bed has to be replaced when the guard layer has been exhausted.

In the case of liquid desiccant impurities can: • Form solids, which are removed by in-line filtration. • Cause foaming, resulting in losses of desiccant due to entrainment, and reduced moisture

removal from the gas stream. High efficiency internals minimise the carryover of desiccant. Anti-foam can be added to limit the foaming and enable control of the process.

• React with the desiccant to form corrosive products. Oxygen can react with TEG to form organic acids.

It is extremely important that the specific impurities and their normal and maximum concentrations are known and adequately considered during design. In the event that the levels of impurities cannot be tolerated, either because of their damaging effects or the increase in dehydration adsorbent volume required to deal with them, then it may be more appropriate to remove the impurities in a separate treatment system, located upstream of the dehydration unit. This may require a cat alytic reactor or use of an adsorbent (which may or may not be regenerable). The dehydration vendor may be able to advise on the most appropriate approach to be taken. Dehydration technology options were discussed. Some of the techniques do not achieve low moisture levels, however they are straightforward, low cost processes, often required in a process anyway (such as compressor inter-stage cooling and knockout) so are important in offloading the dehydration unit, resulting in smaller, less costly dehydration systems. The benefits of some of these options, which involve low temperature chilling, are limited due to the risk of formation of water ice, liquid CO2 or hydrates. Large pressure drops are required to provide the Joule Thomson chilling so low pressure options are less viable. Several liquid and solid desiccant systems were investigated; most are applicable for use with gaseous CO2. The different processes and desiccants can achieve orders of magnitude different product moisture contents. Basic liquid desiccant systems can achieve ~ 150 ppmv moisture, enhanced liquid desiccant systems can achieve down to 30 ppm v moisture. Solid desiccant systems can achieve lower levels; activated alumina and silica gel can attain down to 10 ppmv while molecular sieves can achieve down to 0.1 ppmv moisture.

Technologies

Several different types of CO2 capture processes exist. The type selected for use is dependent upon the basic type of combustion process in operation, e.g. coal or natural gas. The CO2 streams produced by the various combustion and capture processes are of different quality, containing different types of inerts and impurities, with varying compositions and conditions. The dehydration process can be significantly affected by these differences:

• Post combustion capture gas is delivered water-saturated at pressures just above atmospheric.

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• Pre-combustion capture provides multi-stream gases at low pressure and medium pressure conditions.

o The Rectisol capture process delivers dry CO2 gas at < 1 ppmv moisture containing small levels of methanol. Further dehydration is not required. The methanol content is not expected to be condensed out in the subsequent compression and/or cooling process.

o The Selexol solution contains water so the CO2 gas is effectively saturated with water. Selexol has a low vapour pressure so there is minimal contamination of the CO2 by the process. UOP advise that lower water levels of around 500 – 1000 ppmv are achievable, but only at pressures in excess of 10 barg. At these conditions the CO2 content of this HP stream would be significantly less than 98%. If sulphur removal is not required, then the process can use pure Selexol and solvent regeneration can be carried out by flashing alone. In this case significantly lower water content will be present in the CO2 product.

• Oxyfuel combustion gas compositions (dry basis) for the different processes are effectively similar, with the exception of water content and NOx and SO2 impurities. The streams are water saturated.

The information from the different process capture types have been used to produce a set of dehydration feed gas compositions. Base case data represent the minimum or normal impurity levels. Water content of saturated gas is dependent upon the temperature and pressure of the gas stream. Test cases have been used to consider the higher impurities and inerts. Dehydration of post-combustion and pre-combustion capture cases can be carried out at a variety of different pressures, depending upon the supply pressure and the compressor interstage conditions available. Oxyfuel cases span a range of pressures from ~ 5 to 30 bara, dependent upon the supply pressure and downstream processing requirements. Drying pressures are likely to be in the range of LP compression. Information from both package vendors and media vendors centred around two basic process mediums: TEG and molecular sieves. The following data is therefore based upon these media. Type 3A or 4A molecular sieves have been proposed with acid resistant grades in cases containing high levels of undesirable impurities, typically NOx, SOx and H2S. The quantity of desiccant required is a function of the selected adsorption time, the number of beds in parallel and any margin added due to the presence of impurities. Lower pressure operation will require larger diameter beds and larger bed volumes to cater for the larger volume of gas and the increase in moisture present. Typical media life of both molecular sieve and TEG is expected to vary between 2 and 4 years, typically 3 years. The maximum train size appears to vary considerably. For molecular sieve cases with feed gas at 30 bara and 30°C the range (from different vendors) varied between 300 and 600 te/hr. The limitations appear to be based on several factors including the maximum vessel diameter which can be manufactured, the capital cost of the vessel (which begins to increase dramatically before the maximum diameter is reached), the maximum number of beds of a certain size in parallel, the adsorption time (and thus size) of each bed and the regeneration rate (which sets the time before a bed has to be back in commission). It is desirable to keep the bed size small, to avoid the requirement for large volumes of desiccant and associated vessels; available adsorption time is minimised and a fast turnaround of regenerating beds is therefore required. There becomes a point when it is more practical to split the feed across an additional number of trains. It is undesirable to have bed adsorption times of less than 6 hours.

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Preliminary estimates indicate that a TEG regeneration unit could potentially handle the moisture from 3,500 te/hr of CO2 gas, although multiple contactors may be required to be able to process the quantity of gas. If future expansion capacity is built into a dehydration package then capacity can be added at a later date.

• For molecular sieve, if an allowance is made for future adsorption beds at the outset then they can be added at a later date. The bed adsorption time, regeneration loop and associated regeneration equipment need to be large enough to regenerate an increased number of beds within the available adsorption time of the beds.

• For a TEG system adequate allowance needs to be made for the future glycol processing requirements. Additional contactors can be added.

CO2 contamination from the dehydration process and waste by-products have been discussed and quantified, where information is available. CO2 losses from the process have also been considered.

Costs The capital costs of the dehydration equipment are a minor part of the overall costs for a CCS plant. The equipment uninstalled costs are therefore presented. Data presented is a combination of data received from different vendors (as part of this study), data from previous AMEC projects and AMEC modelling and cost estimation. The data is therefore mostly given as cost indicators. There is a wide spread in molecular sieve capital cost data from different vendors for fixed operating pressure. The data has been used to set the maximum and minimum cost lines and has the cost indicator plotted against rate, as shown in Figure 2. The differences are due to several factors:

• The regeneration techniques proposed by the different vendors. Atmospheric pressure regeneration with air will be less costly. The amount of equipment required is significantly lower than for a high pressure regeneration using CO2. The volume of CO2

• Use of the CO

gas passing through the online bed is also lower since there is no regeneration gas to be processed. Smaller bed size results.

2

• The materials of construction proposed.

compression facility to provide the driving force for the regeneration gas results in provision of less equipment within the dehydration package, but larger compression & cooling equipment and more costly compression costs.

• The number and size of the individual adsorption beds proposed. • The number of parallel dehydration trains proposed.

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Figure 2 - CAPEX indicator for molecular sieve

Operating pressure has an effect on the molecular sieve equipment capital costs. Limited available data indicates that equipment capital cost passes through a minimum. Figure 3 illustrates the qualitative relationship between the capital cost and the operating pressure for a molecular sieve system with a minimum ~ 25 – 30 bara. The actual location of the minimum is expected to be application specific depending upon:

• The reasons given above for differences in capital cost. • The equipment design pressure - whether it is set to be 10% above the maximum

operating pressure or designed for compressor settle out pressure on compressor trip. • The type of regeneration and the extent of regeneration equipment supplied.

Figure 3 - CAPEX indicator for solid desiccant

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There is no difference between the capital costs of the molecular sieve equipment for target moistures of 550 ppmv, 50 pmv and < 10 ppmv. Media suppliers and package vendors all advised that it is normal to design for removal of the water stream to < 1 ppmv, irrespective of the target moisture required. Data on liquid desiccants is lacking. The data presented is for water saturated raw gas at 30 bara and 30°C. The raw gas stream is relatively pure containing > 99% CO2

Figure 4

with low levels of impurities. Product moisture is 50 ppmv; the TEG process includes the use of stripping gas to increase the TEG concentration. The available data is understood to form the maximum cost line; the cost indicator is plotted against rate as presented in .

