VIENNA, AUSTRIA - IEAGHG ExCo Papers_email.pdf · Vienna, Austria 29 thto 30 April 2014 ITEM FIRST DAY (08.30 – 17.30hrs) Paper Number 0) Opening Address by Host No Paper 1) Welcome,

45th ExCo MEETING, 29th - 30th APRIL 2014, VIENNA, AUSTRIA

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 44th meeting………………………………………………………………………………………………… Corrections to minutes……………………………………………………………………………………………………

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Matters arising from the 44th meeting ‐ list of actions and status …………………………………. 19 CCS &GHG Mitigation – Key Issues ....……………………………………………………………………………. 20 Membership Issues/New Members………………………………………………………………………………. 21 Members Accounts 2013/14………………………………………………………………………………………….. 22 Budget Proposal for 2014/15…………………………….…………………………………………………………… 23 Operating Agent Report/discussion………………………………………………………………………………. 24 Completed/On‐going Activities Report…………………………………………………………………………. 25

CO2 Pipeline Study (GCCSI)..…….…...……………………………………..………………………………. 34 Barriers to CCS in Cement Industry (GCCSI).………………………………………………………….. 47 Comparing Approaches to Managing Storage Resources………..…………………………….. 59 Assessment of Costs of Baseline Coal Power Plants………………………………………………… 70 CO2 Storage Efficiency in Aquifers……………………..…..……………………………………………… 84 Post Combustion Flow Sheet Modification……….……………………………………………………. 92 Geomechanical Fault Stability…………………………………………..……………………………………. 110 Feedback from Social Research Network and Summer School….…………………..……… 118 Update on GHGT………………………………………..………………………………………………..………… 122

Study Prioritisation………………………………………………………………………………………………………… 124 Criteria for Depleted Oil and Gas Fields to be Considered for CO2 Storage............... 126 Fault Permeability………………………………………………………………...……….………………………. 128 Regional Variation of Capture Costs………….……...…………………………………………………… 130

Studies to be reconsidered for future voting rounds/Members Ideas for Future Studies.. 132 Discussion Papers

ISO Status……………………..………………………………………………………………………………………… 133 ECO2 Press Issues………..…………………………………………………………………………………………. 134

Feedback on IEA CCS Unit/IEA Activities…..…………………………………………………………………….. 138 Interactions with WPFF and other IEA’s…………………………………………………………………………. 139 Feedback on Steel Industry Seminar………………………………………………………………………………. 142 Interactions with CSLF…………………………………………………………………………………………………….. 143 Feedback on Members Activities…………………………………………………………………………………..

Austria – Industry Seminar Feedback…………………………………………………………………….. 146

Date of Next Meeting……………………………………………………………………………………………………… 147 Any other business………………………………………………………………………………………………………… 149

GHG/14/01

IEA GREENHOUSE GAS R&D PROGRAMME 45th 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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Vienna, Austria 29th to 30th April 2014

ITEM FIRST DAY (08.30 – 17.30hrs) Paper Number

0) Opening Address by Host No Paper 1) Welcome, safety briefing, introduction of new members and

observers No paper

2) Motion on procedure at the meeting GHG/14/01 3) Adoption of agenda GHG/14/02 4) Minutes of 43rd meeting GHG/14/03 5) Corrections to minutes GHG/14/04 6) Matters arising from the 43rd meeting - list of actions and status GHG/14/05 7) CCS & GHG mitigation - Key Issues since last meeting No Paper 8) Membership Issues/New Members GHG/14/06 9) Projected out turn 2013/14 GHG/14/07 10) Budget proposal for 2014/15 GHG/14/08 11) Operating Agent Report/discussion No Paper 12) Completed /On-Going Activities Report GHG/14/09 12.1) CO2 Pipeline study (GCCSI) GHG/14/10 12.2) Barriers to CCS in cement Industry (GCCSI) GHG/14/11 12.3) Comparing approaches to managing storage resources GHG/14/12 12.4) Assessment of costs of baseline coal power plants GHG/14/13 12.5) CO2 storage efficiency in aquifers GHG/14/14 12.6) Post combustion flow sheet modification GHG/14/15 12.7) Geomechanical fault stability GHG/14/16 11.11) Feedback - Social Research network/summer school GHG/14/17 11.12) Update on GHGT-12 GHG/14/18 ITEM Second DAY (08.30 to 17.00) Paper 12) Study Prioritisation GHG/14/19 12.1) Criteria for Depleted Oil and Gas Fields to be Considered for

CO2 Storage GHG/14/20

12.2) Fault Permeability GHG/14/21 12.3) Regional Variation of Capture Costs GHG/14/22 13) Studies to be reconsidered for future voting No Paper

14) Discussion papers 14.1) ISO status GHG/14/23 14.2) ECO2 press issues GHG/14/24 15) Feedback on IEA CCS unit/IEA activities No Paper 16) 16.1)

Interactions with WPFF and other IA’s Feedback on Steel Industry seminar

GHG/14/25 No Paper

17) Interactions with CSLF GHG/14/26 17)

Feedback on Members Activities Austria – Industry seminar feedback

No Papers

18) DONM Presentation on 46th meeting at GHGT-12

GHG/14/27

19) AOB 20) Close of Meeting

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GHG/14/03


Stockholm, Sweden, 2nd – 3rd October 2013

LIST OF ATTENDEES

Members Dr Lincoln Paterson CSIRO Australia Prof Kelly Thambimuthu (Chair) CO2CRC Australia Dr Eddy Chui Natural Resources Canada Canada Mr Peter Petrov EU Mr Eemeli Tsupari VTT Finland Dr Nathalie Thybaud ADEME France Mr Jürgen-Friedrich Hake FZJ Germany Mr Ryozo Tanaka RITE Japan Mr Daan Jansen ECN The Netherlands Mrs Åse Slagtern The Research Council of Norway Norway Dr Taher Najah OPEC Dr Jang Kyung-Ryong KEPRI South Korea Mr Pedro Otero Ventin CIUDEN Spain Mr Sven-Olov Ericson (Vice Chair) Ministry of Sustainable Development Sweden Mrs Coralie Chasset Swedish Energy Agency Sweden Mr Gunter Siddiqi (Vice Chair) Swiss Federal Office of Energy Switzerland Dr Suk Yee Lam DECC UK Dr Jay Braitsch US DOE USA Dr Markus Wolf ALSTOM Mr David Jones BG Group Mrs Gina Downes CIAB Dr Sven Unterberger EnBW Kraftweke AG Mr Richard Rhudy EPRI Dr Stephen Lyons ExxonMobil Dr Jose Miguel Gonzales-Santalo IIE Mr Bill Spence Shell Dr Helle Brit Mostad Statoil Mr Dominique Copin Total Mrs Åse Myringer Vattenfall

IEA EPL Dr John Topper IEAEPL 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 Dr Jasmin Kemper IEAGHG Team Dr Prachi Singh IEAGHG Team Mr James Craig IEAGHG Team

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Observers Mr Sean McCoy IEA Mrs Karin Comstedt Webb Heidelberg Cement Northern Europe Miss Jennica Broman Swedish Energy Agency Dr Svante Söderholm Swedish Energy Agency Mr Jan-Olov Wikström Swerea MEFOS Dr Cheol Huh KIST Dr Don Lawton CMC Research Institutes Inc. Canada Mr Richard Adamson

Linda Wickstrom Jan Bida Kim Karsrud

CMC Research Institutes Inc. Geological Survey of Sweden MinFO SSAB AB

Canada

Apologies Mr Dwight Peters Schlumberger UK Dr Ziqui Xue RITE Japan Dr Reinhold Elsen RWE Dr Tony Surridge SACCS South Africa Mr Brendan Beck

Mr Arthur Lee SACCS Chevron

South Africa

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Stockholm, Sweden, 2nd – 3rd October 2013 1. WELCOME AND INTRODUCTIONS Kelly Thambimuthu (Chair) began the 44th Executive Committee (ExCo) meeting by welcoming all to the meeting, and thanking the Swedish hosts (Swedish Energy Agency) for the seminar and reception held on the 1st October. Kelly then proceeded to welcome some Members here for the first time – Dr Stephen Lyons (ExxonMobil), Andrew Purvis (GCCSI) and Åse Myringer (Vattenfall), before welcoming new observers to this meeting – several of whom were from Sweden and one from South Korea, Dr Sanjing Moon of, KETEP. Kelly then welcomed James Craig, a new employee at the IEA Greenhouse Gas R&D Programme, who is working on the geological storage. 2. MOTION ON PROCEDURE The motion for procedure at the meeting (document GHG/13/32) was adopted. 3. ELECTION OF CHAIR Paper GHG/13/33 refers and John Topper (IEA EPL) notified all that there was only one nomination for Chair – Kelly Thambimuthu (Australia). There were no other proposals at the meeting for alternative Chairs. Canada (represented by Eddy Chui) proposed the motion to re-elect Kelly, Switzerland (represented by Gunter Siddiqi, Co-Chair) seconded this motion. There were no further comments and Kelly Thambimuthu accepted chairing for another 2 year term. 4. ADOPTION OF AGENDA Paper GHG/13/34 refers. There were no significant changes to the agenda and Members agreed to adopt the agenda. 5. MINUTES OF 43rd MEETING & CORRECTIONS TO MINUTES Paper GHG/13/35 and GHG/13/36 refers. John Gale (IEAGHG) noted that the minutes in the ExCo pack are not the final minutes (due to printing schedule etc.). There is a slight change that needs to be made, but largely there were few changes requested by members. John will send the FINAL minutes to all Members soon and on this basis Members accepted the minutes from the last meeting.

ACTION 1: General Manager 6. MATTERS ARISING FROM THE 43rd MEETING – LIST OF ACTIONS & STATUS Paper GHG/13/37 refers and John Gale noted the majority of actions have been addressed and some will be discussed in papers at this ExCo meeting. Action number 9 (the benchmarking of the monitoring tool) is underway and the Programme have had offers from many projects to undertake this benchmarking. Members were informed that items 16 and 17 were merged to form one action, number 16 (Summer School), which is well underway in that TNO’s offer of hosting the 2015 School has been kindly declined and the second part of the action (on host criteria) will be addressed in the Summer School 2013 feedback talk, to follow later on in this meeting. The action on hubs and clusters (action 20) is underway. Action 25 (a study on fuels cells for power generation with CCS) will be completed within the next year as a technical review (TR). Action number 27 deals with the combination of two water studies and the eventual outcome will be one technical paper, which will be discussed later in this ExCo meeting. Action 28 is well underway, with John Davison (IEAGHG) looking into this topic of hybrid capture technologies. The review on non-CO2 gases (action 12) will be completed soon by John Gale.

ACTION 2: General Manager

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7. PROGRESS CCS & GHG MITIGATION STATUS REPORT Paper GHG/13/38 refers and John Gale (IEAGHG) presented this to Members. Ryozo Tanaka (Japan) asked about John Gale’s new role in the OCC and PCCC series’ and John confirmed that John Topper has to date overseen the running of these conferences but, due to John Topper’s moving into semi-retirement and resulting reduction in responsibilities with IEAGHG, John Gale will be taking over this ‘overseeing’ role for these two conferences. With regard to IP04-2013 Jay Braitsch (USA) noted that many newer Chinese coal plants have FGD fitted but are not turning it on, and questioned whether this was true. John Topper (IEA EPL) commented that it appears all plants in this region are fitted with FGD and it appears to be generally being used due to the severe penalties otherwise, but noted that some companies are turning it off from time to time. John believes that the use is fairly substantial but that this is not guaranteed. Sven-Olov Ericson (Sweden, Vice-Chair) noted that with regards to sulphur, it is important to look at the cooling/reflecting effect and to not forget effects such as acid rain, which can be very dangerous in the medium term in vulnerable environments (e.g. in Europe) but that some such environments do have a self-healing effect. The Programme should be careful when talking about this effect, particularly when it may be short-term. Kelly Thambimuthu (Chair) agreed, noting that it shouldn’t be seen as an easy fix and should be taken with caution. Kelly noted that Sven’s comments bring this into perspective and this is certainly an area to watch. Richard Rhudy (EPRI) thought that these sulphates are very high in the atmosphere and there are uncertainties on the half-lives of these so we’re not sure exactly what effects acid rain. Helle Brit Mostad (Statoil) noted that the Programme’s information papers (IPs) are very popular at Statoil but noted that in IP22-2013 (water issues) it states that there is no water usage with PV production when there should be quite a lot. John Gale remarked that this was looked at but that many resources noted that intuitively, wind/PV come up quite low. However John urged Statoil to please forward any relevant information on to him, as there was limited data on this. Sven-Olov Ericson (Sweden) thought that this IP gives a good picture but if the figures were revisited it would be wise to distinguish between use, consumption and waste water – Kelly Thambimuthu agreed this is very relevant. John remarked that if there was sufficient desire more could be done on this area. Kelly Thambimuthu agreed that thought should be given to bringing this back to Members and Gina Downes (CIAB) agreed that this is a big issue in South Africa and so worth pursuing, noting that it is timely to take this further as there are current studies on this in South Africa and by the European Commission.

ACTION 3: General Manager John Gale noted that IEAGHG will be keeping an eye on CCS breakthrough technology (IP19-2013) and one new idea called Electrochemically Mediated Amine Regeneration (EMAR) seems more interesting/promising than originally thought and we will continue to track this concept. Jay Braitsch (USA) remarked that one area that should be looked at is plants with intermittent technology and how not to cycle. John commented that this was being looked at in a new study that will be published next year. In terms of policy developments re IP7-2013 Peter Petrov (EU) noted that he shared the opinion of the PhD paper from FZJ (Germany), that IEAGHG is the lead in technical information, but this paper should not describe ZEP as policy prescriptive. On demonstration projects, Helle Brit Mostad (Statoil) remarked that it was a government decision to stop the Mongstad project, where experience has shown that CCS is an important area which requires more research – Statoil intend to keep looking at CCS. Åse Slagtern (Norway) noted that the government have agreed to stop Mongstad as the full scale project was too high risk and costly, but that Norway will be continuing with their CCS strategy, with a goal to have another full scale plant by 2020. An increased budget to the CLIMIT R&D&D program and Technology Centre Mongstad (TCM) is proposed for the national budget.

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Gunter Siddiqi (Switzerland) remarked that a CCS roadmap has recently been completed and the government feel that much more R&D is needed. In terms of capacity development, there will be a future announcement on a new Swiss initiative on a Competence Center for Energy Research with a focus on CO2 Storage. Gunter noted that the location study has been completed and it seems as if the area between the Zurich and Alpine regions will be likely for the injection, but this is to be confirmed. There are 26 cantons in the country, each with different policies/regulations that require thought and consideration. When discussing the IPCC, Kelly Thambimuthu (Chair) remarked that the outcome of 5-yearly reports from the Panel is too long, especially as they’re showing that science is constantly improving. Kelly believes that the IPCC will discuss the option of putting out reports more frequently will happen at their next plenary. Jürgen-Friedrich Hake (Germany) doubted that releasing a report more often would speed up the science. Another issue is that many do not have the time or capacity to read and truly understand these reports, which has led to the media picking out only what they understand – causing misquoting, and scientists don’t know how to overcome this problem of misquoting. There was some more discussion at this ExCo meeting on the issue of the media and climate change. Helle Brit Mostad (Statoil) remarked that the temperature rise and recent slowing down of this is an issue in the media, and a recent MIT paper showed that other greenhouse gases could play a key role in influencing El Nino/El Nina streams – as this perhaps has slowed down the temperature rise. Helle asked if this would be outside the Programmes scope. John Gale remarked that N2O is within the remit, and all agreed that there should be an information paper produced on this. John would like to look at the IPCC report further (he has been invited to peer review WG3) and consider if there are any ways the Programme can relate to adaption measures/policies that are coming out in the area of mitigation.