Figure 4 - CAPEX indicator for TEG

Higher levels of target product moisture (in excess of ~ 150 ppm v) will require more basic equipment; the stripper will not be required. The cost for such a system will therefore be lower. In the case of high impurities:

• Increased oxygen levels of 300 ppmv have no effect on the molecular sieve equipment cost or on t he solid desiccant selected. Oxygen is, however, known to degrade TEG; acceptable limits are not known so the effect on TEG equipment capital cost cannot be evaluated.

• The case with 100 ppmv NOx, 100 ppmv SO2 and 100 ppmv H2

o The use of an acid resistant molecular sieve with an increase in media volume of ~ 5% and an increase in media cost of ~ 15%.

S results in the requirement of:

o An increase in molecular sieve equipment capital cost of ~ 7%. • The effects on TEG equipment capital cost cannot be evaluated.

It is recommended that impurity issues be discussed with the vendor at an early stage, since they may recommend removal of these upstream of the dehydration equipment.

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In the case of high inerts content the cost of the equipment is higher per tonne of CO2

• The increased volume of raw gas per te of CO

present than for a low inerts gas. This is due to:

2

• The higher amount of water present in the increased volume of gas. This extra amount of water has to be removed. A larger circulation rate of TEG is therefore required; equipment in the TEG circulation will loop will be larger. Larger volumes of solid desiccant are required to remove the larger amount of water; larger bed sizes result.

present, which requires a larger diameter TEG contactor and larger diameter solid desiccant beds.

For a high inerts gas it is recommended that the ‘CO2

rate’ value in the capital cost indicator versus rate graphs be increased in proportion to the fractional increase in total volume of the gas due to the inerts content, prior to reading the cost indicator values.

Operating costs estimates have been calculated for 3 different cases and are shown in Figure 5: • Solid desiccant at 265 te/hr – Options from two different vendors, one using low

pressure regeneration with atmospheric air and another using CO2

• Liquid desiccant at 265 te/hr – Only a single vendor has provided data. TEG desiccant life has been quoted as 3 -10 years, depending upon the extent of impurities present. A value of 3 years has been assumed for this analysis.

at pressure for regeneration. These cases form the minimum and maximum capital cost packages. A 3 year molecular sieve life has been used, as per vendor advice.

Figure 5 - OPEX estimates for different dehydration systems

Comparing data from the same vendor indicates that the TEG system annual operating cost is significantly lower than that for the molecular sieve package. However, the more basic molecular sieve package, from a different vendor, but for the same raw gas conditions, indicates that the annual operating costs are significantly lower than those for the TEG system. Estimated minimum operating costs for molecular sieve packages are presented versus rate in Figure 6.

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Figure 6 - OPEX for molecular sieve

Operating pressures of 10, 20 and 30 bara were investigated for the same set of post-combustion conditions for molecular sieve packages. Information from vendors is limited; however it suggests that operating pressure has an effect on ope rating costs; the regeneration power consumption passes through a minimum. The actual minimum pressure is expected to vary for individual applications. Limited data indicates that the effect of impurities on molecular sieve operating cost is effectively negligible. The increased bed volume results in an increased capital cost, which impacts onto maintenance costs and taxes and insurance. Desiccant cost increases but regeneration power consumption is reduced.

Selection It is usually most appropriate to consider combinations of different dehydration techniques to achieve the required target moisture content. The relative applicability ranges of the various different dehydration technologies are shown in Figure 7. It is invariably cheaper to offload the final dehydration system by use of more basic techniques, if they can be applied. For example, if saturated low pressure gas is supplied it is beneficial to use the compression/cooling equipment (which have to be provided anyway to reach the export conditions) to raise the pressure, knockout the condensed water and reduce the gas equilibrium moisture content as part of the normal compression process. This has the effects of: • Minimising the moisture fed to the final dehydration package. • Reducing the actual volume of raw gas which has to be processed in the final dehydration

plant, which results in smaller equipment. The presence of certain impurities/contaminants may physically damage solid molecular sieve desiccant. It may be considered prudent to install a short section of guard layer (containing silica gel or activated alumina) immediately above the molecular sieve. The guard layer is better able to deal with the impurities. The guard layer, however, will have a design life and once the guard layer has aged then protection is no longer afforded to the molecular sieve, which will quickly deteriorate. Multiple dehydration techniques in series can be used. For example compression/cooling, followed by a TEG system, followed by molecular sieve polishing. The benefits of such systems are dependent upon t he individual process requirements. They can provide a higher level of product moisture integrity, in the event of a malfunction. The extent of capital cost penalty is process specific.

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In the event that a second molecular sieve dehydration chain is required to process the gas, it may be prudent to consider offloading the molecular sieve system by installing a TEG system upstream. Smaller adsorber bed volumes and / or increased bed adsorption time will result. A cost benefit analysis should be carried out for each application to determine the most cost effective option.

Figure 7 - Ranges of applicability of different dehydration technologies

Basic advice on s election of the most appropriate dehydration technology is provided for dehydration of gaseous CO2 in a tabular format in the report. The pressure at which CO2 drying is required is dependent upon many considerations, including:

• Hydrate formation conditions. • Undesired liquid CO2 formation conditions. • Water solubility in CO2. • Compressor interstage conditions available. These conditions can be limited in some

cases, such as occur with the use of Ramgen high pressure ratio compressors. • Interstage cooling temperatures available. • Minimum temperatures experienced at the point of dehydration and also downstream. • CO2 export pressure.

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• CO2 supply pressure. • Downstream processing requirements, for example liquefaction or cryogenic processes. • CAPEX/OPEX of dehydration equipment.

Operation and monitoring The drier performance should be monitored to ensure that water breakthrough does not occur. It is important that a continuous monitoring system is used; manual sampling and analysis will not be sufficient. The number of available analysis techniques is limited due to the presence of CO2 itself and the potential contaminants. Several companies, who provide industrial moisture measuring instrumentation, were approached. Many declined to assist or did not reply at all. Moisture Control and Measurement Ltd, Systech Instruments, AMCS and Process Analyser Systems Ltd proposed a range of different techniques and provided relevant data. The proposed techniques cover a range of different physico-chemical measuring principles, specifically:

• Laser absorption spectroscopy • Phosphorous pentoxide (P2O5) coated cell • Quartz crystal cell • Silicon sensor

Budget costs for the instrument vary for a single instrument. The relative cost indicator values given in the report exclude the sampling system and analyser housing/building, as these requirements are project specific. However impurities must be considered in detail. Their normal concentration and their concentration ranges during both normal operation and also on excursion needs to be quantified and comprehensively discussed with vendors. It is important that the actual application is fully discussed with the vendors to enable the most appropriate device to be selected. The sampling system can significantly influence the overall performance and recovery time from upset. A properly designed sample system is essential. Sampling usually involves pressure let-down and sample heating will be required to ensure that Joule Thomson chilling does not result in condensation of any of the components present, which can affect both the analyser itself and the analysis result. A reasonable response time is essential to ensure that offspec product is quickly detected and remedial actions taken promptly. The sampling system can have a significant effect on t he overall response time. Consideration of the conditions which the sensor may experience under upset conditions must be included to ensure that damage or prolonged erroneous readings do not occur. Maintenance frequency can be dependent on t he gas quality. Means should be provided to enable periodic cleaning of the sensor and associated lines in the event that a contamination incident occurs. Particulates are a particular issue for some types of device, such as the phosphorous pentoxide device; particulates can block the capillary. Care needs to be taken to ensure that any of the components present are not capable of reaction at the cell surface, where reactions may be catalysed, such as may occur in the presence of platinum electrodes held at temperature. Reactions may cause contamination of the cell or form water and result in erroneous readings. At least two moisture analysis points are recommended; if a fault develops at one location then the second location will act as a backup. The analysis points should be located at different points in the plant: one immediately after dehydration and another further downstream, possibly located after compression, adjacent to the compression and conditioning plant boundary. Suggested remedial actions have been described in the report in the event that excessive moisture ends up in the downstream process. Operating plants should develop plans regarding

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what to do if offspec gas has reached downstream equipment. The actual course of action may be dependent upon the extent of the moisture excursion and the conditions prevalent in the line / equipment at the time.

Further work There are several areas in which additional work is required to enable a full and adequate consideration of dehydration processes and issues. The effects of inerts and impurities on t he CO2 stream physical properties need to be determined. Impurities and inerts can cause:

• Significant changes in the phase envelope. • The saturated water content of CO2 can be significantly increased or reduced.