ACTION 4: General Manager 8. MEMBERSHIP ISSUES/NEW MEMBERS Paper GHG/13/39 refers. Daan Jansen (The Netherlands) commented on the withdrawal of The Netherlands from the Programme, of which the termination date will be the 31st May 2014. He has discussed the issue with the Ministry of Affairs and it seems unlikely they will reconsider their withdrawal. John Gale noted there has been some indecision within the Ministry in Germany, but there has now been a decision made that they will not fund membership for Forschungszentrum Jülich GmbH (FZJ) to go forward as a contracting party. FZJ have now entered a withdrawal on behalf of Germany, but would like to remain a sponsor (FZJ). Members supported the move to waive the withdrawal (taken from the date that Germany entered notice), to keep the contracting party for the next 6 months, and accept FZJ as a sponsor thereafter. Jürgen-Friedrich Hake (Germany) remarked that this is the best outcome of the situation and he expects no change. FZJ have arranged the budget for this final phase, so can pay the invoice for sponsorship until the end of the period. Kelly concluded that all Members were in agreement to waive the notice period for Germany to 6 months and John Gale is to formally invite FZJ as a sponsor. This action to change a contracting Party to a Sponsor was considered to be an exceptional one and not one the Chairman considered as a standard procedure to be followed by other members. The Executive Committee unanimously resolved to invite Forschungszentrum Jülich GmbH to join the Implementing Agreement for a Co-operative Programme on Technology Relating to Greenhouse Gases Derived from Fossil Fuel Use as a Sponsor. The Executive Committee authorised the General Manager to expedite the formal procedures for FZJ’s membership as a Sponsor and complete negotiations on the terms and conditions on behalf of the Executive Committee.

ACTION 5: General Manager 9. MEMBERS’ ACCOUNTS 2012/13 Paper GHG/13/40 refers and John Gale provided this update to Members. John informed members that the member’s accounts have been approved by the EPL Board subject to some very minor edits

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and will be sent to Members shortly. Peter Petrov (EU) remarked that for him to approve/comment on the provisional Members’ accounts, he must be able to consult with his financial and legal departments first. He understood the cautious approach due to the next year’s potential difficulties, but emphasised that the financial information needs to be sent more promptly. John Gale noted that this is an issue that could be taken back to the accountants, but the process with the accountants usually takes about 3 months after the accounts are submitted at the end of the financial year. Peter commented that this delay is not ideal. John noted that the draft accounts would be available in time for the autumn ExCo, and it was agreed that the ExCo will be able to have access to the draft accounts and can then approve the final accounts online at a later date now that the Implementing Agreement had been changed to allow online voting. This process will be introduced for all following years.

ACTION 6: General Manager John indicated that the 2012-2013 Member’s accounts indicted a substantial surplus of income over expenditure (£270k). He proposed a number of options to utilise the surplus to members to assist the Programme next year when the budgetary conditions will be tighter because of Netherlands and Germany leaving as contracting Parties. Gina Downes (South Africa) noted that there were 10 studies awaiting start and asked what the constraints were on these – John responded that he expects these studies to be picked up quickly, noting that this doesn’t affect the Programme’s budget. Peter Petrov (EU) suggested that the EU would be uncomfortable with using some of the Programme’s surplus on travel to GHGT-12, suggesting that it should be put back into the technical programme. John Gale indicated he was happy to consider Peter’s request if other Members agree feel this is an issue. No further comments were raised. Gunter Siddiqi (Switzerland) concluded that the draft accounts will be available at the 2nd ExCo meeting of every year, with electronic voting a few weeks later on the final accounts. All Members agreed to the proposed use of the surplus. 10. PROPOSED CHANGES TO IA AND ANNEX 1 CHANGES Paper GHG/13/41 refers and John Gale presented this to Members, noting that he has received no comments from Members thus far. Richard Rhudy (EPRI) asked about voting and John Gale remarked that voting would be open to all Members – countries and sponsors. Suk Yee Lam (UK) commented that DECC needs to be referred to differently and in Part 4, intellectual property, there is a reference to the UK – Suk Yee will provide IEAGHG with the text. Sean McCoy (IEA) noted that there seems to be activity in the Programme on biomass, but the scope here only references fossil fuels – perhaps others should be mentioned. Sean also suggested being very clear in Annex 1 what this Implementing Agreement (IA) wants to be involved with (i.e. future interactions with other IA’s). John Gale agreed, noting that there will be a review of the strategic plan mid-term (2014) which will take into account these suggestions.

ACTION 7: General Manager Peter Petrov (EU) noted that Annex 1 is now more in tune with the Programme, but noted that to accept these changes he would like to go back to the EC with a consolidated agreement to finalise. Gunter Siddiqi proposed that ExCo accept the proposed changes. Peter can take this consolidated version to the EU for approval, and only in the case of significant change (requested by the EU) would the paper be brought back to the ExCo. All Members agreed this did fulfil the requirements set down at the previous ExCo. Subsequent to the ExCo meeting, Members voted unanimously by email to change the name of the Implementing Agreement from: Implementing Agreement For A Co-Operative Programme On Technologies Relating To Greenhouse Gases Derived From Fossil Fuel Use, to the shorter name of Greenhouse Gas R&D Programme Implementing Agreement.

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11. DISCUSSION PAPERS 11.1 COP19 DEVELOPMENTS Paper GHG/13/42 refers and Tim Dixon provided this update to Members. There were no comments. 11.2 ISO PROGRESS Tim Dixon gave this talk and apologised for the lack of a paper, due to the timings of the previous ISO meeting and this Executive Committee meeting. Sean McCoy (IEA) briefly added that he is the IEA’s representative on the ISO technical committee, and emphasised the great need to have technical expertise from industry involved. It is important to ensure only the right things are standardised (there is some grounding that will be needed from industry) and Sean appealed for those ExCo Members with such expertise who could be useful to this ISO working group. 12 COMPLETED/ON-GOING ACTIVITIES 12.1 TEST INJECTION STUDY Paper GHG/13/43 refers and James Craig presented this to Members. Jay Braitsch (USA) remarked it seems as if it’s hard to figure out what we’ve learnt that we didn’t know already, and wondered whether this study went into more detail, looking at individual lessons learned. James noted that to an extent it does, although it only considers techniques in general, there is a summary of each project, showing that projects don’t necessarily take the same approach. Of benefit is the knowledge that if you applied a technique at one project, whether it would make sense to use elsewhere. Jay agreed that this type of review is useful and John Gale added that the idea for this study came from a request from the South Africa CCS Centre to help someone coming new to a test injection site could learn from what has been done. As they are research projects, it’s difficult to ascertain if there is necessarily a methodological approach to monitoring strategies – different parties will be eager to use different techniques, which may not be the best. The guideline that has come out will be tested soon by South Africa, so there will soon be an indication of the value of this. Kelly Thambimuthu (Chair) added that in his experiences there have been no such guidelines, and so the value added was clear. James remarked that there is a lot of information for people to consider as they go through their approach, the report can help guide them to redefine their objectives and this is more for early-stage projects. Peter Petrov (EU) commented that the summaries and recommendations presented reflect the scope well – it’s a summary of the best available knowledge. It seems to be more of a holistic approach and will probably not be a best practice manual for a full-scale project, but it would be useful to a pilot or country considering a smaller scale endeavour. Peter suggested a summary of the report should be available on the IEAGHG website, in an easily accessible format. Dominique Copin (Total) remarked this is an interesting study that Total would like to be looked further into – there are 45 projects worldwide and some of these have real results, technical conclusions and many answers that could provide valuable learning’s. John Gale agreed, but noted that the What Have We Learnt 2 proposal later on would address this. John Gale believes that this report will have no policy perspective aspects to it and is based on publicly available data and therefore asked Members for permission to make this paper publicly available shortly to all on the website (rather than waiting the usual 6 months for general release). All Members agreed this proposal. 12.2 EVALUATION OF RECLAIMER WASTE DISPOSAL Paper GHG/13/44 refers and Prachi Singh presented this to all. Richard Rhudy (EPRI) remarked that his concern centred on substances building up (e.g. selenium) which then needs to be purged somehow – it should be considered that these technologies cannot be used to purge this at a coal plant. Another issue is co-firing – can this be done with significant amounts of such substance build-up, which should be addressed in the report. Prachi noted that this is a concern and that metals can be removed in the particulate process, but this report doesn’t look at this in much detail. Prachi confirmed it will be at least mentioned in the final report. Jürgen-Friedrich Hake (Germany) added about the difference between EU and US legislations and Prachi acknowledged this difference, giving an example of amines – some are not listed in the landfill acceptability lists, so in the US they may think that it’s ok for landfill. Prachi assured all that the report looks at regulations in detail.

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12.3 BIOMASS CCS GUIDANCE ON ACCOUNTING FOR NEGATIVE EMISSIONS Paper GHG/13/45 refers. Jasmin Kemper provided this talk. Kelly Thambimuthu remarked that the IPCC emission guidelines aren’t clear on CCS and wondered if they had addressed it. Jasmin thought they covered most technologies and commented that it’s more of an issue that there are different schemes worldwide, so perhaps a global scheme is needed. Sven-Olov Ericson (Sweden) noted this is a very good report, although perhaps oversimplified as to what’s actually being discussed worldwide and questioned why the report shouldn’t address indirect land use change. Sven-Olov would like to separate the treatment of CCS in a stack to the lifecycle of emissions upstream – we recognise CCS on a fossil fuel plant even if the coal mine releases methane; we see the emissions captured despite this. The lifecycle evaluations here are valuable but they mustn’t be confused with the normal CCS treatment of a co-fired power plant. Kelly agreed, noting that a lot of this may be in the policy remit – it is clearly important to progress on this. Sean McCoy noted that the IEA CCS unit are currently looking into bio-CCS and regulations. Markus Wolf (Alstom) thought that it is an excellent piece of work on a complex subject, agreeing that although there are challenges it is a good start for work to come. Eemeli Tsupari (Finland) remarked that the EC are preparing criteria for biomass combustion and it may be useful to see how these criteria are taken into account in industry. Jasmin will need to check if this is included in the study, commenting that it does note that in the EU there are current discussions on how to define the criteria – but there is no summary on this as it is on-going. Jasmin welcomed any input on this though, which could be passed onto the contractor. Coralie Chasset (Sweden) pointed out that in this report it is referred to as bio-CCS, whereas in others it is BECCS, and noted it is important to know which term should be used and when. Jasmin agreed, concluding that BECCS is used if the biomass CCS is applied to the energy sector, whereas bio-CCS is used when including biofuels and industrial applications. 12.4 REVIEW OF CO2 STORAGE IN LOW PERMEABILITY STRATA Paper GHG/13/46 refers; James Craig presented this to Members. Jay Braitsch (USA) asked if, assuming the reservoir formation is thick, you can induce permeability by fracking. James answered yes, to an extent – but it will depend on the lithology, the stress field in it etc., all of which would need investigation and quantification. The full report on this will be out soon, and James noted it seems that there is a need for further research or experience on this. 12.5 FEEDBACK FROM 7TH INTERNATIONAL SUMMER SCHOOL Paper GHG/13/47 refers and Samantha Neades gave this presentation. There were no comments or questions, so IEAGHG takes this as acceptance of the proposed host criteria presented to all. 12.6 FEEDBACK FROM GEOLOGICAL STORAGE NETWORKS James Craig (concentrating on modelling and risk assessment, paper GHG/13/48 refers) and Tim Dixon (looking at environmental impacts and monitoring provided this feedback to Members. Lincoln Paterson (Australia) commented on the language used in modelling/risk assessment report namely when something behaves differently than expected. In his experience, there are always a range of predictions modelled as to CO2 behaviour and now a number of predictions are used so long as they’re within the specified ranges. James agreed, noting that there were presentations on different modelling methods and their accuracy. John Gale added to this discussion by noting that when the initial idea came about for merging the storage networks, it wasn’t appreciated how beneficial the combined meetings would be. This is a great example as to how the networks have grown together – we now bring groups together to collaborate and share data in an effective way. Now it’s not only discussion, it’s the sharing of results as well, and John felt that the modelling and risk assessment networks especially work well together. Bill Spence (Shell) agreed, and noted the phrase that has come out of the environmental impacts and monitoring meeting – ‘consequences that matter’ – is a well-liked statement; sometimes we forget to

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put a scale of importance on this and we need to be careful to determine what actually matters. Tim agreed, remarking that the discussion reflects Bill’s thoughts, for example migration out of the reservoir is only important if it matters. 12.7 FEEDBACK FROM HIGH TEMPERATURE SOLID LOOPING NETWORK There was no paper for this item. Jasmin Kemper presented this, with Kelly Thambimuthu (Chair) noting that the presentation given by Chalmers in the CCS seminar (day before this ExCo meeting) stated that the solid fuel combustion system seems to be using a bubbling bed reactor instead of a circulating one and results have shown that the bubbling bed is too narrow and forms slugging beds. Jasmin remarked that the network meeting also had presentations on using a bubbling bed as well as a circulating bed and there seems no definitive decision as to which one it will be. John Gale added that traditionally you start with fluidised beds, which have limits on the size they can be scaled up to The standard engineering transition is then to go to a circulating fluidised bed. 12.8 KEY OUTCOMES FROM PCCC2 AND FUTURE PLANS Paper GHG/13/49 refers and Prachi Singh gave this talk to Members. Sven-Olov Ericson (Sweden) asked what is known on nitrosamines contributing a hazard and Prachi explained that this has been discussed at the conference and it seems that by having proper designs (i.e. with an acid wash) you can eliminate the hazard completely. The next conference in the series will be held in 2015, with John Gale, Prachi and Sian Twinning beginning planning in 2014. 12.9 KEY OUTCOMES FROM OCC-3 AND FUTURE PLANS There was no paper for this item and Stanley Santos provided this update. John Topper remarked that he thinks this conference was excellent on all aspects – content, location, attendance and expertise. Pedro Otero (Spain) agreed, remarking that it was an honour to host the event and congratulating the organisation team. He reflected on Stanley’s finishing comments – there are some pessimistic thoughts out there currently. CCS isn’t in a good place, industry are not seeing the market to develop it and this may make it harder to keep the interest alight in the future. Ryozo Tanaka (Japan) saw that the oxy-combustion conference had over 300 delegates and PCCC had 150, and wondered what the reason was for this significant difference. John Topper explained that there is a lot of papers on post combustion capture at the GHGT conferences (i.e. there were 2 parallel sessions on this at GHGT11), so this tends to attract the PCC community whereas the oxyfuel community attend the OCC series. It is a question of emphasis – PCC is very academically orientated, whereas OCC is more industrial – but both work well in their own way. 12.10 CCS PUBLICATIONS AND PATENTS OVERVIEW 2003-2013 Paper GHG/13/50 refers and Prachi Singh provided this overview to Members. Kelly Thambimuthu remarked that it is interesting to see the trends and noticed that there seems to be an inverse relationship between publications and policy in Europe, which could require further investigation. Bill Spence (Shell) asked what the expected lag time was between the research work and when the patent appears and Prachi explained that this overview just used the publication date (so when the patent was available, not submitted) – Stephen Lyons (Exxon Mobil) added that in the US the lag time is about 4-5 years. Sean McCoy (IEA) remarked there are some papers on the lag time between regulation and patenting in the US and noted that for the IEA’s tracking report (energy and technology), the same exercise was undertaken with a chapter on CCS – it came up with a database of 17,000 applications and patents up to 2011/12. Sean is interested in looking into this more with IEAGHG. Jay Braitsch (USA) wondered if there was any correlation between the trends seen here and what our studies should be focussing on (i.e. if the trend is increasing, are people more interested in this, or does little on the particular topic mean there is a knowledge gap)? Kelly agreed that this type of trend is worth giving attention to, drawing all Members back to the road mapping exercises. Prachi would like to add to this overview before it coming to the evaluation stage. Prachi added that the articles

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were found using various search engines, so electronic articles were used as the information source here (all articles have been saved by IEAGHG). Suk Yee Lam (UK) thought this was an interesting undertaking, but it is worth noting that some companies choose not to patent – so the gaps should be looked at too; they may be deliberate to protect commercial partners. Kelly concluded that IEAGHG is to connect with Sean on this and to keep the overview in mind – it would be interesting to look further at this in terms of policy (i.e. what major policy directions there have been, trends in this and any links with this overview data).