This has a direct impact on the dehydration equipment, and Joule Thomson cooling in particular. It is therefore important that the effects of inerts and impurities are fully understood; to date this has not been done and this may involve a large amount of work to obtain accurate physical properties. Thereafter further work is required to generate accurate physical property estimation methods to enable these physical properties to be adequately modelled. Hydrates may form prior to water dewing. It has been recommended that the water content selected be < 60% of saturation to avoid hydrate formation. Other references suggest that the maximum amount of hydrates that can be formed with dissolved water in the CCS stream will be too small to cause operational problems. This should be further investigated and the issue quantified. A considerable amount of work needs to be carried out with vendors. Vendor engagement was lacking during this study; many vendors’ opinions have recently changed as a result of:

• The cancellation of most major CCS projects; much work had gone into provision of quotations.

• Failure of the DECC and NER300 competitions to assign the considerable amounts of money originally stated as available for CCS development and establishment.

Work on membranes for use in dehydration of supercritical CO2 is ongoing. Media vendors are continually developing acid resistant grades of solid desiccant to cater for the challenging impurities present in feed gas. Vendors, however, are not prepared to discuss this sensitive area of work.

Expert reviewer’s comments In general, most reviewers felt that the report provides a good background on CO2 dehydration options and the issues surrounding its application to CCS that have not been intensively investigated so far. The majority of the reviewers understood that the quality and quantity of information reported was affected by the lack of vendor support and that further engagement of dehydration vendors in CCS projects is expected to be very limited in 2013.

All reviewers delivered a number of appropriate and valuable comments that will be passed on to AMEC for consideration in the final version of the report.

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Conclusions The purpose of the study was to examine the characteristics of the various dehydration processes and the way they can be best integrated into the CCS system. A number of technologies already exists which can carry out the CO2

Areas requiring further work have been identified, e.g. the effect of inerts and impurities on the physical properties of the CO

dehydration step, in particular the TEG and the molecular sieve systems. However, due to lack of vendor support, the capital and operating information presented in this report is preliminary, fragmentary and associated with uncertainties.

2

stream, but it seems that re-engagement of the vendors will be a priority for any future projects and studies.

Recommendations to Executive Committee

It is recommended that IEAGHG follow up with the research and project activities in this area. Maybe it will be possible to continue and expand on t he existing study at a later date, when vendors are willing to provide more involvement and information. In the meantime it would be a good idea to engage the approached vendors in IEAGHG activities and networks related to CO2 capture and transport.

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POTENTIAL FOR BIOMETHANE PRODUCTION AND CARBON DIOXIDE

CAPTURE AND STORAGE

Ecofys produced a report for IEAGHG on t he global potential for biomass with CCS (IEAGHG 2011/06) which covered a selection of biomass combustion technologies and two biofuel options – bioethanol and FT diesel from biomass. The report received good publicity and interest and has been extensively used. However the report did not cover the production of biomethane. It was proposed by at the 39th ExCo to extend the Ecofys study with a supplement using the same methodology and data sources to estimate the potentials for production of biomethane. This study was undertaken by Ecofys of The Netherlands. The draft report was sent out for peer review, and these review comments were incorporated for the final report. An attached draft overview has been prepared for member’s comments and approval.

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POTENTIAL FOR BIOMETHANE PRODUCTION AND CARBON DIOXIDE CAPTURE AND STORAGE

In 2011, the IEAGHG R&D programme published a report on t he global potential of six technology routes that combine biomass with carbon capture and storage (CCS) titled: Potential for Biomass and Carbon Dioxide Capture and Storage (IEAGHG 2011/06). The study considered four electricity production routes and two routes for biodiesel and bio-ethanol production. In this report we address two additional technology routes combining the production of biomethane with the capture and storage of the co-produced carbon dioxide. The aim of this study is to provide an understanding and assessment of the global potential - up to 2050 - for BE-CCS technologies producing biomethane. We make a distinction between: Technical potential (the potential that is technically feasible and not restricted by economical limitations) and the Economic potential (the potential at competitive cost compared to the reference natural gas, including a CO2 price). We assess t wo concepts to convert biomass into biomethane: gasification (followed by methanation) and anaerobic digestion (followed by gas upgrading). The types of feedstock we take into account are energy crops, agricultural residues and forestry residues. For digestion we also consider biogenic municipal solid waste, and animal manure and sewage sludge as feedstock.

Table 1, Figure 1 and Figure 2 summarise the most eminent results of this assessment. The results show the maximum technical potential in 2050 is found for the gasification route with CCS. In this route 79 EJ of biomethane is produced, leading to the removal of 3.5 Gt of CO2 from the atmosphere. This is a significant potential when compared to the current (2009) global natural gas production of almost 106 EJ. On top of that, the substitution of 79 EJ of natural gas with biomethane would result in an additional greenhouse gas emission reduction of 4.4 Gt of CO2 equivalents. In total, almost 8 Gt CO2 eq. can be reduced through this route1

and with it provides a significant reduction potential compared to the global energy-related CO2 emissions, which grew to 30.6 Gt in 2010 (IEA 2011).

The total technical potential for the digestion based route with CCS (digestion-CCS) is lower, 57 EJ, as a sm aller fraction of the biomass potential for energy crops and residues (forestry and agriculture) can be used in this technology route as the technology is less suitable for the conversion of lignocellulosic biomass. The potential of the more suitable feedstock for digestion, being municipal solid waste (MSW), animal manure and sewage sludge, is relatively small. The potential of these sources sums up to almost 12 EJ (0.7 Gt CO2eq) of biomethane in the year 2050.

1 Note that 1 Gt of negative emissions is not the same as 1 Gt of emission reductions. Generally speaking, the emission reduction potential of BE-CCS options is equal to the amount of negative emissions plus the emissions of the technology or fuel it replaces, in this case natural gas. Throughout the remainder of this report we will indicate negative emissions, not avoided or reduced emissions, unless otherwise indicated.

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Table 1 Overview of global technical and economic potential per BE-CCS route for the view years 2030 and

2050

Technology route Year Technical potential Economic potential

Primary energy

Final energy C

O2 stored

GH

G balance (C

O2

eq) Final energy G

HG

balance (C

O2 eq)

EJ/yr Gt/yr Gt/yr EJ/yr Gt/yr

Gasification 2030 73.1 44.8 2.4 -1.8 2.7 -0.1

Gasification 2050 125.6 79.1 4.3 -3.5 4.8 -0.2

Anaerobic digestion – EC and AR* 2030 43.3 26.0 1.2 -1.1 1.4 -0.1

Anaerobic digestion – EC and AR* 2050 74.7 44.8 2.1 -2.1 2.4 -0.1

Anaerobic digestion - MSW 2030 5.1 3.1 0.1 -0.1 3.1 -0.1

Anaerobic digestion - MSW 2050 10.6 6.4 0.3 -0.3 6.4 -0.3

Anaerobic digestion - Sewage/ Manure 2030 7.4 3.0 0.2 -0.2 3.0 -0.2

Anaerobic digestion - Sewage/ Manure 2050 13.8 5.5 0.4 -0.4 5.5 -0.4

Anaerobic digestion - Total 2030 55.9 32 1.5 -1.4 7.4 -0.4

Anaerobic digestion - Total 2050 99.1 56.7 2.8 -2.7 14.3 -0.8

*Energy Crops and Agricultural Residues One of the interesting features of biomethane production for grid injection is that the separation of CO2 is already an intrinsic step in the production process. This means that the incremental costs of adding CCS is potentially low.

0

20

40

60

80

100

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140

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2050

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2050

Gasification Gasification Anaerobic digestion - EC

and AR

Anaerobic digestion - EC

and AR

Anaerobic digestion - MSW


Anaerobic digestion -

Sewage/ Manure


Sewage/ Manure

EJ/

year

Technical potential (primary energy) Technical potential (f inal energy)

Economic potential (negative GHG emissions)

Figure 1 Global technical and economic energy potential (in EJ/yr) per BE-CCS route for the view years

2030 and 2050. Note that potentials are assessed on a route by route basis and cannot simply be

added, as they may compete and substitute each other.