ACTION 8: General Manager/IEAGHG 13 STUDY PRIORITISATION Paper GHG/13/51 refers and Tim Dixon went through this summary of voting on prioritisation of new studies. 13.1 VALUE OF FLEXIBILITY IN CCS POWER PLANTS Paper GHG/13/53, Stanley Santos presented this to Members. Kelly Thambimuthu commented on the need for some background, e.g. natural gas plants are usually on standby and there’s a psyche out there that they’re always on standby – this need reflecting upon before flexibility is discussed. It is also important to look at energy storage and environmental storage – and how this fits with flexibility. Stanley agreed and noted that this background will be included at the beginning and the storage comments will be taken back to John Davison. Jay Braitsch (USA) remarked that things here are key to a hot study area in the US right now, but thought that to do a good job this study will be more than average in terms of financial needs; to make the deep dive into understanding the technology interactions is hard, but should result in a great study. Sean McCoy (IEA) noted that he and John Davison published a paper with the same title. The IEA hired a consultancy firm to look at this, and was a very difficult topic to deal with. The key challenge will be the second item in the scope (very difficult), and Sean encouraged thinking of other approaches to deal with this rather than an entire dispatch model for an arbitrary system. Kelly remarked that there certainly must be a baseline, and then other scenarios can be worked up to. Richard Rhudy (EPRI) liked the idea of the study conceptually, but it seems that other groups are spending time on this and we do not want repetition – we need to know what exactly we’re doing that could add to their work. John Gale and Kelly remarked that John Davison really does know this area well and he will have a clear picture of what’s going on worldwide on the topic. Gunter Siddiqi (Switzerland) noted that the IEA have just finished a study on renewables with fascinating but complex results. This study would be very valuable but we do need to look at what’s out there – Simon Muller from the IEA may be able to help. Markus Wolf noted that Alstom highly supports this study, but he sees complexity in a top-down approach and perhaps this study would add more if it used a bottom-up approach with 2 or 3 extreme cases for examples. Richard Adamson (Canada) noted his recent discussions with Alberta Utilities with much investment in gas fired power and wind – they’re moving away from the combined cycle, so away from the carbon benefit which is an important analogue to be learned from. Gina Downes will share some work from CIAB on 21st century coal (published in February 2013), which contains a chapter on the RWE experience which could be used for guidance here. There is also some similar work on coal fired power plants and value added, which could also be useful. Sean McCoy echoed Richard Adamson’s comments, and noted results of an EU modelling study that could be shared. Kelly recognised that all discussion here had been valuable, with generally positive comments as well as a lot of ideas – and a few cautions to direct the report to a niche opportunity. Overall, Kelly concluded that there was generally positive endorsement, so this study will go ahead subject to some initial assessment. 13.2 WHAT HAVE WE LEARNT FROM LARGE-SCALE OPERATIONAL PROJECTS Paper GHG/13/53 refers and Samantha Neades proposed this study to Members. Kelly Thambimuthu commented that public outreach should be included, so the social research network will be involved. Don Lawton (Canada) suggested including closure plans for projects and Dominique Copin (Total) added that when looking at storage performance, it should be more specific and include the gap

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between the expected and found. Samantha will incorporate these comments into the technical specification, and Kelly concluded that this study will go ahead. 13.3 LOW HANGING FRUIT FOR CCS IMPLEMENTATION Paper GHG/13/54 and John Gale gave this proposal. Kelly Thambimuthu remarked that when looking at communication in storage, you need a cheap CO2 supply, like this – there is a lot of opposition in SE Asia on exactly this. Jay Braitsch (USA) will make the NETL report on the cost curve for CO2 available to IEAGHG, which includes low-hanging fruit. Sean McCoy noted that the IEA have looked at this from the policy side and identified challenges, which seem to be the location and lack of drivers. Sean questioned how this study would vary from what was done for the UNIDO case study work. John explained that this looked at barriers, didn’t look from a bottom-up approach and didn’t look at CTL. John suggests doing this in-house first to see where projects have/have not happened, and the reasons why. Dominique Copin (Total) remarked that the discussion shows that low-hanging fruit is not just a question for capture but also for storage. Kelly noted that you’d first begin with pilot storage and work back – which is important for those involved with storage. Bill Spence (Shell) noted that they were able to build a consortium and do have the successful sale of CO2, but have less success with storing it – it doesn’t always match. Kelly concluded that this will start with internal work, and then go external to contractors if the initial in-house work leads anywhere. John will go back to ExCo Members after the internal work before proceeding.

ACTION 9: General Manager 13.4 PRODUCTION OF HYDROGEN WITH CO2CAPTURE Paper GHG/13/55 refers and Stanley Santos gave this talk. Åse Slagtern (Norway) remarked that her research group found other studies more interesting, but Markus Wolf (Alstom) thought that this would be an interesting study, as it interfaces with storage opportunities respect to capture technologies. He asked if this will also look at large/medium/small sized plants, and which would be more beneficial – large plants or locally in small plants. Stanley confirmed that they will review the options available. Coralie Chasset (Sweden) noted that they have the same view as Norway, but respects the views of supporting Members, and Mexico (Jose Miguel Gonzales-Santalo) supports the study. Kelly concluded this would be parked until other proposals have been presented. Eddy Chui (Canada) reiterated the importance of this study and Markus Wolf agreed that this study should be done. After seeing the other proposals, it was agreed that this study would go ahead, providing the budget is sufficient. This study will be deferred if needed but kept on the list for future prioritisation. 13.5 EVALUATION AND INCORPORATION OF FUTURE IMPROVEMENTS IN CO2 POST COMBUSTION CAPTURE TECHNOLOGIES Paper GHG/13/56 refers and Prachi Singh presented this to Members. Richard Rhudy (EPRI) liked the concept but feels it may be almost impossible to do. Some of these processes are so early on, assumptions would need to be made that wouldn’t be accurate. Real cooperation from suppliers is needed, so perhaps they should be evaluated then talked to on which would fit. Prachi agreed, noting that this would be good to include. Sven Unterberger (EnBW) supported Richard’s comment. The review shows the data availability is low; it is early-stage development so proprietary data, which should be considered. Sven also recommended not spending too long on design changes and pre-investment. Åse Slagtern noted that Norway would like to include health, safety and the environment if possible. Gina Downes (CIAB) remarked that there is no existing plant with post combustion and it seems too far in the future to look at how to incorporate 2nd/3rd generation into such plants. If current policies are adhered to, future plants will have to have CCS. Markus Wolf agreed there would be many uncertainties. If this study was to try to judge 2md/3rd generation technologies, it should stay away from costs, which is a huge issue. Richard Rhudy noted that a big issue is how to do costing on low level TR concepts or technologies, and perhaps it is more interesting to look at energy requirements, pros and cons. John Gale agreed, noting that this could be done in phases with the cost network. Kelly Thambimuthu (Chair) concluded that there are clearly warnings about the cost issues and that most interest is the performance parameter in terms of assessment. This may well end up with a smaller initial scope, but that is part of a phased approach. This will be taken forward.

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13.6 REVIEW OF OFFSHORE MONITORING TECHNIQUES Paper GHG/13/57 refers and Tim Dixon proposed this to Members. Helle Brit Mostad noted that there were not many votes from Statoil on this but she supports it. IEAGHG has a role to play, to look at projects and their technical results. They have different ways of expressing their findings and language can differ greatly – as a neutral organisation we can present the results impartially and understandably. Ryozo Tanaka (Japan) also supported the study, and asked for contribution from Japanese research institutes, including RITE, to the UK QICS project to be included in the background information. Tim apologised for missing this work off, it will be included and biological monitoring will also be included. Jose Miguel Gonzales-Santalo also supported this work as it addresses a pressing need. Jay Braitsch thought this could be a very interesting study and Bill Spence (Shell) agreed, noting that many regions worldwide will be utilising offshore storage and IEAGHG will be seen as the honest broker. Dominique Copin agreed, and noted his support for this study, particularly in light of the lack of storage proposals this year. David Jones noted the BG Group’s support for this and Kelly concluded that this study is a definite go ahead and any ideas for contractors or reviewers should be emailed to Tim. 13.7 DESIGN AND COSTS OF FULL SCALE SOLID LOOPING CO2 CAPTURE PLANTS Paper GHG/13/58 refers. Jasmin Kemper provided this talk to all. Kelly Thambimuthu asked if there was a reason why gas is excluded here and Jasmin answered that it can be included if the need for information is there. While developing the scope the inclusion of gas could broaden the study hugely and perhaps not necessarily though. Kelly agreed but thought that from the contamination and loss of oxide view, a gas system would more likely be a ‘goer’ than a coal-based system. Richard Adamson (Canada) agreed with the inclusion of natural gas and thought it would be a valuable study as there are many opinions on this topic. Sven Unterberger (EnBW) fully supported this study, remarking that cost data would be available from desk-based research. He suggested focussing on full-scale data only, on calcium and chemical looping, and to put all new developments in the other study on 2nd/3rd generation technologies. John Gale agreed, noting that John Davison has also come across a NETL study on chemical looping which uses two cases – the IEAGHG study will look to build on these studies rather than replicating the NETL work. He added that gas and retrofit options are worth looking into. Jay Braitsch (USA) remarked that in a study like this a reference plant is needed as a study on chemical looping (etc.) won’t mean much if it’s not comparable. John noted that IEAGHG has baseline coal costs and that John Davison has just completed his gas combined cycle costs work – John Gale thinks we could adapt what we do and build on it. Kelly recognised the overall strong support for this study, noting that including gas is a must. This study will go ahead providing the above comments are taken into account, and with a caveat that the NETL report will be looked at prior to developing and adapting the IEAGHG approach. To conclude the study prioritisation, Kelly Thambimuthu (Chair) noted that all the studies are to go ahead, providing the budget is available. The hydrogen study will be deferred if needed. 14 STUDIES TO BE RECONSIDERED FOR FUTURE VOTING There was no paper for this item and Tim Dixon guided this discussion. Helle Brit Mostad remarked that Statoil would like to see 44-08 (‘Criteria for Depleted Oil and Gas Fields to be Considered for CO2 Storage’) back – they feel it would be site-specific but a valuable study. Gina Downes (CIAB) would like to see 44-10 come back (‘GHG and Water Footprints in the Power sector’), and Lincoln Paterson (Australia) and Eddy Chui (Canada) agreed by supporting both 44-08 and 44-10. Dominique Copin (Total) also supported 44-08, noting that it is important to investigate site criteria early on and to a greater extent, wondering if it was possible to hold a workshop, network or macro study on storage capacities would be useful. John Gale agreed this would be useful; noting that an ideal time to consider such a workshop would be after the storage efficiency report has been published. Tim Dixon agreed, remarking that work recently completed by the IEA CCS unit on methodologies would fit in well with this. Kelly Thambimuthu concluded that both 44-08 and 44-10 will come back for future voting.

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Tim Dixon noted that the bottom two ideas, 44-06 (‘Model Comparison and Development’) and 44-07 (‘Fault Permeability’) were priorities from the Programme’s network meetings and Kelly confirmed that because of this these should go back in for future voting. Jay Braitsch (USA) thought that 44-06 would be hard to carry out successfully. Gunter Siddiqi (Switzerland) supported 44-07 – he is concerned about the strength of faults, particularly when injecting CO2, and suggested looking into the study idea and expanding the scope. It would be interesting to see what happens near active faults. Lincoln Paterson remarked that he was aware of two papers on model comparison and development. Kelly concluded by noting all four ideas (44-08, 44-10, 44-06 and 44-07) will go back into future voting rounds. Tim invited all Members to submit ideas for new studies, noting that IEAGHG will send out a prompting email before the deadline.

15 STATUS REPORT ON GHGT Conferences There was no paper on this report, which Sian Twinning presented to Members. Gunter Siddiqi (Switzerland) noted that the grant (for GHGT-13) from the Swiss Federal Office of Energy is the equivalent to a financial guarantee, and hoped that this satisfies the requirement made at the 43rd ExCo Meeting in terms of such a guarantee. There was unanimous agreement that it did. 16 UPDATE ON GCCSI PROGRAMME Paper GHG/13/59 refers. Tim Dixon gave this update to Members. Please note that the feedback on GCCSI activities talk was given at the beginning of this update, but will be detailed in the Item (17) below. John Gale opened the discussion about IEAGHG joining the soon to be reorganised GCCSI. He pointed out that IEAGHG had been offered to join as a General Member with access to services or join as an Associate Member with no voting rights and no access to services. GCCSI had indicated that they were uncertain whether they would continue as an IEAGHG member. In John’s discussions with their CEO Brad Page a third option: to agree a MoU with the Institute (details to be confirmed) could also be an option. Andrew Purvis (GCCSI) noted that the Institute is currently in a time of transition, and details such as the Institute’s scope will be released soon. Kelly Thambimuthu thanked Andrew for the preliminary information about the Institute. Kelly indicated that he would like to see a precise description of the scope of work that GCCSI will undertake (including products and services offered) and detailed information on the different options sent to Members as some sort of Information paper, to be discussed at the next ExCo Meeting. Bill Spence (Shell) recommended adding information on how IEAGHG and GCCSI complement each other, work together and the differences between the organisations. Peter Petrov (EU) remarked that the EU is a Member of both IEAGHG and GCCSI, noting that there is the potential for overlap of activities – it is imperative that all Members understand these future collaborations, overlaps and differences. Kelly remarked that it would be nice if a regular representative from the Institute could attend the IEAGHG ExCo meetings as it would provide a more efficient way to handle such exchanges. Gunter Siddiqi concluded that John Gale will follow this up with GCCSI, compile the information (as detailed above) and send to Executive Committee Members before discussing at the 45th ExCo Meeting.

ACTION 10: General Manager 17. FEEDBACK ON GCCSI ACTIVITIES There was no paper for this Item and Andrew Purvis (GCCSI) provided this feedback to all. Andrew noted that there are many changes currently on-going within the Institute due to their termination of their funding agreement with the government. The head office is now moving to Melbourne and there will be a shift in expertise to give a wide range of knowledge/expertise across all regions. The model is changing, so the Institute will be transitioning to be a member-funded organisation, likely to result in a change in business. More interaction with members will be needed and Andrew’s role for the short term will be to integrate members. Gunter Siddiqi (Switzerland) asked about the distribution of membership at this current time and Andrew wasn’t sure but anticipated that the majority will be industry, but thought that there will be some attrition whilst moving forward. Jay Braitsch (USA) noted that the budget will obviously be less than before and asked what GCCSI will be continuing. Andrew remarked that the focus and direction will stay the same, and more information regarding future activities, membership types and costs is currently under discussion but will be released soon.

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18. FEEDBACK ON IEA CCS UNIT/IEA ACTIVITIES There was no paper for this item and Sean McCoy (IEA) presented this to Members, noting that the relevant activities included the CCS roadmap, the pathway for the wider development of CCS, producing key messages and 7 key actions that should be completed within the next 7 years. In terms of on-going projects, the IEA have activities underway including a study on the approached to liability management for storage; the assessment of EOR for storage; and collaboration with IEAGHG and GCCSI on the ISO CCS process. Forthcoming publications include the annual CCS legal and regulatory review and a CCS annual. Gunter Siddiqi feels that the collaboration between the IEA CCS unit and the IEAGHG IA is valuable and Ryozo Tanaka (Japan) asked if the IEA will continue to publicise the CCS Annual every year – Sean confirmed that the IEA are currently looking at publications and hope to continue the CCS Annual as a yearly activity. 19. INTERACTIONS WITH WPFF AND OTHER IA’S Paper GHG/13/60 refers and John Gale presented this Item. 19.1. IETS IA AND JOINT ACTIVITIES There was no paper for this item. Jennica Broman (Swedish Energy Agency) gave a brief update on industrial energy-related technologies and systems (IETS). The IETS is an IA, established in 2005 and they have 8 member countries. They aim to ‘foster international cooperation among OECD and non-OECD countries for accelerated research and technological development of IETS’. They have 7 current on-going annexes and Jennica ran through the numerous benefits for members of the IETS IA. There are several new initiatives within the IA for 2013, including a joint workshop on CCS between Annex XI and the IEAGHG. This workshop will be held in May/June 2014 in Portugal. Participants will be charged a nominal registration fee (i.e. 150 – 200 euros), with the IA’s covering any surplus budget. Jennica asked for the Executive Committee Members’ comments on this workshop. John Gale remarked that this is a real collaboration between two IA’s in different working parties, and feels that this is a good synergy on what the IEAGHG Programme could bring to industrial sectors from this. John added that he has emailed Members on the Tokyo meeting but has had no comments. A proposal has been agreed – the Portuguese hosts are to provide a venue and sponsor the dinner, then the registration fees will be contributed to the cost of the meeting, with any shortfall after that being split between the two IA’s (maximum expected 1-2000 Euros). Stanley Santos remarked that this workshop will look at the Iberian market so this region will be the key audience and noted that there should be a good mix of researchers, policymakers and industry. Gunter Siddiqi (Switzerland) remarked that it was good to see this collaboration and felt the workshop was a good opportunity to kick off this cooperation, suggesting that Members should agree on the cost share if there’s a shortfall, and this should be left to the General Managers discretion. 20. FEEDBACK ON MEMBERS’ ACTIVITIES and 20.1, GEOTHERMAL EXPERIENCE IN SWITZERLAND There were no papers for this item. Gunter Siddiqi (Switzerland) looked at a geothermal experience in Switzerland (agenda item 20.1), Dominique Copin (Total) gave an insight into the Lacq project in France, Jay Braitsch (USA) spoke on the US regional programme, Peter Petrov (EU) looked at the EC’s support to CCS, and Don Lawton (Canada) gave a talk on Carbon Management Canada’s geoscience field research station (GFRS). Presentations from these talks will be provided to Members. 21. DONM PRESENTATION ON 45TH MEETING – OPEC, VIENNA, AUSTRIA Paper GHG/13/61 refers and Sian Twinning provided this talk. Kelly Thambimuthu invited Members to offer hosting the Spring 2015 ExCo meeting, noting that all who wish to do so should contact John Gale directly.