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0

1

2

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5

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Gasification Gasification Anaerobic digestion - EC

and AR

Anaerobic digestion - EC

and AR




Sewage/ Manure


Sewage/ Manure

Gt

CO

2 eq

./yr

Technical potential (CO2 stored when exploiting the full biomass potential)

Technical potential (negative GHG emissions)

Economic potential (negative GHG emissions)

Figure 2 Greenhouse gas emission balance (in Gt CO2

eq/yr) for the global technical and economic potential

per BE-CCS route for the view years 2030 and 2050. Note that potentials are assessed on a route by

route basis and cannot simply be added, as the biomass resources may compete with each other.

The economic potential for biomethane-CCS is dominated by the CO2 price and the natural gas price, which may vary per location. For almost all combinations of feedstock (energy crops, agricultural residues and forestry residues) and conversion technology there is only an economic potential at high natural gas prices (>11 €/GJ) combined with CO2 prices of at least 20 €/tonne. An exception is the use of municipal solid waste (MSW) and sewage sludge in combination with anaerobic digestion which show already an economic potential at a CO2 price of 20 €/ tonne CO2 and natural gas price of 6.7 €/GJ. The economic potential is the highest for digestion-CCS of animal manure/sewage sludge and MSW. When assuming a CO2 price of 50 €/tonne, the economic potentials in 2050 reach 5.5 EJ (-0.4 Gt CO2 eq) for animal manure/sewage sludge and 6.4 EJ (-0.3 Gt CO2

eq) for MSW. Drivers for the deployment of biomethane are (EU) targets for biofuels, increasing security of supply (e.g. by reducing the import dependency of natural gas), and the presence of existing natural gas transport and distribution infrastructure.

Barriers typical for the deployment of digestion-CCS are high biomass transport costs which limit the plant size and it is likely that the small size of digesters also results in a high cost for connecting to the CO2 and natural gas infrastructure. Nevertheless, anaerobic digestion-CCS of MSW, sewage sludge and animal manure might become a promising niche application that offers the opportunity to process waste, reduce carbon emissions and produce valuable biomethane. Further it is important for the digestion-CCS route to look for possible valuable end-use of captured CO2 to enhance business case for smaller systems with CO2 capture (e.g. CO2

use in industry and in horticulture).

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The gasification-CCS route fits best with a large scale infrastructure for the transport of biomass, natural gas and CO2; that is, a more centralised production of biomethane combined with CCS. The implementation of decentralised production of biomethane and end-use, in combination with CCS is deemed unlikely, due to infrastructural requirements for both CO2

and natural gas.

Expert reviewer’s comments Comments were received from five reviewers. The majority of the negative comments stemmed from the need to have read the original report IEAGHG 2011/06, and these peer reviewers were different to those used on that report (only one being the same). This follow up report on biomethane refers to the original report for assumptions and detailed explanation of methods, and therefore, as such detailed information is missing the majority of reviewers did not know the process undertaken. It was therefore recommended that the report’s conciseness was improved and the report shortened to enable this report to be an addendum of the original report. Though more concise, further explanation in some areas of the report was necessary, such as sustainability criteria used and when stressing the major findings by putting them in context to the approach used, uncertainty and why this is important. The terminology in the draft report appeared a little inconsistent, and needed to be revised, and a little more discussion/explanation was needed when discussing terms to assist readability. There were various technical aspects which needed addressing also. There are some assumptions and discussion points which would be useful to address, such as avoided methane emissions versus GHG savings, the sustainability criteria, CO2

price allocation producer versus end user and branched or centralised grids; and discussion points which could be easily removed as they add little to the report. Overall, the reviewers thought that with the revisions, the report would be a good contribution to the subject. The reviewer’s comments were then addressed by the contractors in a revised final report. Conclusions • Biomethane production in combination with carbon capture and storage has the technical

potential to remove up to3.5 Gt of greenhouse gas emissions from the atmosphere in 2050 • Annual greenhouse gas emission savings could be almost 8 Gt in 2050 when natural gas is

replaced by biomethane production with CCS. • The economic potential depends strongly on the CO2

price and natural gas price.

• Small scale biomethane production with CCS based on digestion is most likely restricted to niche market applications.

• Large scale gasification based production of biomethane with CCS could have potential in

regions where large scale infrastructure is already in place for the transport of biomass, natural gas and CO2.

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Overall, it is concluded that the economic potential for biomethane combined with CCS is most likely restricted to those regions that have favourable (high) natural gas and CO2 prices, and have favourable infrastructural conditions. A logical next step in understanding the potential of technology routes that combine biomethane production with CCS would be to assess more location specific (region, country, local area) conditions. The combination of elements like presence of suitable industry, infrastructure and biomass import facilities, and technical knowledge may provide synergies for economical production of biomethane combined with CO2 removal and re-use or storage. A focus could be on regions with demand for CO2

(industry, horticulture) or starting CCS infrastructure, (dense) natural gas infrastructure, high (local) availability of biomass and/or high natural gas import.

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Summer School Update for 2014 and 2015

Review of the second phase A full review of the second phase (2011-2014) will be held in 2014. T he results will be discussed with the International Steering Committee at GHGT-12 and recommendations made for ExCo to consider. 2013 - UK Since the withdrawal of the planned hosts for the 2013 S ummer School in Spain (due to circumstances beyond their control), two expressions of interest were received from European bodies for the 2013 Summer School. Both were very sound, and the one selected was the University of Nottingham, UK. The dates agreed are 21 to 26 July 2013. In terms of student applications, 137 applications were received, and 60 s tudents selected. Work is underway in organising. Sponsors are being sought by the hosts. 2014 - USA Two informal expressions of interest were received from North American potential hosts for the 2014 Summer School, from The University of Texas at Austin and from West Virginia University (WVU). Both were followed-up, but only one formal expression of interest was received, from The University of Texas at Austin. This was a sound expression of interest with early confirmation of sponsorship, and therefore it was accepted and the 2014 Summer School will be in Austin. 2015 – Aruba? To follow the cycle of the Summer Schools , Asia or Australasia would be the region to host for 2015. However an unexpected but serious expression of interest has been received from the Dutch organisation TNO, to host a Summer School in the TNO offices on the island of Aruba in the southern Caribbean (see map below). This office was set up to focus on and service Latin America, and so a Summer School there could be considered as a regional one for Latin America. There has not been an IEAGHG Summer School in that region to date. TNO have indicated that sponsorship would be provided by TNO, the Prime Minister of Aruba, and from South American industrial organisations. The ExCo is asked to consider this offer, whether to accept, and if so whether for 2015 or another year.

More information is provided from TNO’s expression of interest below.

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IEAGHG Summer School Aruba 2015 Aruba has been working diligently to position itself as the Green Gateway to the Caribbean and Latin-American region and a knowledge hub for sustainable (energy) technology. It has done this through partnerships with renowned institutes such as TNO, Harvard and the Carbon War Room Smart Island Strategy initiative. In 2010 Aruba hosted its first Green Aruba conference with All Gore as its key note speaker. The event has grown since then and in 2013 it will be combined with the Caribbean Regional Energy Forum (CREF), the region’s most prestigious sustainable energy conference. In 2012 Aruba hosted the first annual Aruba-Harvard Sustainability summit. The summit was chaired by Professor Dan Schrag, Director of the Harvard University Center of the Environment and a member of the United States President’s Council on Science and Technology. Aruba not only has an impressive track record of accomplishments in the area of sustainability, it also offers an attractive setting and high quality infrastructure. Thanks to its strong tourism industry it has great connections to major airport hubs in Europe, the United States and South America. Aruba has a strong reputation as a high quality destination with an excellent service level and boasting some of the highest rates of returning visitors in the Caribbean region. The government and business community of Aruba have been very supportive in the organization of these types of events. In 2012 TNO opened the doors of the Caribbean Branch Office TNO. Since then TNO has developed, with its Aruban partners, a Roadmap Sustainable Aruba 2020. This document outlines sustainable energy goals and actions. One of the flagship programs is ‘Smart Community Aruba’ a 20 unit experimental residential area in which smart-grid applications and sustainable energy integration will be tested and demonstrated in a real live environment. The first tranche is scheduled to be completed in the Fall of 2013. The neighborhood is on track to be finished Fall of 2014. Smart-Community will offer an inspiring example of sustainable living and demonstrate sustainable technologies. TNO has been one of the leading CCS research institutes and therefore well suited to co-organize and host the 2015 IEAGHG Summer School. TNO researchers are actively engaged in all aspects of CCS. Since 2009 TNO has led CATO-2 the Netherlands National CCS research program. The University of Aruba, housed in an old convent, offers a very inviting setting for summer school and joint research sessions. Aruba offers excellent hotel and conferencing facilities combined with some of the best beaches in the region and rugged nature at the Arikok National Park. Creating ample opportunities for entertainment, networking and socializing for summer school participants. Aruba’s Green Gateway ambition, its powerful story of the transformation of a nation and its partnerships to become a sustainability hub for the region make Aruba the ideal location for the 2015 IEAGHG summer school. Emile Elewaut, TNO. 21 March 2013

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CONFERENCE UPDATE

OCC3 – 9th-13th September 2013, Leon, Spain The conference will be hosted by CIUDEN and held in the Templar Castle in Leon with a site visit on the 13th to the Compostilla Project. 160 abstracts were received with the programme due to be finalised 9th May. The final programme will have up to 4 parallel sessions over three days and will incorporate three specialist workshops on the closing day. PCCC2 – 17th-20th September 2013 Bergen, Norway This conference is being supported by CLIMIT and will include a site visit to the Test Centre Mongstad (TCM) on the 20th. The call for abstracts attracted 94 submissions with the final programme being available on the 23rd April. GHGT-11 Feedback GHGT-11 saw a continuation of the year on year increase in numbers of submitted abstracts to the conference at 1221 all of a very high quality meaning the only obvious abstracts for rejection were the out of scope of the conference submissions. As a result, the GHGT-11 conference had seven parallel streams across all 11 technical sessions producing 296 oral presentations and with the most successful poster session yet, a further 621 posters were presented across 2 s essions The number of attendees was 1293 from 40 countries, this was a 7% decline from GHGT-10 which had seen the largest number of attendees of any of the GHGT conferences. Taking into consideration the location and current economic climate, the attendee level at GHGT-11 shows the conference is the frontrunner in CCS conferences. Sponsorship, although harder to come by this time than previously, still reached the target levels with a change in demographics, with much of the total coming from Japanese sponsors. The feedback survey was completed by 21% of the attendees and gave many positive responses for the technical programme, with the only negative comments relating to the Conference Dinner – points that will be taken forward in the planning for GHGT-12. The Summary Brochure for GHGT-11 has been produced and is available on the www.ieaghg.org and www.ghgt.info websites at the time of writing; we are waiting a final date for the GHGT-11 proceedings publication on Energy Procedia. GHGT-12 Austin Texas, USA 5th-9th October 2014 The Steering Committee continues to meet on a regular basis with the Technical Programme Committee now also agreed and having begun the selection of the Technical Themes for the conference. Planning is ahead of schedule. Sponsorship is now being sought for GHGT-12. GHGT-13 Venue Selection Following the General Manager having received three expressions of interest from the target area of Europe, to host GHGT-13 (2016), invitations to tender were sent out to the UK, Norway and Switzerland, on r eceipt of the invitation, the UK notified IEAGHG of a d ecision to withdraw from the tendering process. Tenders were received from Norway and Switzerland. A presentation of both tenders will be made during the ExCo for member’s feedback.

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PRIORITISATION OF NEW STUDIES

Prioritisation of new studies 15 proposals for new studies were sent to members and sponsors for voting. These consisted of:

• 10 proposals re-submitted from the previous round of voting (6 from members) • 5 new proposals, 3 from members and 2 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 36 of the 46 members and sponsors, representing a 78% 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

43-03 Evaluation for Various Process Control Strategy for Normal and Flexible Operation of Post Combustion Capture process

11 6 23

43-02 Energy Storage and CCS 14 4 22

43-12 Economics of well stimulation with CO2 for shale oil / gas production

12 5 22

43-06 Oxy Gas Turbine Power Plants 17 2 21 43-11 Public Perception of CO2 Pipelines 17 2 21

43-08 Evaluation of CO2 Adsorption Process in Natural Gas Production

6 7 20

43-10 Techno-Economic Evaluation of the Potential CO2 Capture Application in Pulp and Paper Industry

10 4 18

Other proposals

43-05 Production of Hydrogen with CO2 Capture 12 1 14 43-07 Fuel Cells for Power Generation with CCS 7 2 11

43-01 Optimization of Water Usage/Treatment in Oxy-Coal Fired Power Plant

9 1 11

43-14 Closing the Water Loop 10 0 10 43-04 Floating Capture plant and buffer storage 6 1 8

43-13 Comparison of the water usages of low-CO2 power generation technologies

8 0 8

43-09 Surplus Electricity for Decarbonizing Transport

4 0 4

After reviewing the outstanding studies waiting tendering and our current study commitments we will be able to take on up to 5 or 6 new studies. The outline proposals for the 7 studies which received the most votes (over 13 weighted votes) have been included here for members to consider. However 43-11 Public Perception of CO2 Pipelines is partly being covered by a

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new study for GCCSI on CO2 Pipelines (see paper GHGT/13/32) so will be deferred until that is completed. 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? Technical Reviews and scoping studies Several ideas for studies are more appropriate to undertake as Technical Reviews or ‘scoping studies’ instead of full Technical Studies. These are smaller pieces of work normally undertaken in-house by IEAGHG staff. This may be because the work required is smaller than a Technical Study, such as a literature review, or for the first assessment of a new area of development, which can itself be used a b asis for a d ecision on whether to progress to propose a full Technical Study. S ome new ideas from members may be taken-up first as Technical Reviews. The following are the current list. These will be undertaken as resources allow. Title ExCo Comments Feasibility and costs of CO2 storage in geological strata with relatively low permeability and porosity

41 Source SA. Defer until Implications of Shale Gas Production Study completed..

Biomass Based FT Synthesis Process for Aviation Fuel

40 Low voting. New topic so look at TR first.

Hubs and Clusters Source EON. No background provided.

PCC technology based upon Bio-based material Response to major CO2 leaks TR after FEED report out

and CO2RISKMAN report out

Complexity on industrial sites CO2 Storage Wells/Site Abandonment 42, 41 The EU CO2CARE project

covers this topic. Study deferred until CO2CARE completes (IEAGHG attended CO2CARE meeting 12-13 March 2013)

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EVALUATION FOR VARIOUS PROCESS CONTROL STRATEGY FOR NORMAL AND

FLEXIBLE OPERATION OF POST COMBUSTION CAPTURE PROCESS 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 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 43-03 Meeting 43nd ExCo, Regina, Canada Title Evaluation of Process Control Strategies for Normal, Flexible and Upset

Operation conditions of Post Combustion Capture process Subject area Post Combustion Capture Originator IEAGHG Description Solvent based CO2 post combustion capture (PCC) at power plants requires

high operational energy. The energy consumption in the reboiler of the stripper is very large; typically around 15-30% of the net power generated by a coal fired power plant [1]. Coal-fired power plants are operated flexibly over a large operating range. Moreover, any upset conditions like equipment failure in the process can influence the operation of whole CCS chain. For optimal operation, the post combustion CO2 capture process is required to follow the power plant operation load and to separate the carbon dioxide at every operating point with minimum energy demand. Design of simple control systems in a systematic manner by selecting the right individual and combinations of controlled variables (“self-optimizing controlled variables”) to enable chemical processes to operate near optimum has been reported in literature [2]. Good PCC process controlled variables (CV’s) are CO2 capture rate, temperature of lean solvent entering the absorber, stripper pressure (due to amine degradation at higher pressure), and stripper condenser temperature. Therefore, a plant should be controlled based on these CV’s for its optimal operation. The aim of this project is to develop the process control strategy, to select the right controlled variables and design economically efficient control structures for operation of a post combustion capture process with minimum energy requirements for coal and natural gas power plant. The control structure of PCC process for power plant operating range of 40 t o 100% load will be developed. Control strategy in potential upset conditions could also be evaluated but this may be deferred to a later study. The following is the scope of this study: • Identify different operation regions and controlled variables for PCC

process in normal, part load and upset conditions. • Develop control strategy for optimal operation of PCC process in

normal, part load and upset conditions. • Evaluation of the process performance improvements from different

control strategies. • Estimation of the costs related to the installation of these process control

systems. Resources required

Financial: Average Management: Average

Links with other on-going or proposed studies

Reference: [1] M.S. Jassim, G.T. Rochelle, Innovative absorber/desorber configurations for CO2 capture by aqueous Monoethanolamine, Ind. Eng. Chem. Res. 45 (2006) 2465–2472. [2] Skogestad, Control structure design for complete chemical plants, Comput. Chem. Eng. 28 (2004) 219–234.