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22. AOB Åse Slagtern (Norway) commented on the ‘Milestone Mongstad’ event that was run at this year’s PCCC conference to commemorate TCM having been running for one year. She noted there were some good presentations from both Alstom and Aker Solution on their progress at the TCM, and made it clear that the work at TCM will continue. Alstom and Aker Solution have extended their period for testing their technologies. The amine plant is open for other vendors as well. The third site available at TCM have had 15 applications for establishing smaller pilot plants (which will be evaluated soon) and there is a project currently on-going looking for other full scale plant opportunities in Norway. It is planned that the next full scale plant will be identified by 2020. 23. CLOSE OF MEETING Kelly Thambimuthu (Chair) thanked the Swedish hosts for hosting the 44th Executive Committee meeting and drew the meeting to a close.

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CORRECTIONS TO MINUTES

Minutes have been sent to members for comments the version included is correct at time of printing. Comments on the minutes were received from; IEA EPL, Norway, Sweden, Switzerland, Chevron, and Statoil all of which have been incorporated in these minutes. Members are asked to formally approve the minutes.

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LIST OF ACTIONS

Action

No. On Action Status

1 General Manager Send final minutes of 43rd ExCo to members with corrections included

Complete

2 General Manager Complete review on non-CO2 gases In-hand 3 General Manager Revisit IP13-22 water use with PV production In-hand 4 General Manager IP required on N2O emissions status Complete

5 General Manager Complete negotiations to formalise FZJ’s membership as a sponsor

Complete

6 General Manager Initiate online voting for end of year accounts to speed up the process of approval

Complete

7 General Manager Review of IA incorporating members comments on topic areas

Complete

8 General Manager Explore co-operation with IEA CCS unit on the correlation between the CCS publications and patents with changes in policy etc

Complete

9 General Manager Prepare a scoping paper on Low Hanging fruit to discuss with the ExCo

In-hand

10 General Manager Prepare a brief for members on similarities and differences between IEAGHG and GCCSI

GHG/14/06

19


CCS & GHG MITIGATION – KEY ISSUES

NOTES

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MEMBERSHIP ISSUES/NEW MEMBERS

Members Status The Netherlands and Germany have formally left the IA and paid all outstanding dues. ForshungzentrumJulich (FZJ) has formally joined the IA. Babcock & Wilcox have informed us that they not continue their membership into the 2014/2015 financial year. GCCSI have notified us they will not be members for the forthcoming financial year. A MoU between the parties has been suggested but only outline discussions have been held so far. New Members There are no proposals for new members to be considered at this meeting. Interested Parties The following progress with interested parties can be reported:

• Discussions with Carbon Management Canada and COSIA re membership and are ongoing.

• We are continuing to explore if there is potential interest in an exchange of membership between IEAGHG and the World Steel Association

• Low level discussions have been held with Qatar Petroleum, Masdar/ADNOC, KNOC and Siemens re membership

• The EPA of Taiwan have expressed their desire to be members but OECD/IEA rules exclude them

• The Chairman attended the CCUS Summit in China in late October and picked up on contacts with a number of Chinese organizations and since then we have contacted SINOPEC, China Huaneng Group Clean Energy Research Institute (CHCERI) re membership. SINOPEC have given us a positive response.

• We have had discussions with JCOAL re the MoU but there are no developments to report.

• There is the possibility of developing a co-operative arrangement with the energy group of UN ESCWA1 following the meeting the GM attended in Abu Dhabi in autumn 2013.

1 United Nations Economic and Social Commission for Western Asia

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FINANCIAL OUT-TURN FOR 2013/14

The projected financial out turn is based 10 months of management accounts, which we are still in the process of reconciling with the accountants at the time of drafting this paper. At the time of the last management accounts, January 2014 the financial position was: Income: £1,503,000 Expenditure: £1,348, 250 (as of January 2013) Project expenditure: £154,000 (February and March 2014) This projection suggests we will be close to break even on the financial year. As indicated earlier we are still reconciling issues with income and expenditure in the accounts which we hope will be completed by the time of the ExCo so we can give a clearer indication of our end of year out turn.

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BUDGET PROPOSAL 2104/2015

This paper will be provided and presented to members at the ExCo meeting to allow the end of year assessment and any impact on the following year’s budget to be considered and included in the proposed budget.

23


OPERATING AGENTS REPORT

NOTES

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COMPLETED AND ONGOING ACTVITIES REPORT

Introduction This report provides a summary of activities completed and ongoing since the last ExCo meeting (44th) held in Stockholm, Sweden, October 2013. The report covers a 5 month period which included the Christmas holiday period. IEA Environmental Projects Ltd - IEAGHG team With regard to the IEAGHG team there are no issues to report. The move to our new office premises has been successfully completed. Members have been informed of our new location and postal address. 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 44th and 45th meetings, studies that will be underway at the time of the 45th meeting and studies that are outstanding are summarised in the tables below and overleaf. Table 1 Technical Studies published since the 44th ExCo meeting

Table 2 Studies being reported Title Contractor Publication date Comparing Different Approaches to Managing CO2 Storage Resources *

BGS March 2014

Deployment of CCS in Cement Industry * ECRA February 2014 CO2 Pipeline Infrastructure Review * Ecofys January 2014 Assessment of costs of capture at baseline coal power plants

Foster Wheeler Italia

May 2014

Contractor Report number

Publication date

UK FEED Studies – A Summary IEAGHG 2013-12 17/10/2013 The Process of Developing a CO2 Test Injection Experience

CO2CRC 2013-13 24/10/2013

Information Sheets for CCS Digital Creative 2013-16 06/11/2013 Summary report of the IEAGHG Modelling Network and the Risk Management Network Meeting

IEAGHG 2013-14 20/11/2013

Monitoring Network and Environmental Research Network – Combined Meeting

IEAGHG 2013-15 02/12/2013

IEAGHG OPEC Report of Workshop on CCS and CDM

IEAGHG 2013-17 14/01/2014

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CO2 Storage Efficiency in Aquifers EERC April 2014 Post Combustion Capture Process Flow Sheet Modifications

Hamburg University of Technology

April 2014

Geomechanical Fault Stability NGI May 2014 *GCCSI funded Table 3: Studies underway Title Contractor Draft Report date Xtl to Liquids Now being

covered in Study Proposal 45-13

tbc

Monitoring Selection Tool BGS December 2014 Impact of CO2 Impurity on CO2 Compression and Transportation

Newcastle University

June 2014

Oxy Gas Turbine Power Plants Foster Wheeler August 2014 Operating Flexibility of CO2 Storage and Transport

EERC August 2014

Evaluation of CO2 Adsorption Process in Natural Gas Production

WorleyParsons July 2014

Table 4: Studies out to/awaiting tender Title Proposal number Understanding the Cost of Retrofitting CO2 Capture in Oil Refineries (consortium formed, co-funding under negotiation, expected start date summer 2014)

42-07

Cost components for Storage of CO2 in association with enhanced oil recovery (tender deadline 31 March)

42-14

Quantifying and monitoring emissions reductions from CO2-EOR (tender deadline 10 March)

42-13

Techno-economic evaluation of CO2 capture for Pulp and Paper (under negotiation, expected start date summer 2014) 43-10

Evaluation of Various Process Control Strategy for Normal and Flexible Operation of PCC 43-03

Review of Offshore Monitoring Techniques 44-09 What Have We Learnt from Large Scale Operational Projects - Storage Study) 44-11

Table 5: Studies outstanding awaiting start Title Proposal number Environmental Impact Statements – Review of Gaps (will now be an IP)

41-09

Energy Storage and CCS 43-02 Public perception of CO2 pipelines 43-11 Value of Flexibility in CCS Power Plants 44-04 Evaluation and Incorporation of Future Improvements in CO2 PCC Technologies 44-02

Production of Hydrogen with CO2 Capture 44-01 Design and Costs of Full Scale Solid Looping CO2 Capture Plants 44-03 What Have We Learnt from Large Scale Operational Projects - Capture Study) 44-11

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b) Facilitating implementation.

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

• UNFCCC. COP 19 took place in Warsaw in November. IEAGHG attended, had discussions with various organisations, and distributed IEAGHG publications on the IEA and GCCSI booths. The Technology Mechanism was operationalized and progress made towards the 2020 agreement. The results of the COP were blogged on the 25 November.

• CSLF Technical Group/PIRT. Tim Dixon attended the CSLF Technical Group, Policy Group and Ministerial meeting in Washington DC in November, providing an update on IEAGHG activities and the study on Implications of Gas Production from Shales and Coal (a CSLF-proposed study). The IEAGHG were referred to in the Ministerial Communique. A report of the meeting was blogged on 11 November and published as IP 28.

• EU ZEP. IEAGHG (Tim Dixon) is member of the Policy and Regulation Task Force. IEAGHG (Stanley Santos) collaborated with ZEP in an advisory role and co-author for the report on ‘CCS for Energy-Intensive Industries’ (July 2013). Tim Dixon acted as the Independent Reviewer for a review of ZEP decision procedures in December 2013.

• Joint Task Force (JTF) on Bio-CCS. IEAGHG’s Tim Dixon is a member and will be replaced by Jasmin Kemper. 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.

• IEA International CCS Regulatory Network. IEAGHG assisted IEA to establish this network. The 4th edition of the Legal and Regulatory Review was published in January 2014, reviewing global developments, including IEAGHG’s work of relevance. The next meeting of the CCS Regulatory Network is 27-28 May at IEA Paris. All material and information from the Regulatory Network is available at: http://www.iea.org/topics/ccs/ccslegalandregulatoryissues/ieainternationalccsregulatorynetwork/ .

• London Convention. The annual meeting was on 14-18 Oct in London. Tim Dixon participated, updating on IEAGHG work of relevance and contributing to the CCS working group. Significant developments were agreed on the safeguards for transboundary CCS and on ocean fertilization. The conclusions were blogged and published as IP 26 (transboundary CCS) and IP 27 (Geo-engineering) on 23 October.

• CCSA. IEAGHG (Tim Dixon) participates in the International Mechanisms Working Group, and attended the IMWG meeting on 20 September to plan coordination for COP-19 in Warsaw. IEAGHG (Tim Dixon) is also an observer in the CCSA Working Group on Regulation.

• Clean Energy Ministerial (CEM) CCUS Action Group. IEA and GCCSI provide secretariat to the CCUS AG. For the CEM meeting in April 2013, a new work stream was organised on industry CCS, involving CCSA and IEAGHG (Stanley Santos). A report was produced for the CEM by IEA with IEAGHG input ‘Global Action to Advance Carbon Capture and Storage - A Focus on Industrial Applications’. There is a proposed work stream on storage capacity assessment for developing countries and multilateral-development banks, involving DECC, IEAGHG and BGS. Tim Dixon attended the CCUS Action Group meeting on 19 February and presented on Marine Treaties and shared CSLF’s plans on storage capacity methodologies. Several

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recommendations were agreed for further consideration by CEM countries for going forward to CEM 5 in Korea in May. These included application of CCS in industrial settings, the London Protocol transboundary issue, collaboration on demonstration projects, and work on CO2 storage capacities. 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 (including IEAGHG). The third meeting of the ISO Technical Committee on CCS, TC-265, was held in Beijing on the 23-25 September and reported to ExCo 44. A new working group on CO2-EOR was adopted. Work is underway in all the 6 working groups now. IEAGHG are actively involved in 4. The next ISO meeting is 31 March to 3 April in Berlin. IEAGHG (Tim Dixon and Stanley Santos) will attend. An update will be presented at ExCo 45.

The 2014 Summer School is due to be hosted in North America by the University of Texas from the 6 to 12 July. The organisation is underway. Over 230 registrations were received, up by 76% on last year. In addition to the existing Series Sponsors (Shell, Statoil, Schlumberger, Alstom, Gassnova, DECC, Ciuden, and CO2CRC) further sponsors are invited. This will conclude Phase 2 of the Summer School series, and a review of this phase will be undertaken and discussed with the International Steering Committee at GHGT-12 and at the 46th ExCo. Expressions of interest for hosting for 2015 have been received from Mexico and Australia. c) Facilitating international collaboration International Research Networks There has been one network meeting since the 44th ExCo. The Social Research Network was held in Calgary on 14-15 January, hosted by the University of Calgary. A blog was issued and the summary report is being drafted. This will be reported under ExCo paper GHG/14/17. All presentations and summary reports are on the Networks’ websites. 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. d) Communication activities Website. Early teething problems with the website have now been addressed, lost links etc and the new format it running smoothly. During the period 14/08/2014 and 06/03/2014 we have had 20,373 visits with , 81,222, pages viewed from 10,780 different visitors, taking into account the different reporting period, this is a slight decrease on the previous reported figures but does include the Christmas period. Although the majority of visits are still from conventional PC use, 4.5% of visits are now coming from mobile devices which will benefit from the new responsive template. The average visitor spends 4.16 minutes on the site a significant increase from previous reporting periods. The table below shows the breakdown of the location of our visitors.

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Country/Territory Visits % Visits

1. United Kingdom 4,516 22.17%

2. United States 2,472 12.13%

3. Japan 1,304 6.40%

4. Norway 1,177 5.78%

5. Germany 943 4.63 %

6. Canada 806 3.96%

7. Spain 804 3.95%

8. Australia 779 3.82%

9. France 769 3.77%

10. China 719 3.53%

Greenhouse News The Greenhouse News newsletter is still being well received despite it now having moved to an electronic format. It has been much easier to distribute and we have still had regular requests for subscription and for electronic editions to be e-mailed. We have still been receiving input from members, even though this is lower than we had hoped although we will continue to send out regular requests for news articles. Members are encouraged to send articles to Becky Kemp and Samantha Neades for inclusion in the newsletter. Weekly News The weekly news has also continued to be well received by all on the subscription list. We regularly receive comments regarding news stories and, although the number of people that are subscribed seems to have plateaued, we know that from word of mouth it is still popular. Conference series. -

• See paper GHG/14/18 for update on the GHGT conferences. • Summary reports have now been produced for both OCC3 and PCCC2. This is the

first time we have produced such a document for these conferences and early feedback has been very positive, welcoming the addition and recognising their value to not just the conference delegates, but also to those not able to attend. Both documents are available on our website at: OCC3 - http://www.ieaghg.org/docs/General_Docs/OCC3/OCC3%20Summary%20Brochure

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_final_high%20res.pdf PCCC2 - http://www.ieaghg.org/docs/General_Docs/PCCC2/PCCC2_Summary_1_highres.pdf

International Journal on Greenhouse Gas Control (IJGGC). The main development to note is that the Editors of IJGGC have agreed to develop a Special Issue in 2015 that will aim to update the IPCC Special Report On CCS which by then will be ten years old. The Editors have selected key topics to both update and review and a number of new topics to review that have developed since the IPCC report, such as pressure management/plume migration. The Editors will shortly going out to invite Authors to take the lead and produce these review papers. Information Dissemination developments

• Social Networking. As of August 2013, the Facebook, Twitter and LinkedIn pages are being kept up to date and current with regular posts about IEAGHG activity and other relevant news. The Facebook page has 342 ‘likes’, the Twitter page has 352 followers and the LinkedIn group has 204 members

• IEAGHG Blog. We are endeavoring to increase our activity on the blog site with more regular articles from staff and a blog now on each published report.

• 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. 34 were created for Members in 2013 and a total of 2 have been were issued so far in 2014.

• Annual Review – The Annual Review for 2013 is currently underway. Overview Book – The annual Overview Book for 2013 will be underway in due course.

Table 6: List of Completed Information Papers (October 2013 – March 2014) 2013 Information Papers Title Report No. Issue

D t Ozone hole and Global Warming linked 2013-IP21 August

Water Intensity of Power Generation 2013-IP22 August

HCFC Substitution 2013-IP23 September

Corrosion Workshop Discussion Summary 2013-IP24 September

Impact of N2O on the greenhouse effect and ozone depletion 2013-IP25 October

CCS in the London Convention – Update from the 2013 meeting 2013-IP26 October

Geoengineering in the London Convention 2013 2013-IP27 October

CSLF Meetings, Washington DC, 4th - 7th November 2013 2013-IP28 November

HFC’s Amendment Stalled 2013-IP29 November

New Report on Ocean Acidification 2013-IP30 November

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Drawing Down N2O to Protect Climate and the Ozone Layer 2013-IP31 November

RISCS workshop 25th September 2013, London 2013-IP32 December

North American Wellbore Integrity Workshop October 16-17th, 2013

2013-IP33 December

Site Char Closing Conference 28th November 2013, IFP Energies Nouvelles, Rueil-Malmaison, Paris

2013-IP34 December

IEA 65th Working Party on Fossil Fuels (Confidential) 2014-IP1 January

Carbon capture technology could be vital for climate targets 2014-IP2 January

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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GHG/14/09 2014 Meeting Presented by Date Biomass and CCS: Global Potential and GHG Accounting

APGTF Annual Workshop, London

Jasmin Kemper 13 March 2014

Carbon Dioxide Capture and Storage - International Legal and Regulatory Developments and Carbon Accounting (and the role of IEAGHG)

CCS MSc. Climate Change Law LLM. Carbon Management MSc. University of Edinburgh

Tim Dixon 28 February 2014

CCS in Europe Austin, USA John Gale 28 January 2014 Carbon Dioxide Capture and Storage - Managing Promises and Resolving Uncertainties Through Science

IEA Fusion Power Co-ordinating Committee

Tim Dixon 28 January 2014

IEAGHG Offshore-related Activities BEG, UT, Austin, USA Tim Dixon 21 January 2014 Carbon Dioxide Capture and Storage - What, Why, Where and Texas's role (and GHGT)

CleanTX, Austin Tim Dixon 21 January 2014

IEAGHG Perspectives on MVA and ETS (for CCS) CARB and LBNL, Sacramento, USA

Tim Dixon 17 January 2014

2013 Review of Decision Making Processes in ZEP EU ZEP Advisory

Council, Brussels Tim Dixon 11 December 2013

Post Combustion CO2 Capture Technology: Current Status and Future Directions

Conference on Clean Coal and CCS Technologies, India

Prachi Singh 3 December 2013

Carbon Capture and Storage: Developments, Potential and Challenges in the Global Context

Conference on Clean Coal and CCS Technologies, India

Prachi Singh 3 December 2013

Global Status of CCS CCUS in EWSCA Member States, Abu Dhabi

John Gale 6-7 November 2013

Update on IEAGHG activities and Implications of Gas Production from Shales and Coal for Geological Storage of CO2

CSLF Technical Group, Washington DC, USA

Tim Dixon 5 November 2013

CO2 Post Combustion Capture Operational Flexibility and Scale-up for power plants

13 AiChE Annual Meeting, San Francisco

Prachi Singh November 2013

Applications and Potential of CCS in the non-Power Sector

IEAGHG-OPEC Workshop, Vienna

John Davison 29 October 2013

CCS Costs and Economics IEAGHG-OPEC John Davison 29 October 2013

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http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CCS_in_Europe_2014.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Fusion_and_CCS_v1.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/Fusion_and_CCS_v1.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/IEAGHG_and_Offshore_Activities_v4.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CleanTx_CCS_v4.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/CleanTx_CCS_v4.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/ETS_and_IEAGHG_v3.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/IEAGHG_P._Singh_Post_Combustion_CO2_Capture.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/IEAGHG_P._Singh_Post_Combustion_CO2_Capture.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/IEAGHG_P.Singh_CCS_Global.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/IEAGHG_P.Singh_CCS_Global.pdf

http://www.ieaghg.org/








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

GHG/14/09 Workshop, Vienna

Applications of CCS in the Power Sector IEAGHG-OPEC Workshop, Vienna

John Davison 29 October 2013

Overview of CCS Technology IEAGHG-OPEC Workshop, Vienna

Tim Dixon October 2013

CCS - Necessary Action to Reduce CO2 Emissions from Energy Intensive Industries (Case Study for Iron & Steel Sector)

Scottish CO2 Capture & Storage Workshop, Grangemouth, UK

Stanley Santos October 2013

CCS - Necessary Action to Reduce CO2 Emissions from Energy Intensive Industries (Case Study for Iron & Steel Sector)

Swedish Energy Agency - Stockholm Seminar on CCS, Sweden

Stanley Santos October 2013

Update Report on IEAGHG Activities to ISO TC 265 ISO TC 265, Beijing Tim Dixon 25 September 2013 Performance of Dehydration Units for CO2 Capture PCCC2 Bergen, Norway Jasmin Kemper September 2013 Technology Advances in Post-Combustion Capture to Approach a Viable Business Case

PCCC2, Bergen, Norway

Prachi Singh September 2013

Getting a new technology adopted by international legal frameworks and carbon accounting – CCS

Joint UQ Energy Initiative, SMI, Centre for CSG Seminar, Brisbane

Tim Dixon 4 September 2014

UK Feed Studies 2011 - A Summary UKCCS/NCCS Biannual Meeting, Nottingham, UK

John Gale 4 September 2013

Understanding the Cost of Deploying CO2 Capture in an Integrated Steel Mill

Seminar on the Economics of CO2

Stanley Santos September 2013

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http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_-_Grangemouth_Wkshp_Final_Version_v_1.0.pdf



http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_Stockholm_Nordic_CCS_Wkshp.pdf




http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/P._Singh_Tech_Eco_SCPC_PCCC2.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/P._Singh_Tech_Eco_SCPC_PCCC2.pdf

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

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_ESTEP_Mtg_IS_ppt_final.pdf

http://www.ieaghg.org/docs/General_Docs/IEAGHG_Presentations/S._Santos_ESTEP_Mtg_IS_ppt_final.pdf

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CO2 PIPELINE INFRASTRUCTURE

The aim of this IEAGHG study with funding from GCCSI was to collate information from the public domain on existing CO2 pipelines and to provide the overall lessons learned from this task. Based on a wide range of interviews and literature, Ecofys and SNC-Lavalin have gathered information on 29 CO2 pipeline projects (out of more than 80 worldwide) and produced a comprehensive reference manual on the key issues regarding CO2 pipeline projects. To make access to the collated information easier and more user-friendly, Ecofys also implemented an interactive web tool that shows the location, routing and project details of the 29 CO2 pipeline projects investigated in this study. In addition, Frank Wiersma of Ecofys presented the findings of the study during a webinar hosted by GCCSI. The Overview was sent to members in December for review, and IEAGHG published the report in January 2014 as report IEAGHG 2013/18.

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CO2 PIPELINE INFRASTRUCTURE

Key Messages

• New CO2 pipeline projects require large investments in infrastructure. Re-use of existing infrastructure can lead to substantial savings in investment costs.

• In the US, EOR has been the primary driver for CO2 pipeline infrastructure development. Most EU projects focus on CO2 storage within emissions reduction schemes.

• Except for the US, most countries have little or no experience with CO2 pipelines or CO2-EOR operations.

• Start-up, routine inspection, shutdown and venting of CO2 pipelines can differ considerably from natural gas pipelines.

• Pipelines can usually handle the flexible operational needs of both supplier and user. Examples for pipeline networks exist in the US. These hubs have no specific set of rules, as each system has its own standards for CO2 purity and operating conditions.

• Although CO2 pipelines are rarely the focal point of public concern, effective communication strategies are a key element for successful implementation of the whole project.

• Currently it is not possible to draw robust conclusions, whether or not the incident rate with CO2 pipelines would be different from other gas pipelines.

• Little information is publicly available on the costs of CO2 pipelines.

• The contractor created a reference manual, database and interactive web tool detailing information on 29 CO2 pipeline projects worldwide.

Background to the Study Currently there are more than 6,500 km of CO2 pipelines worldwide; most of them are linked to EOR operations in the United States but there are also a number of pipelines associated with or under development for CO2 storage. Valuable experience is available from these projects for all phases of pipeline projects: from early design through to operation and decommissioning.

The aim of this study is to collate information from the public domain on existing CO2 pipelines into a comprehensive reference document. Other objectives are to discuss the similarities and differences between CO2 and other, especially natural gas, pipelines and to provide an overview. The overall lessons learned from this study should support project developers, decision makers, regulators, and governmental bodies who do not deal with engineering calculations and cost estimates on a regular basis.

The IEAGHG commissioned this study on behalf of the Global CCS Institute. Ecofys was the main contractor with SNC-Lavalin, who has extensive experience in the oil and gas industry, e.g. in US-based EOR operations, acting as a subcontractor.

Scope of Work

The deliverables for this study consist of a reference manual, database, interactive web tool and webinar. The reference manual highlights key design, construction, operational and regulatory

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learnings. A database, containing more than 100 data elements, complements the reference manual. It covers the following categories, as Table 1 shows:

Table 1 - Categories and elements of the database

Category Sub-categories Data elements

Pipeline infrastructure Pipeline Auxiliary equipment Costs

E.g. Route, length, depth of lay, material, diameter, wall thickness Compression and dehydration Design and construction

Operation & maintenance, risk and safety

Operational characteristics Monitoring Safety

E.g. Volume, source, destination, purity, pressure, flow Inspections and monitoring Procedures, corridors and valves

Regulatory regime Realisation process Restrictions

Spatial planning, environmental impact assessment and permits/concessions E.g. Spatial planning and location

Public concern Public communication Decision process

Media, publications and health Environmental Impact Assessment

To make access to the collated information easier and more user-friendly, Ecofys implemented an interactive web tool based on Google Maps. It shows the location and routing of the 29 CO2 pipeline projects investigated in this study and allows users to zoom in and access a summary of information from the database (see screenshot in Figure 1).

Figure 1 - Interactive web tool (demo version available at http://www.globalccsinstitute.com/publications/co2-pipeline-infrastructure)

From over 80 CO2 pipeline projects worldwide, Ecofys carefully selected a subset of 29 projects covering all key regions and operating conditions in a balanced way (see Table 2). More than half of the chosen projects are operational.

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Table 2 - CO2 pipeline projects included in the assessment

Project name Country codea

Statusb Length (km) Capacity (Mton/y)

Onshore / Offshore

Sinkc

North-America

1 CO2 Slurry CA P Unknown Unknown Onshore EOR

2 Quest CA P 84 1.2 Onshore Saline aquifer

3 Alberta Trunk Line CA P 240 15 Onshore Unknown

4 Weyburn CA O 330 2 Onshore EOR

5 Saskpower Boundary Dam CA P 66 1.2 Onshore EOR

6 Beaver Creek US O 76 Unknown Onshore EOR

7 Monell US O 52.6 1.6 Onshore EOR

8 Bairoil US O 258 23 Onshore Unknown

9 Salt Creek US O 201 4.3 Onshore EOR

10 Sheep Mountain US O 656 11 Onshore CO2 hub

11 Slaughter US O 56 2.6 Onshore EOR

12 Cortez US O 808 24 Onshore CO2 hub

13 Central Basin US O 231.75 27 Onshore CO2 hub

14 Canyon Reef Carriers US O 354 Unknown Onshore Unknown

15 Choctaw (NEJD) US O 294 7 Onshore EOR

16 Decatur US O 1.9 1.1 Onshore Saline aquifer

Europe

17 Snøhvit NO O 153 0.7 Both Porous Sandstone formation

18 Peterhead UK P 116 10 Both Depleted oil/gas field

19 Longannet UK C 380 2 Both Depleted oil/gas field

20 White Rose UK P 165 20 Both Saline aquifer

21 Kingsnorth UK C 270 10 Both Depleted oil/gas field

22 ROAD NL P 25 5 Both Depleted oil/gas field

23 Barendrecht NL C 20 0.9 Onshore Depleted oil/gas field

24 OCAP NL O 97 0.4 Onshore Greenhouses

25 Jänschwalde DE C 52 2 Onshore Sandstone formation

26 Lacq FR O 27 0.06 Onshore Depleted oil/gas field

Rest of the World

27 Rhourde Nouss-Quartzites DZ P 30 0.5 Onshore Depleted oil/gas field

28 Qinshui CN P 116 0.5 Onshore ECBMR

29 Gorgon AU P 8.4 4 Onshore Sandstone formation a Country codes: AU=Australia, CA=Canada, CN=China, DE=Germany, DZ=Algeria, FR=France NL=Netherlands, NO=Norway, UK=United Kingdom, US=United States b Legend status: P=Planned, O=Operational and C=Cancelled c EOR=Enhanced Oil Recovery, ECBMR=Enhanced Coal Bed Methane Recovery

The contractor used the following sources for data gathering:

• Project websites • Environmental Impact Assessments (EIA) / Environmental Impact Statements (EIS) • Reports and permit applications • Front End Engineering Design (FEED) studies • Scientific publications • Interviews with pipeline owners and project developers

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To maximise amount of data and lessons learned, Ecofys included four cancelled CO2 pipeline projects in the scope of the study (i.e. Barendrecht, Jänschwalde, Kingsnorth and Longannet).

Findings of the Study

Availability of data

The quality, accessibility and level of detail of the data presented in the following sections varied for a number of different reasons:

• Confidentiality / commercial purposes • Change of pipeline owner • Lost or inaccessible data • Lack of digitalisation • Language

Drivers for CO2 pipeline projects

Table 3 shows the main drivers for CO2 pipelines and gives example projects for each category.

Table 3 - Drivers of CO2 pipeline projects (adapted from Amann, 2010)

Motivator Comments Example projects

Enhanced Oil Recovery (EOR) CO2 is used as a tertiary recovery agent to increase oil production in depleting or old oil fields.

SACROC, Monell, Beaver Creek, Boundary Dam

CO2 reduction targets CO2 is stored in deep saline formations or depleted oil or gas fields

Quest, Barendrecht, Jänschwalde, Kingsnorth, Lacq Longannet, Peterhead, ROAD, Snøhvit, White Rose, Rhourde-Nouss-Quartzite

Enhanced Coal Bed Methane Recovery (ECBMR) and Enhanced Gas Recovery (EGR)

CO2 is used to enhance coal bed methane production from coal-beds or coal bearing formations or re-injected in suitable gas formations (depleted or for EGR)

Qinshui

Use of CO2 for industrial purpose CO2 is transported to greenhouses and used to stimulate growth of plants and crops

OCAP

In case of EOR, a project can make a good return and offset the investment costs by using CO2 to increase the oil production. However, if market conditions change the project may lose its incentive. An example is the Beaver Creek project that was abandoned due to low oil prices during the late 1980s but was revived in 2005.

In certain jurisdictions, revenue may come from generating carbon offsets. Most CCS projects in Europe focus on CO2 storage as a mitigation option. As this does not result in additional revenues, a financial support system or carbon offset system, like the EU ETS, needs to be in place.

Sources, sinks and hubs

CO2 pipelines connect a variety of sinks and sources. Figure 2 shows that gas processing and coal-fired power plants are the most common sources for the pipeline projects investigated in this study. Common sinks are oil fields under EOR but also depleted oil and gas fields. These storage sites generally have the benefit of existing infrastructure that can be re-used.