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ENERGY STORAGE AND INTERACTION WITH CCS

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 43-02 Meeting 43rd ExCo, Regina, Canada, May 2013 Title Energy storage and interaction with CCS Subject area CO2 capture and integrated systems Originator IEAGHG Description Energy storage is expected to be important in future electricity systems, to

cope with the variability of electricity demand, the variability of some renewable energy sources and the relative inflexibility of some low-CO2 power generation technologies.

This study will review energy storage techniques and their current state of development, operating parameters (storage and discharge rates, capacities, etc.), energy efficiency, costs and other significant issues such as health and safety and availability of sites where they could be installed.

Energy storage technologies will have implications for CCS plants, including their operating flexibility requirements, capacity factors and revenues. Also, some storage technologies can be integrated with CCS plants, for example production of hydrogen by electrolysis of water creates an oxygen by-product which could be stored and used in CCS plants. The report will assess the implications of energy storage for CCS plants.

The study will focus mainly on large scale energy storage but technologies that could be used for storage at a large number of small scale distributed locations, for example batteries in electric cars, may also be considered. The report will consider the following types of energy storage technique:

1. Techniques which take in electricity and which produce electricity at a later time, including pumped hydro storage, compressed air storage, fly-wheels, capacitors and various types of batteries.

2. Storage of hydrogen produced by CCS plants or by electrolysis of water using renewable electricity, for later use by distributed energy consumers or for large scale electricity generation.

3. Production and storage of liquid or gaseous oxygen produced in air separation plants or by electrolysis of water, for later use in CCS plants.

4. Storage of heat, for example in hot water for district heating.

Resources required



Separate studies on hydrogen production, and use of surplus electricity for decarbonising transport are being proposed. If these studies are selected, IEAGHG shall co-ordinate the scopes of work to ensure there is no duplication of effort.

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ECONOMICS OF WELL STIMULATION WITH CO2 FOR SHALE OIL / GAS

PRODUCTION 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 43-12 Meeting 43rd ExCo, Regina, Canada, May 2013 Title Economics of well stimulation with CO2 for shale oil / gas production Subject area Storage and Utilisation of CO2 Originator EnBW - Energie Baden-Württemberg AG Description Hydraulic stimulation of oil&gas reservoirs inducing artificial fractures is standard

operation in the E&P business for almost 70 y ears. Production of oil and gas from shale resource systems in recent years can largely be attributed to improved fracking technology in respective plays. However, in most cases the medium of choice during hydraulic stimulation has been water / water-based composite despite adverse effects on the reservoir and ultimately well performance. The main difference between shale resources, “unconventional” reservoirs, is the nature of the hydrocarbon-bearing rock:

• “conventional” reservoirs: sandstones, limestones, fractured rocks • “unconventional” shale reservoirs: shale or claystone

Unconventional reservoirs show much greater interaction with aqueous stimulation fluids, compared to conventional ones. Depending on the mineralogy, the reservoir is irreversibly damaged by aqueous stimulation fluids in several ways:

• Water causes swelling of some clay minerals effectively reducing induced permeability by closing fractures

• Water is adsorbed to clay minerals effectively blocking induced permeability • Depending on the wetting system, increase of water saturation can negatively

influence mobility of hydrocarbons to such an extent that parts of the reservoir may become inaccessible for production

• In order to prevent or lessen negative effects of aqueous frac-fluids on shale reservoirs, chemicals are added to the stimulation fluid.

The ideal stimulation medium for shale resource systems would therefore be a gas (e.g. propane, nitrogen, CO2) that does not interact with the reservoir, does not need so many additives compared to water-based solutions and can be re-produced effectively during the well clean-up phase. Frac-jobs with CO2 have already been performed and are sometimes the only solution in high-temperature reservoirs (above 100°C). A large scale application of CO2 for stimulation purposes has not yet happened. This study will investigate the economics of fracturing shale resource systems with CO2 as the main frac-fluid at a large scale. This will include:

• Overview of existing industrial commercial applications of fracturing with CO2 o Relative performance of CO2 compared with water based stimulation o Costs, volume of CO2 required, other important project data

• Economics of overall process: o Amount of CO2 required o Amount and nature of additives required o Quantification of CO2 volume remaining in the shale resource reservoir

vs. re-produced CO2 o Surface facilities required for CO2 frac-job o Clean-up process o Prediction of well performance (i.e. CO2 ratio)

Resources required



Potential Implications of Gas Production from Shales and Coal for CO2 Geological Storage (ARI – in progress)

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OXY-COMBUSTION GAS TURBINE POWER PLANTS




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Reference number 43-06 Meeting 43rd ExCo, Regina, Canada, May 2013 Title Oxy-combustion gas turbine power plants Subject area Capture of CO2 – Power Sector Originator USA and IEAGHG Description There is increasing interest in oxy-combustion gas turbines for power

generation with CCS, including by some major plant manufacturers. Such turbines use recycled CO2 and/or steam as the working fluid instead of air. They can be used for natural gas and they can also be combined with solid fuel gasification as an alternative to IGCC with pre-combustion capture. The natural gas fired oxy-combustion gas turbine cases included in IEAGHG’s 2005 oxy-fuel study and a study by NETL published in 2010 had higher costs than post combustion capture. However, there are a large variety of oxy-combustion gas turbine cycles and recently published information indicates that a natural gas power plant with CCS based on the NETPOWER process could have a substantially higher efficiency (59% LHV) and lower costs than a plant with post combustion capture. IEAGHG is well positioned to undertake an independent evaluation of these claims. The proposed study will

• Describe the leading natural gas fired oxy-combustion gas turbine cycles, including ones that are being developed commercially, particularly by NETPOWER and CES, and ones that have been proposed by academics, such as the Matiant and Graz cycles.

• Estimate the performance and efficiency of selected cycles by flowsheet modelling. The assessment will include oxygen production and CO2 compression which are important components. The sensitivity of the overall performance to ambient conditions and the performance of plant components will be assessed.

• Estimate capital and operating costs, costs of electricity and CO2 abatement and the sensitivities to the costs of major components.

• Use of high-CO2 natural gas will be assessed (the incremental cost of capture of the CO2 in the natural gas could be near zero).

• Provide an outline assessment of operability/flexibility. • Assess opportunities for integration with industrial processes and

CO2 utilisation, which should help to identify the most appropriate markets for oxy-combustion gas turbine systems.

• Assess the current development status, key uncertainties and the development and demonstration needs.

• Identify ways in which coal gasification could be combined with oxy-combustion gas turbines. The performance and costs of the most promising configuration will be assessed and compared to IEAGHG’s new baseline IGCC with pre-combustion capture.

Resources required



IEAGHG has an on-going techno-economic study on baseline coal fired power plants with CCS. The coal oxy-combustion turbine case in this proposed study shall be compared to the new baseline coal plants with CCS.

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PUBLIC PERCEPTION OF CO2 PIPELINES The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on t he 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 43-11 Meeting 43rd ExCo, May 2013, Regina Title Public Perception of CO2 Pipelines Subject area Transport Originator IEAGHG Description Much if not all of the public perception work to date has focused on storage

issues. However as we develop new projects and transport CO2 offshore the public in Europe is likely to confront a planning proposal for a CO2 pipeline running through their area than they are a storage site. Europe does not have any experience of large scale CO2 pipeline construction/operation so this will be a new element for many to consider. Europe does however have experience from developing natural gas pipeline infrastructure that might be relevant in cases. I n the USA and Canada they have experience of CO2 pipeline construction and operation and new long distance pipelines like the one from Beulah, North Dakota to Weyburn in Saskatchewan have been built in recent times, so there may be some experience on CO2 pipeline public perception that is transferrable. However, one must note that the population densities in the two regions are very different and the environmental sensitivities of the regional populations might be very different.

It seems an appropriate time to consider the public perceptions in different regions to CO2 pipelines, to understand what people’s concerns might be before construction of such pipelines begins in earnest. The study should provide an early reference point on issues of concern that could be used to build a public awareness campaign in advance of the pipeline announcement and act as a tool for project developers.