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Figure 2 - Sources and sinks of CO2 pipeline projects

The purity of the CO2 stream depends on the CO2 source and, if appropriate, the CO2 capture technology. In ⅔ of the 29 pipeline projects the purity exceeds 95% and ⅓ of the projects deliver a purity greater than 99%. The main impurities in the CO2 stream are H2O, N2, O2, H2S and CO.

Where multiple CO2 sources and sinks exist, a gathering, transmission and distribution network - a hub - may develop. Currently operating hubs are almost all located in the US; examples are the Denver City Hub and the McCamey Hub. CO2 hubs have no specific set of rules or lessons learned because they are usually developed ad-hoc when CO2 sources are available and/or a viable market exists. Each hub has its own standards for CO2 purity, acceptable impurities, pressure and temperature.

Planning, design and construction of CO2 pipelines

The physical characteristics of the CO2 pipelines investigated in this study vary greatly. For example, the range in length lies between 1.9 and 808 km. The following Table 4 shows the spread in other characteristics such as diameter, wall thickness, etc.

Table 4 - Physical characteristics of CO2 pipelines

Range

Length (km) 1.9 - 808

External diameter (mm) 152 – 921

Wall thickness (mm) 5.2 – 27

Capacity designed (Mt/y) 0.06 – 28

Pressure min (bar) 3 – 151

Pressure max (bar) 21 – 200

Compressor capacity (MW) 0.2 - 68

The inclusion of short-distance demonstration projects as well as commercial, long-distance EOR projects is the main reason for the large variation. The longest pipelines are located in North America and the average length of CO2 pipelines there is longer than in Europe. Another interesting point is a positive correlation between length and capacity of the pipelines. It seems that longer pipelines have to transport larger volumes of CO2 to be economically viable.

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Technical standards for CO2 pipelines

The following dedicated standards for CO2 pipelines currently exist:

• Unites States: CFR part 195 • Canada: CSA Z662 • Europe: DNV-RP-J202 • ISO/TC 265 (currently under development)

CO2 pipeline project phasing

In many respects, CO2 pipelines are comparable to natural gas pipelines but there are the following key differences:

• The properties of CO2 lead to different design parameters. • In many places CO2 pipeline projects are first-of-a-kind. • CO2 pipelines do not transport a product that people see as directly beneficial. • Risks associated with geological storage and the Lake Nyos incident influence the public

perception of CO2 pipelines.

Apart from this, CO2 pipeline projects generally go through the same cycle as other gas pipeline projects. The project cycle typically takes between 3 to 6 years from concept stage to the final investment decision. The actual construction time usually lies between 1 and 4 years depending on the length and complexity of the pipeline.

Pipeline and equipment

Pipelines usually have a service lifetime that exceeds their reason for existence. If the initial design specifications allow for, than in most cases a re-use is beneficial, as this can drastically reduce the overall project costs. Offshore pipelines are a common area for re-use because they have the highest costs of all different terrain types (see Table 6 in section on CO2 pipeline costs). There are no serious negative technical implications to operate a re-purposed pipeline in CO2 service, as long as the capacity is lower than original.

Corrosion of the pipeline steel (which is usually carbon steel due to economic reasons) is a serious concern related to leakage and needs to be addressed during the whole project. Most CO2 pipelines are buried under the ground, so they need both internal and external corrosion protection. The most commonly used method to prevent external corrosion is cathodic protection, sometimes in combination with a coating. Water is the main risk factor for internal corrosion. A dehydration system can keep the water content well below the allowable limit (about 840 ppmv for onshore in North America; offshore European may require below 50 ppmv). CO2 streams from sources that produce a dry CO2 gas (e.g. hydrogen plants, gas-processing plants) may not need additional dehydration.

The number and capacity of the compressors depend on the pipeline dimensions, transported volume and phase of the CO2 stream. The majority of the studied pipelines transport the CO2 in supercritical phase. To avoid phase change in practice the operators stay clear of the phase transition boundaries.

During operation, a sudden unexpected pressure drop in the pipeline can indicate a leak. For such a case, pipelines are equipped with Emergency Shutdown (ESD) valves to isolate the affected pipeline section. The distance between these ESD valves varies over the pipeline and depends on factors like population density and regulations. The selected CO2 pipelines in this study have an average ESD valves distance of 10-20 km.

Flow meters are another important piece of equipment. They provide both a means of accurate billing and early detection of leaks.

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In contrast to natural gas, high-pressure CO2 pipelines are not self-arresting in terms of longitudinal failure and thus require the installation of crack arrestors. Crack arrestors can simply be occasional joints of pipe with greater wall thickness and improved hoop-stress properties. An alternative is the periodic wrapping with non-metallic materials.

Regulatory regime and permitting

Depending on the location of the project and the related regulatory framework, an assessment of environmental impacts might be necessary. The approaches and requirements for this vary from country to country. In general, such an assessment for a CO2 pipeline is not fundamentally different from that for another gas pipeline.

North American regulations require an Environmental Impact Statement (EIS) when the project is complex in nature and needs consideration and analysis of environmental effects, for example under the National Environmental Policy Act (NEPA) in the US. Opinions of stakeholders and public participation play an important role in North American EISs. According to Directive 2011/92/EU, in Europe an Environmental Impact Assessment (EIA) is required for pipeline sections with a diameter of more than 800 mm and a length of more than 40 km. Most European CO2 pipeline projects carried out an EIA because the capture and storage facilities triggered it, not the pipeline itself. By and large, there are not many EIAs or EISs that focus specifically on the pipeline part. The Kingsnorth project, for example, carried out an assessment for the offshore section of the pipeline.

In the investigated jurisdictions, CO2 pipelines are within the regulatory framework of all pipelines that transport gaseous or liquid substances. In the US, CFR 49 Part 195 applies, which was amended in 1989 to include CO2 in the former “Hazardous Liquid” category. Before this, CO2 pipelines had to meet codes for natural gas pipelines. Canada has its own regulation for CO2 pipelines, CSA standard Z662. In Europe, Directive 2099/31/EC on geological CO2 storage states that the framework used for natural gas pipelines is adequate to regulate CO2 as well.

The permitting and approval process plays a key role in the timeline realisation of pipeline projects. Securing permits and performing EISs/EIAs usually takes much longer than actual construction. An example for this is the 808 km Cortez pipeline in the US, which took 8 years to complete with only 2 years of construction time. Reason for the long timeline was the requirement for state-by-state approval of the pipeline routing.

Construction of CO2 pipelines

The acquisition of necessary permits and right-of-way may be more time consuming than the actual construction of the pipeline, so they have to be done in a timely manner. In the US, CFR Section 195.248 prescribes a minimum pipeline burial depth of 1.2 m. After construction, regulations require a test of pipeline integrity. CO2 pipelines that have passed hydrostatic testing are cleaned and dried to prevent corrosion or premature failure on start-up.

Operation, inspection and maintenance of CO2 pipelines

Regulations require that the responsible operator prepares and follows a manual for each pipeline system. It consists of written procedures for conducting normal operations and maintenance activities but also handling abnormal operations and emergencies. In the US, this manual needs to be reviewed at least once a year.

Limited data was available on the control systems used for CO2 pipelines. Typically, a SCADA (Supervisory Control and Data Acquisition) system monitors the key operational parameters: pressure, temperature, water content and flow rate. Very small leaks may be hard to detect with this system. The Weyburn project uses a special Leak Detection System (LDS), which monitors for leaks

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every 5 seconds and displays the related data on a computer screen. In combination with proprietary software, the LDS can determine the size and location of a potential leak. The flow meters integrated into SCADA and LDS help with checking the CO2 mass balance for contract obligations.

Inspection

To minimise external influences, most pipelines are buried underground but this makes inspection more difficult. Most countries prohibit building activities within a certain range of the pipeline corridor (typically 5 m). In addition, visual corridor inspections by foot, car or helicopter take place every week.

Most operators use so-called “pig runs” to inspect the inside of their pipelines. A pig can clean the pipeline, measure wall thickness and detect leakage and corrosion. With around EUR 1 million (USD 1.4 million) for pipelines with a length between 25 - 270 km, pig runs are very costly. One reason for this is the low lubricity of CO2, which poses a great challenge.

Besides the pipeline, inspection of auxiliary equipment takes places on a regular basis as well. This includes compressors, dehydration units, valves, cathodic protection system, monitoring systems and emergency systems.

Safety statistics

For the US, the PHMSA (Pipeline and Hazardous Materials Safety Administration) provides statistics on pipeline incidents. According to PHMSA, there have been 46 incidents involving CO2 pipelines between 1972 and 2012. The main reasons for these incidents were:

• Relief valve failure • Weld, gasket or valve packing failure • Corrosion • Outside force

Most of these incidents occurred in areas with low population density, so they did not cause any reported casualties or fatalities. In contrast, natural gas pipeline accidents injured 217 and killed 58 people over the period 1986 – 2001. However, it is difficult to make effective comparisons between CO2 and natural gas pipelines yet because of the huge discrepancy in the number of km of pipeline (550,000 km vs. 6,500 km in the US).

In Europe, no incident reporting or analysis system exists for CO2 pipelines, so industry gathers statistics and reports incidents on a voluntary basis. The OCAP project reported three incidents with small leakages during operation of the pipeline. Again, no human injuries or fatalities occurred.

Decommissioning and abandonment

Pipeline decommissioning is the permanent deactivation of a pipeline that leaves the pipeline in a permanently safe condition, as prescribed by a regulatory body.

The main reason for decommissioning of a pipeline is that it no longer has a commercial use. Otherwise, well-constructed and well-maintained pipelines often have a lifetime in excess of the design lifetime. CO2 pipelines are expected to perform as well or even better than other gas pipelines if the operator carefully addresses corrosion issues.

Because the existing CO2 pipeline projects are relatively young (40 years), there is hardly any information available about large-scale decommissioning activities.

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Public concern

It is important to understand the key drivers of public concern because it can become a serious threat to a project if not handled in time and in a careful manner. During interviews many pipeline operators made clear that the CO2 pipeline is usually not the focal point of public opposition. Most concerns relate to either the capture (building of a power plant or production plant) or the storage part of the project. In general, there is less public concern over offshore transport and storage than over onshore projects.

The Barendrecht CCS project in the Netherlands is an example where public concern led to the cancellation of the project. The developers of the ROAD project directly used the lessons learned from Barendrecht by training staff to communicate simply and clearly and to address concerns from local residents.

Most projects investigated in this study used websites, public meetings and telephone helplines as means of communication. The range of available information on the websites can vary between the different projects. Some projects (like Saskpower Boundary Dam, OCAP, Lacq) have dedicated websites while others (e.g. Kinder Morgan, Jänschwalde, Kingsnorth) just provide simple generic information. The participation in public meetings varies as well. Most North American pipeline projects have seen only limited interest in public meetings. Reasons for this are the difference in population density and the long-standing oil and gas operations that both lead to a higher acceptance of pipelines compared to Europe.

CO2 pipeline costs

The following list gives an overview of the key costs drivers for pipelines:

• Piping (type and grade of material) • Equipment (such as compressors, booster stations, valves, crack arrestors, etc.) • Trenching (i.e. earthworks, excavation, backfilling) • Distance • Diameter • Terrain • Labour • Engineering (e.g. design, project management, regulatory/permitting activities)

For some projects, cost data is publicly available and can be used as a reference to estimate future project costs. Due to commercial reasons, engineering companies sometimes keep the design and construction costs confidential. Table 5 presents actual costs for selected CO2 pipeline projects that were available from public documents.

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Table 5 - Actual costs for selected CO2 pipelines

Pipeline Costs for pipeline

Currency

Year Onshore/ Offshore

International units

Canyon Reef Carriers (SACROC)

46 million USD 1971 Onshore

D= 324 – 420 mm L= 354 km

Cortez 700 million USD 1982 Onshore

D= 762 mm L= 808 km

Weyburn CO2 pipeline

51 million USD 2008 Onshore

D= 305 – 356 mm L= 330 km

Quest 140 million USDb 2012 Onshore

D= 324 mm L= 84 km

Qinshui 39.35 million USD 2006 Onshore

D= 152 mm L= 116 km

Longannet 160 million GBP 2011 On: 100 km Off: 270 km

D= 500 to 900 mm L= 380 km

ROAD 90 million EUR 2010 On: 5 km Off: 20 km

D= 450 mm L= 25 km

Gorgon 9 million AUD 2011 Onshore D= 269 – 319 mm L= 8.4 km

a For pipeline and associated compression stations b Initial estimate in CAD (Canadian dollars). Assumed exchange rate USD 1.00 = CAD 1.00

If data is not readily available, then it is possible to estimate pipeline capital costs using credible sources, like the NETL guidelines (Carbon Dioxide Transport and Storage Costs in NETL Studies – Quality Guidelines for Energy Systems Studies). The related formulas reflect US dollars as of 2011 and require diameter and length as input parameters. The results of the estimation can give a first impression of possible CO2 pipeline costs but are in no way an accurate estimate. In any case, terrain has the strongest influence on pipeline costs and accounts for the largest uncertainty in cost estimation. Table 6 shows costs for different types of terrain and it is clear that interference with bodies of water increases the costs most.

Table 6 - Pipeline cost metrics as disclosed by Kinder Morgen

Terrain Capital Cost (USD/inch-Diameter/mile)

Flat, Dry USD 50,000

Mountainous USD 85,000

Marsh, Wetland USD 100,000

River USD 300,000

High Population USD 100,000

Offshore (150-200 feet ~ 45–60 meters depth) USD 700,000

Operation and maintenance costs are not readily available from the investigated CO2 pipeline projects but again can be estimated by using the following guidelines:

• Fixed O&M costs of USD 8,454 per mile and year (NETL guidelines) • 1.5% of initial capital costs per year (Wong 2010) • 3-8% of initial installed capital costs (confidential source) • EUR 1 million (USD 1.4 million) per pig run (Wevers 2013)

A number of factors differentiate CO2 pipelines from other gas pipelines when it comes to costing. Some examples are:

• The CO2 depressurisation characteristics dictate the use of crack arrestors.

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• The carbon steel grade needs to be resistant towards brittle fracture because CO2 can reach very low temperatures when expanded.

• CO2 suppliers have to deliver at specified conditions which are in general: o 95% purity o Water content depending on region between 50 – 840 ppmv o Temperature and pressure according to single dense phase transport

• Installation of ESD valves to limit CO2 release in case of leakage. • Venting procedures need to include provisions for lofting and dispersing released CO2. • Gaskets and other non-ferrous materials must be resistant to deterioration in presence of CO2.

Usually the CO2 supplier(s) or the CO2 capture project part is responsible for accounting the costs related to separation, clean-up, compression and dehydration of the raw CO2 stream.

Expert Review Comments

Six reviewers from industry, academia and other organisations took part in the expert review of the reference manual and submitted useful comments. In general, the reviewers stated that the reference manual has a good structure and provides a valuable overview on CO2 pipeline transport. Some reviewers asked to increase the level of detail in certain sections (especially regarding operating conditions, impurities and corrosion) and to harmonise the information presented in the two main sections of the report (i.e. lessons learned from existing projects and guidelines for CO2 pipeline projects). Ecofys addressed most of the comments in the final version as long as they have been within the scope of the study. In some places, Ecofys regarded the addition of more information as not beneficial for the report and established a stronger reference to the database. The review of database and web tool was done by IEAGHG and the Global CCS Institute only.

Conclusions

The purpose of this study was to collect public information on CO2 pipelines and make it available to project developers, decision makers, regulators and the interested public. The findings of the study are easily accessible in three different ways: through a reference manual, a database and an interactive web tool.

With the exception of the US, most countries have no or little experience with CO2 pipelines or CO2-EOR operations. Even for many of the operational projects certain information is not accessible due to commercial or other reasons. This applies especially to costs and auxiliary equipment that belongs to other parts of the process chain, like compressors and dehydration units.

Currently the main driver for CO2 pipeline projects is EOR. CO2 transport and storage as part of larger CCS projects can only generate revenues if a pricing or support scheme is in place.

A main result of the study is that CO2 pipelines are both similar and different compared to other gas pipelines, natural gas in particular. They are similar to some extent, so that the regulations and standards used for CO2 originate in natural gas pipeline codes. But they are different in terms of the physical properties of CO2, which results in different design parameters, and the risk perception, which the public usually associates with geological storage of CO2.

The permitting and approval processes play a large role in realisation of the project timeline. This can take much longer than expected and exceed the construction time by far. The CO2 pipelines in the US have a 40-year history of operation with no civilian injuries or fatalities. In contrast to Europe, a sophisticated reporting system exists.

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Detailed cost information was difficult to find for many projects due to confidentiality. Key factors determining the costs of a CO2 pipeline are terrain, length and capacity. The primary means of cost reduction is the re-use of existing pipeline infrastructure. Some projects in the EU considered this approach (e.g. OCAP, Lacq, and Peterhead).

Public concern may vary from project to project, depending on the location, population density, type of project, source and sink of CO2, etc. As public opposition can lead to cancellation of the whole project (as in the case of Barendrecht), effective communication strategies and early involvement of all stakeholders are key elements in addressing such concerns. Although important developments are expected in pipeline technology, e.g. in the fields of corrosion resistance, pigging and crack arresting, it is likely that the main area, where improvement is necessary, will be public acceptance.

Recommendations

The combination of the three deliverables (i.e. reference manual, database and interactive web tool) is a very attractive way of disseminating the results of this study to slightly different target groups and their needs. However, these tools live on being up-to-date. This is why we recommend a regular update of the web tool and database through follow-up studies (every 2-3 years).

We also think it is a good idea to use the results of this study for setting up a Wiki on CO2 pipelines/transport to deliver information in an easily comprehendible way to the public. Likewise, an extension of the Wiki with other IEAGHG studies on CO2 transport, capture, storage, etc. is possible.

Although CO2 pipelines are usually not the focal point of public concern, source and sink of the CO2 can largely influence how the public perceives them. Because of this, we aim to undertake a study focussing on the public perception on CO2 pipelines.

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IEA GREENHOUSE GAS R&D PROGRAMME

45th EXECUTIVE COMMITTEE MEETING

BARRIERS TO CCS IN THE CEMENT INDUSTRY

This study was undertaken for IEAGHG by the European Cement Research Academy (ECRA) in Germany, at the request of and with financial support from the Global CCS Institute (GCCSI). The Overview of the final report is attached. The Overview was sent to members in December for review, and the report was published as IEAGHG report 2013/19.

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DEPLOYMENT OF CCS IN THE CEMENT INDUSTRY

Key Messages

• Established techniques can be used to reduce CO2 emissions from cement production, including increased energy efficiency, use of alternative raw materials and fuels and reducing the clinker:cement ratio. However, CCS will be needed to achieve deep emission reductions.

• The preferred techniques for capturing CO2 in cement plants are oxyfuel and post combustion capture. Pre-combustion capture is at a disadvantage because it is unable to capture the large amount of CO2 produced by carbonate decomposition.

• Oxyfuel technology is in general expected to have a lower energy consumption and costs than post combustion capture using liquid solvent scrubbing.

• Some pilot plant projects for post combustion capture at cement plants are underway but oxyfuel technology for cement plants is still at the laboratory stage of development.

• A survey of the cement industry showed that most of the respondents think that CCS is relevant to them and they are aware of research projects, and half are involved in CCS activities. More than half of the respondents would contribute financially to CCS research but only a third would be willing to contribute to pilot or demonstration plants due to high costs.

• With the current legal and economic conditions CCS would impair the competiveness of cement production, which will inhibit development and application of CCS in the cement sector.

Background to the Study The cement industry is a major source of industrial greenhouse gas emissions and accounts for around 5 % of global anthropogenic greenhouse gas emissions. The cement industry has been reducing its energy consumption and greenhouse gas emissions per tonne of cement through a variety of different techniques aimed at reducing costs and satisfying other environmental targets. These techniques have already been exploited to a significant extent and they will only be able to partly contribute to the emission reductions required to meet global climate change goals. The remaining fraction of the reduction will require the application of CCS.

IEAGHG published a techno-economic study on capture of CO2 in the cement industry in 20081. Since that time the level of interest in the application of CCS to cement production has increased but there is still relatively little practical development work being carried out. The main objective of this study is to review greenhouse gas emissions in the cement industry and provide a survey of the state of development and barriers to the deployment of CCS in this industry.

This study was undertaken for IEAGHG by the European Cement Research Academy (ECRA) in Germany, at the request of and with financial support from the Global CCS Institute (GCCSI).

1 CO2 capture in the cement industry, IEAGHG report 2008/3, July 2008.

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Scope of Work

The study focuses on the following tasks:

1. Review current practice in energy efficiency improvement and fuel and clinker substitution practices in relation to reduction of CO2 emissions in the cement sector.

2. Engage with key stakeholders with the aim of identifying the key barriers to the demonstration of CCS in the cement sector.

3. Review the current state of development of potential CCS technologies evaluated for the cement industry, particularly oxyfuel and post-combustion capture and review current CCS activities initiated and led by the cement industry.

4. Review policy and government initiatives to support the application of CCS to the cement sector.


State-of-the-art practice towards CO2 reduction in the cement industry

Cement is a blend consisting mainly of ‘clinker’, along with various additives. In the state of the art clinker production process shown in Figure 1 raw meal consisting mainly of carbonate mineral, usually limestone, is pre-heated against hot flue gas in a series of cyclone preheaters. It is then fed to a precalciner when it is heated with fuel, resulting in the decomposition of most of the carbonate into calcium oxide and CO2. The solid product from the precalciner is then fed to a rotary kiln where it is further heated by combustion of fuel and the calcium oxide reacts with silica and other minerals to produce the clinker product. The clinker is cooled, fed to a grinder and blended with other additives to produce cement.

Raw meal

Cyclonepreheater

Flue gas

Precalciner

Tertiary air duct

Cooler exhaust gas

Fuel/air

Fuel

CoolerCooling air

Rotary kiln

Clinker

Figure 1 Cement clinker production plant

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More than half of the CO2 emissions from cement production are ‘process related’, i.e. from decomposition of carbonate mineral, and the rest are from fuel combustion. Apart from CCS, the main practices that can be used by the cement industry to reduce CO2 emissions are:

• Increased energy efficiency

• Utilisation of alternative fuels

• Application of alternative raw materials

• A lower clinker:cement ratio

Increased energy efficiency

Just 64 % of the world’s cement production is delivered by facilities which are equipped with precalciner technology and are working as described as state of the art practice. While a large number of cement plants with up-to-date technologies have been built in the last two decades, mainly in emerging countries, there is still a significant number of shaft, wet and semi-dry kilns as well as obsolescent grinding equipment in operation worldwide. Therefore, technical optimization of production processes offers a certain but limited improvement potential with respect to the energy demand.

In 2010 the thermal energy demand for cement clinker production was 3,580 MJ/t clinker2 and the worldwide average electric energy demand for cement manufacturing was 108 kWh/t cement. According to ECRA’s assessment the specific fuel demand can be reduced to a level of 3,300 to 3,400 MJ/t clinker in 2030 and to 3,200 to 3,300 MJ/t clinker in 2050, i.e. around a 10% reduction by 2050. A fundamental change in the actual cement production technologies causing a significant reduction in the specific energy consumption is unlikely.

Utilisation of alternative fuels

Utilisation of alternative fuels, mainly derived from waste streams such as waste oil, tyres, plastics, mixed industrial waste, animal meal, sewage sludge, wood waste and grain rejects can reduce net CO2 emissions due to their lower carbon content as well as their biogenic fraction. The overall CO2 emissions of a cement kiln plant are not necessarily decreased and the thermal energy demand of the process may rise but biomass is carbon neutral when part of an ecological cycle with photosynthesis and recycle via combustion. Measures such as oxygen enrichment and gasification could partly compensate for the increased thermal energy demand but at the expense of higher electrical energy demand. In general, a lot of know-how is required in order to adapt the process to the differing properties of alternative fuels. This know-how exists in some world regions or companies but it is lacking in others. The importance of alternative fuels is growing globally due to other environmental advantages and positive economics. There are some investment costs, mainly for storage and handling and in some cases pretreatment but operational costs are lower due to lower prices of alternative waste fuels compared to regular fuels such as coal. In summary, the application of alternative fuels and other fuel switching offers the potential to contribute to the target CO2 reduction requirement in 2050 by 24 % compared to the base case.

Application of alternative raw materials

The application of alternative raw materials can help towards the limitation of the process related as well as fuel related CO2 emissions. CO2 emissions can be reduced by using decarbonated materials because the CO2 emissions have already been charged to the earlier processes that created them. Examples of alternative materials are wastes from recycled concrete or fibre cements and other

2 Worldwide weighted average, according to the World Business Council for Sustainable Development.

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materials such as blast furnace slag and fly ash. The limitations to this technique are mainly the availability of the alternative materials and the need to correct the composition of the raw material mixture to maintain product quality and kiln operation, which is only possible to a certain extent. Due to the limited availability of these materials, it is more reasonable to use them as clinker substitute in the cement because this enables higher emissions reduction potentials to be achieved.

A lower clinker:cement ratio

Cement is a blend of clinker, i.e. the material produced by a cement kiln, and other additives. A lower clinker-to-cement-ratio results in less energy demand for clinker production as well as less process CO2 emissions due to the decarbonation of the limestone. The most important clinker replacing constituents are fly ash, slag, limestone and pozzolanas (a type of mineral of volcanic origin). It has to be taken into account, that the blended cements may have different or even limited cement properties compared to Ordinary Portland Cement but the greatest limitation is the availability of most of these materials.

Besides the approach to reduce the process CO2 emissions by the reduction of the clinker content in cement or low-carbonate clinker, new binding materials as alternatives to cement, such as Celitement, Novacem or Calera are being investigated. However, these technologies are still at research or pilot scale. To what extent these materials could replace cement as binder in building materials is not currently foreseeable.

All of the techniques described above can contribute to a reduction of combustion and material related CO2 emissions to a certain limited degree but the calculated potentials could not be simply added, as some of them counteract each other. Moreover some measures which enhance thermal energy efficiency require increased electrical energy demand and related indirect CO2 emissions.

Nevertheless a simulated “blue map scenario” by IEA showed that 44 % of the target CO2 reduction potential in the cement industry related to the base scenario in 2050 could be achieved by the conventional methods described above. This shows the prospects these methods still have but also the limits of the emission reduction potential.

Research and CCS activities in the cement industry

The preferred technologies for CO2 capture in the cement industry are oxyfuel and post combustion capture. Pre-combustion capture is at a disadvantage because it would not capture the CO2 produced by mineral decomposition.

Post combustion capture

Post-combustion capture technology has been the subject of research and has already been proven in some industries. Although part of this experience could be transferred to application in the cement industry, some issues especially concerning the cement plant’s flue gas composition and impurities still need to be proven at pilot scale.

Research activities that are currently on-going in the field of post-combustion capture include chemical absorption, adsorption, membrane, mineralization and calcium looping technologies. The most investigated technology is chemical absorption but this faces the challenge of a high energy demand. Developments in calcium looping or membrane processes may have the potential to increase the overall energy efficiency but further research and development is needed. There would be some synergies between calcium looping and a cement plant because the purge stream of de-activated calcium sorbent could be reused as raw material in the cement clinker production process.

Pilot and demonstration plant projects which are actively proceeding include:

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Norcem, Brevik, Norway: Test centre offering the possibility to conduct several small scale or pilot trials of post combustion capture using cement plant flue gas (2013-2017). Companies involved in this project include Aker Solutions (amine scrubbing), RTI (dry adsorption with specialized polymers), KEMA, Yodfat and NTNU (membranes) and Alstom (calcium looing).

ITRI/Taiwan Cement Corp.: Pilot plant capturing 1 tonne CO2/h from a cement plant and a power plant using a calcium looping process, commissioned June 2013.

Skyonic Corp.: Plant under construction, capable of capturing 83,000t CO2/y from a cement plant in Texas, using the “SkyMine” process. In this process salt and water are electrolyzed to produce hydrogen and chlorine gases and sodium hydroxide solution, which is reacted with CO2 in flue gas to produce sodium bicarbonate, which can be sold on the market. Other combinations of chemicals can also be produced.

Due to the already high level of knowledge, the technology of post-combustion capture has the potential for implementation in a relatively short timescale, but not before 2020 for full scale plants.

Oxyfuel

Unlike post combustion capture, oxyfuel technology requires adaptation of the cement clinker production process. Oxyfuel technology for cement production is still at the basic research and laboratory testing state of development. Detailed research is still needed before advancing to pilot-scale, which is the next logical step but currently no pilot plants are planned or initiated. As a pre-stage, ECRA is presently preparing a concept study for an oxyfuel pilot cement kiln. The time horizon for application of oxyfuel technology at several full size cements plants is expected to be not before 2025.

Hybrid technologies

Hybrid technologies in terms of a combination of oxygen enrichment and post-combustion technologies have not been actively investigated. The benefit of those combinations depends on several factors concerning the energy demand, which interact with each other. Therefore it is not possible at present to make reliable statements on technical and economic barriers and potentials.

Stakeholders’ opinion on CCS

Cement industry stakeholders were surveyed by way of a questionnaire to determine their awareness, activities, interests and reservations about CCS.

Figure 2 shows the characterization of the participating stakeholders. The main feedback was given by companies from Europe, Middle East, Asia and North America. The greatest number of participants were cement producers but plant manufacturers, gas suppliers, technology providers and research centres also provided feedback. Approximately half of the companies are global players with international businesses. In summary the composition of the responding companies delivers a representative overview of the industry’s view on CCS technologies.

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Company size

Global playerMedium sizeSmall size

Business

NationalInternational

Location

EuropeMiddle EastAsiaNorth America

Type of business

ProductionResearch

ProductCementmanufacturerPlantmanufacturerGas supplier

TechnologyproviderOthers

Figure 2 Companies responding to the stakeholder survey

Evaluation of the questionnaire showed the following main results:

- Most repondents are aware of CCS technologies but the knowledge about CCS and the activities in this field is lower in the Middle East and Asia than in Europe.

- Approximately three quarter of the responding companies feel CCS is a relevant issue or an issue which will become relevant for them. Especially medium or smaller sized cement producers and plant manufacturer think that CCS is not relevant for them at this stage of development. Uncertainties about the technical feasibility and the avoidance of economic risk make them prefer tradional methods for CO2 reduction.

- Nearly half the respondents, especially from Europe, are involved in CCS activities, mainly as part of a consortium with or without financial contribution. Most of the companies are at least aware of these research projects.

- Nearly 90 % of respondents think that these technologies have potential in the cement industry and would apply them, if they were available. The negating companies are those which are convinced of other technologies or too alienated by the uncertainties of the technical feasiblity

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(including medium sized companies and plant manufacturers). Also some companies are not aware of capture technologies but they would apply them, if they became state of the art.

- More than half of the interviewees would contribute financially to research but only about a third would contribute to a pilot or demonstration plant due to high costs. The willingness to financially contribute to research or especially to pilot or demo plants is higher in globally acting companies.

- Alternatives to CCS for CO2 reduction are seen in about 40 % of respondents and some 10 % are uncertain about the development of other technologies for emission control.

Technical and economic performance

The study evaluated the technical and economic performance and barriers to application of oxyfuel technology and post-combustion capture using chemical solvent absorption in cement plants.

Technical issues relating to the use of chemical solvent absorption for post combustion capture in cement plants are largely the same as for power plants. These include the possible need for secondary treatment to reduce the quantities of impurities such as SOx, NOx, particulates and other trace materials in the flue gas to avoid excessive degradation of the solvent and the need for disposal of degraded solvent waste. Space and HSE requirements may also constitute a constraint at some plants. The solvent reboiler consumes a large amount of energy and as there is only sufficient waste heat in a cement plant to provide about 15 % of this energy demand, an additional combined heat and power (CHP) plant is needed. The CO2 emissions from the CHP plant can be captured along with those from the cement plant. Two CHP options were considered in this study: a coal fired boiler plant and a natural gas combined cycle (NGCC) plant. The optimum choice will depend on local conditions and fuel prices.