The study would look at experience from natural gas pipeline developers and what issues will be translatable to CO2 pipelines as well as exploring what additional issues might arise from CO2 pipeline development. The study should use case studies from projects in the UK on public perception of CO2 pipelines undertaken during the development of the CCS FEED work in the UK and any other relevant activities in this field. For instance the public consultation process for the Weyburn pipeline could also be a relevant case study

The study should then go on to look how an expansion of the CO2 pipeline system in the USA/Canada might be perceived. The project would then go on to look at what reference material for a p ublic consultation activity related to a new pipeline development might be need and indicate what information could be readily utilised, such as US DOT safety record data, and identify any new information that might need to be developed for such a campaign.

Resources required



1.) Social Research Network 2.) Key Messages for Communication Needs for Key Stakeholders 3.) CO2 Pipeline Infrastructure

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CO2 CAPTURE IN NATURAL GAS PRODUCTION BY ADSORPTION PROCESS FOR CO2

STORAGE, EOR AND EGR




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Reference number 43-08 Meeting 43rd ExCo, May 2013, Regina Title CO2 Capture in Natural Gas Production by Adsorption Process for CO2

Storage, EOR and EGR Subject area Capture of CO2 – Industry Originator IEAGHG / University of Regina Description CO2 capture in natural gas production has been successfully demonstrated in

several projects like Sleipner, Snøhvit, In Salah, Zama and Gorgon for CO2 storage and EOR purpose. The natural gas from these projects generally contains 8-14% CO2. Whereas several natural gas fields in Southeast Asia (Indonesia, Vietnam, Thailand & Brunei) contain high CO2 concentrations up to 80%. Future demand in natural gas will initiate development of these natural gas fields in South-East Asia. Therefore, there is a requirement to evaluate CO2 capture technology to reduce emissions from natural gas production. CO2 capture from natural gas can be performed by chemical solvent as well as by solid sorbent based CO2 capture technology. CO2 capture by adsorption technology has a potential to reduce the energy requirement and capital cost due to smaller equipment size and technologies like activated carbon are reaching the field testing stage. Physical adsorbents and pressure swing adsorption (PSA) are considered to be suitable for CO2 capture at higher CO2 partial pressure. Whereas at low CO2 partial pressure, adsorbents with strong basic functionalities and temperature swing adsorption (TSA) is favourable. Currently a wide variety of solid sorbents are being developed to separate CO2 from flue gas like zeolites, activated carbon, calcium oxides, hydrotalcites, supported amines, metal-organic framework (MOF) materials. The aim of this study is to evaluate different CO2 adsorption technologies for different CO2, impurities and moisture concentrations present in natural gas production. The impact of CO2 quality requirement for different purposes like CO2 storage, EOR and EGR on a dsorption process will be evaluated. Moreover, impact of onshore and offshore natural gas production on CO2 adsorption process design will also be looked into. Scope of work: • Evaluate techno-economics of various adsorption processes and their

configurations (like PSA and Vacuum Swing adsorption (VPSA), TSA, Electric swing adsorption (ESA), Hybrid process like Pressure–Temperature swing adsorption (PTSA) etc.) for small to large scale CO2 capture in natural gas production onshore and offshore.

• Evaluate the effect of CO2, moisture and other impurities concentration in the natural gas and impact of produced CO2 quality requirement on different adsorption process performance.

• Evaluate feasibility of advanced solid sorbents like carbon nanotube, metal organic frameworks (MOFs), functionalized fibrous membranes and poly-ionic liquids.

Resources required



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TECHNO-ECONOMIC EVALUATION OF DEPLOYMENT OF CO2 CAPTURE IN AN

INTEGRATED PULP & PAPER MILL The proposal submitted to the members for this study as part of the voting round is attached for reference. A presentation on t he 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 43-10 Meeting 43rd ExCo, May 2013, Regina Title Techno-Economic Evaluation of Deployment of CO2 Capture in an

Integrated Pulp and Paper Mill Subject area CO2 capture and integrated systems Originator IEAGHG Description Globally, the pulp and paper industry is the fifth largest industrial sources of

CO2 emissions. Recently, IEA CCS roadmap has identified this industry with potential for CCS deployment in industry outside the power sector.

This study would therefore complement earlier industry CCS studies done by IEAGHG. A group of studies across industry would assist IEAGHG in assessing the potential for CCS introduction in industry and help us guide future road mapping activities by IEA.

The most commonly used process in the production of the pulp consists of chemical and mechanical pulping from virgin woody biomass. Recently, significant amount of papers are also produced from recycled fibres. Mechanical pulping physically shred the wood using grinders and heat to recover the fibre for paper production. Typically 90% of the tree is recovered as final paper product. On the other hand, chemical pulping requires chemicals (sulphates) to separate the fibre from the wood. Typically, only 50-60% of the wood from the tree are recovered as final paper product. Both pulping process would generally require “cooking” of the woody biomass by using steam.

This industry is the largest user and producer of renewable energy (around 50% of the primary energy consumption comes from biomass). They generally used waste biomass derived from their own processes as fuel to the boilers, evaporators and furnaces to supply the steam, heat and electricity requirements of the mill. Significant part of the waste biomass obtained from pulp and paper industry consists of wood residues, sludge and black liquor.

As part of the Biomass CCS and Industry CCS series, this study aims to evaluate the cost of deploying CO2 capture technology in the pulp and paper industry. A s most fuel used by the pulp and paper industry are biomass derived fuel and if woody biomass are sourced sustainably, any CO2 emissions captured from the pulp and paper mill should contribute to a “negative” emissions.

The study shall focus on an integrated pulp and paper mill based on Kraft process; and to evaluate the options to incorporate CO2 capture based on MEA solvent. The resulting study will provide a reference document for the techno-economic evaluation of deploying CO2 capture technologies in an integrated pulp and paper mill.

Furthermore, pulp and paper mills are often linked to CHP depoloyment. This study would also include the evaluation of impacts of CCS on CHP operations.

Resources required



1.) Biomass & CCS – Guidance for Accounting for Negative Emissions 2.) Techno-Economic Evaluation of Biomass Fired or Co-Fired Power

Plant with Post-Combustion CO2 Capture 3.) All Industry CCS Studies (Oil Refining, Cement, Iron and Steel)

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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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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 sixth status report was prepared in December 2012. GCCSI were a Silver Sponsor for GHGT-11. GCCSI funded the Mentored Student Programme at GHGT-11, which funded students from developing countries to attend GHGT-11 and provided a programme of an introductory seminar, mentored sessions, and a conclusions session. This ran successfully. The scope of works for Phase 2 of What Have We Learnt from Large-scale Operational Projects has been developed and discussed with GCCSI at a meeting on the10 April in Canberra, and is proceeding in-house by the IEAGHG team. GCCSI are also collaborating into the IEAGHG study on Methodologies and Technologies for Mitigation of Undesired CO2 Migration in the Subsurface. GCCSI are providing expertise, contributed to the specification and the kick-off meeting, and will be co-badging the final report. Also under a sep arate contract, the General Manager is a m ember of GCCSI’s Technical Advisory Committee. This contract has been renewed until June 2013. The main GCCSI contract with IEAGHG ended on 10 December 2012, with some funds unspent. GCCSI negotiated and agreed with IEAGHG a t ime extension of one year to use these unspent funds on specific activities. These activities are three studies specified by GCCSI and sponsorship of the Monitoring and Environmental Assessment Networks Combined meeting in August in Canberra. The three studies are:

a. Comparing market-driven and managed approaches to maximising CO2 storage resources in the mature CCS futures

b. Assessment of the Potential Barriers to the Deployment of the CCS in the Cement

Industry

c. Assessing the current status of CO2 pipeline infrastructure The studies have to complete and report by the end of the contract extension i.e. December 2013, so have been contracted as quickly as possible at the start of 2013. Two were single tenders and one was a competitive tender. More information on the three studies is provided in the rest of this paper. These are the draft outlines. The final studies may differ slightly.

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Study a. Comparing market-driven and managed approaches to maximizing CO2 storage resources in the mature CCS futures Purpose: Under current arrangements and regulations, licensing of CO2 storage sites is likely to follow a ‘market-driven’ approach in which applications for licenses for individual projects are submitted to regulators and may be considered in isolation. These storage sites will have been selected by their operators on a “most economically advantageous” basis, matching the needs of individual or clusters of CCS projects. However, basins have multiple uses and increased pore fluid pressure in any reservoir formation resulting from CO2 injection in one project may reduce storage capacity and increase costs in adjacent sites, because of increased reservoir pressures, potentially wasting good sites. A more strategic approach might ensure basins realize their full storage potential. This raises important questions: • How can capacity be fully utilized? • How should storage boundaries be defined in open and/or interacting projects? • How should adjacent projects be developed, including accommodating hydrocarbon production and natural gas storage? The workflow: 1) Gain steering advice and views from stakeholders. 2) Use outputs from recent research to examine interactions between multiple storage

operations, through two scenarios: a) Scenario 1: Market-driven development; Operators select their preferred sites,

based on techno-economic considerations. Early entrants will choose the most economic sites with least risk that are currently available (most likely to be depleted hydrocarbon fields).

b) Scenario 2: Managed pore space; Strategic basin management would allow optimization of the storage resource through phased release of sites.

3) Credible case studies, based in the North Sea (UK), will investigate optimum route(s) to maximizing storage potential, illustrating the benefits and issues to be considered. We expect the results will have much wider application internationally and will allow comparisons with approaches undertaken in other areas, such as Australia and Gulf of Mexico.

A workshop will be held to gain inputs from international contexts, on the 20-21June at BGS Nottingham. Outputs This research will provide evidence to policy makers to demonstrate whether pore space should be managed strategically. The results will be used as a basis for discussions with stakeholders to inform future policy on pore space management and spatial planning. Pore space management would include consideration of: identifying the prioritization of sites to be leased, appropriate injection rates and total storage achieved per site and per province. Contractor British Geological Survey, UK

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Study b. Assessment of the Potential Barriers to the Deployment of the CCS in the Cement Industry Purpose: The 2012 Energy Technology Perspectives by the IEA (IEA ETP) indicates that CCS from industrial applications could contribute 3.8 Gt of CO2 abatement by 2050. This makes it the second largest sector, after fuel efficiency for vehicles. CCS in power generation is estimated to provide abatement of 3.3 Gt CO2 by 2050. The cement industry is currently the 2nd largest source of CO2 emissions among the energy intensive industry. To achieve the 2050 target recommended by IEA ETP, it was recommended that the cement sector is to enable 11 projects capturing 13 million tonnes per year by 2020. Currently, there are no large scale projects identified in the cement sector so significant work is required to enable the sector to contribute to the abatement targets through CCS. The study will focus on the following areas:

(1.) To review current energy efficiency practice in the cement industry. (2.) To review and analyse for the dynamics of the fuel and clinker substitution practices

in relation to the deployment of CCS in reducing CO2 emissions in the cement sectors.

(3.) To review the current state of development of all potential CCS technology evaluated for the cement industry. Particularly, this study will focus on Post-Combustion, Oxyfuel Combustion and Chemical Looping Technology.

(4.) To engage with key stakeholders with an aim to identify the key barriers to the demonstration of CCS in the cement sector.

(5.) A review of the CCS activities in the cement sector by providing a listing of activities at research, pilot and demonstration scale in the sector;

(6.) A review of policy and government initiatives to support the application of CCS to the cement sector;

Note: Emphasis in this study will be given to Task 4. Deliverables: A targeted report will be produced as a knowledge product covering the above areas and outlining the key barriers to the demonstration of the CCS in the cement sector. Contractor European Cement Research Academy (ECRA), Germany

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Study c. Assessing the current status of CO2 pipeline infrastructure Purpose: There are some 3000km of existing CO2 pipelines in the USA that have been operating since the mid 1980’s. Newer pipelines include:350km pipeline from the Dakota gasification plant in North Dakota to Weyburn in Canada, the 160km undersea pipeline which is part of the Snohvit injection project in the Barents sea. For all these pipelines the specification of the CO2 purity has been approved, the construction materials have been scheduled, operational/control systems have been approved by regulators as have dispersion modeling studies and site routing/incident areas agreed. In the case of the pipelines in the USA, the USDOT has control. CO2 pipelines are therefore well established but there has not been an activity to collate the various data on these pipelines that is available freely in the public domain. The purpose of this study is to collate information on the current status of operational CO2 pipelines. This data will cover the following areas: i. Develop a list of existing CO2 pipelines globally and collate data on their geographical

siting, their distances and the composition of CO2 including impurities they carry and how long they have been operational.

ii. Review the existing CO2 pipeline regulations that are in place for CO2 pipelines, who the regulatory bodies are etc.,

iii. Review information on public concerns over CO2 pipeline safety and experiences and approaches by pipeline developers;

iv. Review the USDOT records of CO2 pipeline operations, noting data like hours of operation, number of recorded incidents reasons for incidents, collateral damage incurred and any injuries/deaths.

v. Review the materials of composition of the existing pipelines, CO2 purity requirements, corrosion measures, distances between block valves, control systems, control procedures for handling flow outages, planned and unplanned etc.,

vi. Review the safety provisions required under existing regulations, dispersion modelling studies etc., incident zones, management requirements for leaks/breakages etc.,

vii. The review should also include compressor requirements listed compressors used, operational experience etc.,

viii. The review should also look at available FEED studies, such as Longannet, Kingsnorth etc., and assess the pipelines design/operational parameters from these proposed projects and if they differ from existing operations and if so why.

Deliverables: This targeted report will produce a knowledge product that covers the topics above, a database of the information gathered, and a webinar. Contractor Ecofys, the Netherlands

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INTERACTION WITH WPFF, IEA AND OTHER IA’S

Interactions with WPFF, IEA and IEA IA’s IEAGHG were invited to present an overview of our current study activities to the 43rd Working Party on Fossil Fuels (WPFF) held in Paris in December 2013. John Gale presented an overview of IEAGHG’s current, planned and future study work which was well received by the WPFF Members. The next Working party meeting will be held in June 2014, In Warsaw, Poland. If IEAGHG is not invited to present we will provide the WPFF with a summary of our activities to circulate to members. IEAGHG has interacted extensively with the IEA CCS unit over the period; some of these interactions have been discussed under Facilitating Information. We h old regular ad hoc meetings/telecom’s with members of the IEA CCS unit. John Gale is a member of the advisory committee on the revised CCS road map and chaired a session at the Stakeholders meeting on 25 F ebruary. IEAGHG has also supported the CCS Roadmap activity by providing a venue for a discussion panel at GHGT-11, providing text and by reviewing drafts of the document. We have been interacting with the EOR IA who will act as reviewers for the new EOR related studies we have underway. We have also begun discussion with the IEA IETS IA a group that report to the End Use Working Party. IETS stands for Industrial Energy-related Technologies and Systems (IETS). IETS is a task shared IA with 10 country members.. The program was established in 2005 as a result of a merger of two former IAs on Pulp & Paper and Process Integration. The new program is still under development, with several new activities starting up. Its work is set up as separate Annexes. Through its activities, the program aims to increase awareness of technology and energy efficiency in industry, contribute to synergies between different systems and technologies, and enhance international cooperation related to sustainable development. Projects underway include:

• Energy Efficient Separations Systems: Methodological Aspects, Demonstration and Economics (Annex IX)

• Energy efficient drying and dewatering technologies (Annex X) • Industry-based Biorefineries (Annex XI) • Energy Efficient Separations Systems: Methodological Aspects, Demonstration and Economics

(Annex IX) • Energy efficient drying and dewatering technologies (Annex X) • Membranes as energy-efficient technologies for Separation of Hydrocarbons (Annex XII) • Industrial Heat Pumps (Annex XIII). • Process integration in the iron and steel industry (Annex XIV) • Industrial Excess heat Recovery (Annex XV)

Clearly Annex XIV is directly relevant to our recent study on integrating CCS into the Iron and steel sector. Hence Stanley Santos attended a meeting the group organised on s ystem integration and their ExCo in March 2013. The IETS IA has an interest in CCS and discussions on pos sible future collaboration have now been initiated will continue. Gunter Siddiqi attended the IEA Workshop on the aims of the Unconventional Fuels Working Group. He will report verbally at the ExCo meeting.

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DATE OF NEXT MEETING

The next scheduled meeting will be the 44th ExCo and will be hosted by Sweden, 2nd – 3rd October 2013 in Stockholm. The 45th ExCo will be held in Vienna, Austria, hosted by OPEC on the 29th-30th April 2014 with the 46th ExCo being held in Texas, USA prior to GHGT-12.

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