Oxyfuel technology can be integrated in the clinker production process using two different concepts – full or partial oxyfuel. In the partial oxyfuel concept, oxygen is used only in the pre-calciner and the rotary kiln remains air-fired. In the full oxyfuel concept oxygen is used in both the precalciner and the kiln. Both concepts seem likely to be suitable for retrofitting existing plants, although the plant specific space availability in the structure may limit the construction. As integrated systems, both concepts influence the process and the material conversion and greater effort will be required for operating and controlling the plant. Enhanced HSE measures will be required for handling high purity oxygen and carbon dioxide. While the thermal energy demand is only affected to a small extent, the electrical energy demand is doubled per tonne of cement product.

Figure 3 compares the Total Plant Costs (i.e. excluding owner’s costs, interest during construction and start-up) of a reference plant without CO2 capture and various plants with capture. The costs are for European plants producing 1Mt/y of clinker (1.36Mt/y of cement). The costs of the plants with post combustion capture are higher particularly because of the need to build a combined heat and power plant to supply steam for regeneration of the capture solvent. It should be noted that the capture rate in the partial oxyfuel case is about 60% compared to 90% in the other cases.

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Figure 3 Comparison of Total Plant Costs

Figure 4 compares costs of cement production. The costs are based on coal and gas costs of 3 and 6 €/GJ respectively, an 8% discount rate, a 25 year plant life, an 80% annual capacity factor and an electricity value of €80/MWh, which is an approximate average of the costs of power generation with CCS in coal and gas fired power plants in recent IEAGHG studies. Details of other technical and economic assumptions used for these cost estimates are included in the study report.

The cement production cost is increased by 68-105% when applying post combustion capture and 36 to 42% when applying oxyfuel technology. In the case of the oxyfuel technologies this cost increase is mainly driven by the additional electricity demand, whereas the main costs for post-combustion capture are both additional electrical and fuel energy demand as well as the at least doubled investment cost. It should be noted that costs are subject to significant uncertainty and will depend on various factors including site specific conditions, fuel prices and future technology developments. These costs exclude CO2 transport and storage costs. Cement plants are normally located close to the source of limestone and have relatively small CO2 outputs compared to power plants, which would tend to increase CO2 transport and storage costs. However, if the plant was close to other sources of captured CO2, a larger trunk pipeline could be used which would reduce costs. As an illustration of the impact of transport and storage costs, a cost of €10/t CO2 stored would increase the cost of cement production by about €5/t for the full oxy-fuel case.

Figure 4 Comparison of cement production costs

The cost of avoiding CO2 emissions depends on the definition of the quantity of emissions avoided. Different definitions could be used for cement plants with CCS:

• The direct emissions avoided at the cement plant site;

• The direct emissions plus the indirect emissions from power plants at other sites.

Oxy-fuel cements plants import electricity generated at other power plants, mainly for oxygen production and CO2 compression. If this electricity is generated at power plants which emit CO2, these ‘indirect emissions’ reduce the quantity of emissions avoided by CCS at a cement plant. In contrast, plants with post combustion capture would normally require an on-site CHP plant to provide the low pressure steam for CO2 capture solvent regeneration. The CHP plant would generate some electricity from passing high pressure steam through a back-pressure turbine and, in the case of an NGCC, from a gas turbine. This electricity is usually sufficient to provide all of the needs of the capture plant and there is a surplus, which displaces power that would otherwise be generated in external power plants. Including indirect emissions therefore increases the quantity of emissions avoided for cement plants with post combustion capture.

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The cement industry’s preferred definition of the quantity of CO2 emissions avoided is the ‘direct’ emissions, because those are the emissions which a cement plant operator would be accountable for, and for which they would have to pay CO2 taxes or purchase emission credits.

The quantity of indirect emissions depends on the specific CO2 emissions of the electricity system. At the time when CCS is installed on a large scale at cement plants, electricity generation may already be mostly decarbonised, in which case the ‘indirect’ emissions would be small.

Direct costs of CO2 emission avoidance compared to the reference plant, excluding costs of CO2 transport and storage, are shown in Figure 5. Including indirect emissions, assuming the same electricity value and specific emissions of 600 kg CO2/MWh, would decrease the cost of emissions avoidance of post combustion capture by 9-14 €/t and increase the cost of oxyfuel by 4-6 €/t CO2.

Figure 5 Comparison of CO2 avoidance cost

The full oxyfuel technology shows the lowest cost of CO2 avoidance. Regarding post-combustion capture, the combination with an NGCC CHP plant is less costly than a coal fired CHP plant, but this depends strongly on the relative prices of coal and gas.

Other studies have shown that a symbiosis of a cement plant with power plants and a joint CO2 capture plant (carbonate looping) could reduce the specific costs of post combustion capture.

Sensitivities to various technical and economic criteria were assessed in the study. In particular, because global cement production is concentrated in less developed countries, the sensitivities of costs to two non-European locations, China and the Middle East, were assessed. CO2 avoidance costs in these regions were estimated to be around 50% lower than in Europe.

Barriers to CCS in the cement industry

The overall investment costs and the operational costs are seen as a high barrier to initiate even the first steps towards pilot and demonstration plants. Any time frame for either of the technologies will therefore to a high degree depend on substantial funding. Specific funding for carbon capture demonstration and research in the cement industry is not available.

From today’s perspective, with respect to the current legal and economic conditions CCS technologies would impair competiveness of cement production. Some nations or groups of countries have put a price on CO2 emissions (via cap-and-trade or tax) to stimulate investments in emission reduction methods such as CCS. Since the costs for CCS and the corresponding CO2 price are high as a proportion of the cement production cost there is always a significant risk that clinker and/or cement will be imported from countries with lower abatement costs, with the corresponding carbon leakage. This must be taken into account in designing the appropriate legal framework for CO2 abatement by means of CCS in the cement industry.

Further generic barriers to CCS are the lack of an adequate overall legal framework for CO2 storage and inadequate storage capacities in some countries.

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In conclusion there seems to be little incentive to undertake the high effort to build a CCS installation without a dedicated political approach which addresses the risk of carbon leakage and a clear perspective towards reliable storage options.


Comments on the draft report were received from seven reviewers in the cement industry and research and energy policy organisations.

A general view of the reviewers was that the report provided a good contribution to knowledge in the subject area. Key suggestions included a request for more information on the economic analysis and more detailed and up to date information on calcium looping, which were addressed in the main study report, along with various other detailed comments. The length of time required for commercial demonstration was questioned by some reviewers and consequently discussion of this issue was expanded.

Conclusions

Established techniques can be used to reduce CO2 emissions from cement production, including increased energy efficiency, use of alternative raw materials and fuels and reducing the clinker:cement ratio but these techniques are already being used to a significant extent. The scope to further reduce emissions using these techniques is therefore limited.

A survey of the cement industry, including cement producers, equipment suppliers and others has shown that most of the respondents think that CCS is relevant to them and they are aware of research projects, and half are involved in CCS activities, mainly as part of a consortium. More than half would contribute financially to research but only a third would be willing to contribute to pilot or demonstration plants due to high costs.

The preferred techniques for capturing CO2 in cement plants are oxyfuel and post combustion capture. Post combustion capture is considered to have the potential for application in a shorter timescale because of relevant experience in the power sector but tests at cement plants will still be needed to determine the effects of the different flue gas compositions. Some pilot plant projects using various technologies are underway. Oxyfuel technology is still at the laboratory stage of development and there are currently no firm plans for pilot and demonstration plants.

This study indicates that oxyfuel technology will have a lower energy consumption and costs than post combustion capture using liquid solvent scrubbing. However, costs of CCS at cement plants still have relatively high uncertainties due to the absence of real plant data and site specific factors, in particular the various options for supply of steam for post combustion solvent scrubbing. Also, new technologies may in future reduce the costs and energy consumptions of CO2 capture at cement plants.

The current globally unequal cost of emitting CO2 would impair the competiveness of cement production with CCS. There is a significant risk of import of cement or clinker from countries with lower abatement costs, with corresponding carbon leakage. Underdeveloped legal frameworks for CO2 storage in some countries are a further constraint on the development and application of CCS technologies in the cement sector.

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Recommendations

It is recommended that IEAGHG should continue to maintain a watching brief on CCS in the cement industry as part of its portfolio of activities on CCS in sectors other than power generation.

A further techno-economic assessment of oxyfuel technology, conventional post combustion capture and next generation capture technologies including calcium looping and membranes should be undertaken when or if sufficient information becomes available from operation of the cement industry pilot plant projects described in this report. This study could also include a more detailed assessment of options for providing the additional energy for post-combustion solvent regeneration, either by an additional power source on-site (coal or NGCC CHP) or in combination with a nearby power plant (cluster arrangement).

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COMPARING DIFFERENT APPROACHES TO MANAGING CO2 STORAGE RESOURCES IN MATURE CCS FUTURES

(IEA/CON/13/212)

This study was undertaken by the British Geological Survey (BGS). It was funded by the Global CCS Institute.

The work was completed by Jonathan Pearce (BGS), Michelle Bentham (BGS), KL Kirk (BGS), Robert Pegler (BBB Energy Pty Ltd), G Remmelts (TNO), Serge van Gessel (TNO), K Young (Alberta Energy) and Sue Hovorka (University of Texas).

The draft report was peer reviewed in November 2013 and the comments adopted in the final report. The Overview was sent to members for review in February 2014 and the final report published in March as IEAGHG 2014/01.

The following paper presents the final Overview of the study.

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COMPARING DIFFERENT APPROACHES TO MANAGING CO2 STORAGE RESOURCES IN MATURE CCS FUTURES

Key Messages

There are many potential competing users of the surface and subsurface in both onshore and offshore environments

There are various different approaches to storage management, all of which are highly dependent on the jurisdiction involved

Most jurisdictions currently work under a ‘first-come, first-served’ approach Management of storage on a first-come, first-served basis is likely to be sustainable in the

short to medium term Pressure increases do not always result in detrimental effects, but pressure responses in open

storage sites should be the focus of a detailed assessment in all cases The operator and regulator must understand the consequences of a pressure increase over an

area much larger than the extent of the CO2 plume itself The main benefit of a first-come, first-served approach is that the operator has the final

decision on where to develop CO2 storage The first-come, first-served approach should work for multiple-stacked sites Potential disadvantages of the first-come, first-served approach include possible reduced

storage capacities, difficulties for monitoring and a lack of regional storage optimisation with stranded sources.

Background to the Study

Current regulations concerned with carbon dioxide capture and storage (CCS) mean that the licensing of CO2 storage sites is likely to be undertaken to follow a first-come, first-served basis. Applications for licences (for individual projects) are submitted to regulators and the basis of the regulators’ assessment will be primarily to consider if the site is fit for purpose as a storage site for CO2. This assessment will be subject to certain region-specific exclusions, designed to protect the interests of pre-existing users of the subsurface, ground surface and seabed.

Storage sites for CO2 will be selected by the operators on a ‘most economically advantageous’ basis, to meet the needs of individual clusters of CCS projects. A recent (2013) IEAGHG study, ‘Interaction of CO2 storage with subsurface resources’, highlighted that sedimentary basins have multiple potential uses – hence there is potential for CO2 storage projects to conflict with other subsurface and surface users (see figure 1, overleaf, for a conceptual view of spatial and subsurface interactions which may limit storage site selection). This report showed that increased pore fluid pressure in any reservoir formation (resulting from the injection of CO2) may reduce storage capacity and increase costs in adjacent sites, which could potentially reduce the efficient use of the storage resource. Therefore a more strategic approach would be required when dealing with sedimentary basins to ensure such formations realise their full resource potential. This raises important questions, including:

How can CO2 storage capacity be fully utilised in the presence of potentially competing uses of the subsurface and overlying ground surface or seabed?

How should storage boundaries be defined in potentially pressure-interacting projects? How should potentially interacting resources e.g. CO2 storage, hydrocarbon exploration

and production and natural gas storage be developed most economically in the light of national or jurisdictional policies?

Factors which may influence the optimisation of a basin include cost, minimising risk, access to a range of uses of the basin, ground surface and seabed, and the value of the resource. Such factors

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would be considered within the framework of government energy policies. It may also be necessary to look at other, perhaps less tangible potential future uses of the basin.

FIGURE 1. Conceptual view of spatial and subsurface interactions which might limit storage site selection, using a hypothetical example of gas fields and two storage site scenarios in the UK Southern

North Sea

Scope of Work

This report develops scenarios for CO2 storage development in the Southern North Sea Basin to compare first-come, first-served and managed approaches to CO2 storage site licensing. The report describes the benefits and consequences of these broad strategies for the pore space owner and the operator, and considers current approached to managing offshore and onshore storage resources (in a range of jurisdictions).

A workshop was held in the early stages of the report process, which helped to evaluate approaches to the management of pore space in different jurisdictions. The following general issues were discussed at the workshop and are looked at further in the report:

- The availability of storage capacity - Other uses and users of the pore space - Priorities on different uses in different jurisdictions - Potential routes to wider storage deployment - Technical regulatory challenges for storage in areas of multiple stacked storage opportunities - Risks that may arise from site interactions - Examples of pore space conflict resolution - Strategic initiatives for storage deployment.

The report details potential subsurface interactions, UK policy for CO2 storage development (including a UK Southern North Sea case study), potential interactions between two case studies in

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the Southern North Sea, CO2 storage permitting in the Netherlands, CO2 storage in Australia, the role of CO2 enhanced oil recovery (EOR) in Texas, USA and managing the pore space in Alberta, Canada.


Pressure as a result of CO2 injection

Subsurface interactions may occur when a storage project operates within a geological formation and such interactions are well-documented. The most significant potential interactions are likely to be the pressure effects of CO2 injection and the associated brine displacement. This reservoir pressure increase is a prime risk to other resources (including other storage sites) which are in pressure communication. Figure 2 shows a simulation of the relationship between CO2 plume extent and the extent of the pressure rise from this injection.

FIGURE 2. A TOUGH2 simulation showing the relationship between CO2 plume extent and pressure rise, over a 50 year period.

UK Policy and Regulation for Storage Development

The UK has several strategies and policies to reduce greenhouse gas emissions, including a legally binding target to reduce emissions by at least 80% below base year levels by 2050. The 2012 CCS Roadmap notes that; the UK has extensive storage capacity in the North Sea and clusters of power stations/industrial plants – which could share knowledge and infrastructure to develop CO2 storage. The Department for Energy and Climate Change (DECC) has recognised the potential for CCS clusters to develop across several regions and their storage strategy identifies the challenge of future storage deployment, included the scale of possible future storage needed. The storage roadmap sets out specific activities that the UK government will focus on in these efforts and other activities (by organisations like the Crown Estate and the Storage Cost Reduction Task Force) will support such efforts. The UK government have undertaken several significant activities for storage research and demonstration (R&D) including a commercialisation competition and a coordinated research, development and innovation programme.

The UK Southern North Sea has a vast amount of storage potential, including in gas fields (the majority of which occur within the Rotliegend Leman Sandstone formation) and saline aquifers (including the Bunter Sandstone, thought to have the best potential for aquifer storage, with good pressure communication across the reservoir).

UK Southern North Sea Case Study

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The report undertakes a UK-specific case study to illustrate the range of potential users/ conflicts which could be anticipated as more storage sites are developed. The main classes of potential CO2 storage sites used are saline water-bearing domes in the Bunter Sandstone formation; gas fields in the Bunter Sandstone; gas fields in the Leman Sandstone; and gas fields in carboniferous limestones. Potential users or conflicts identified include hydrocarbon operations, gas storage and other CCS sites (all subsurface users), and wind farms, dredging areas, pipelines, other operators, environmental protection areas and shipping routes (surface users). Scenarios were developed (first-come, first-served (FCFS) and managed storage resource) to run from 2020 to 2050, to illustrate the interactions that may occur as a result of CO2 injection.

Two potential storage sites were chosen to undergo the scenario simulations, with assumptions made that all storage capacity could be used and no pressure management wells are used. No cost assessment was carried out, so differences will arise due to varying site characterisation and commissioning costs. Even in areas with large potential storage resources, surface and subsurface interactions may arise – and early projects will benefit from being able to choose the best sites for a minimal chance of interactions, and the likelihood of interactions will increase as the number of storage sites increase. The managed storage resource scenario demonstrates that CCS could face competition from other nearby CCS projects, wind farms, gas storage sites and hydrocarbon production operations; however it is likely that the development of both options could occur as demand for storage capacity increases, for reasons explained in the report. For example, offshore wind farms could present a physical barrier to accessing any potential storage sites in terms of laying down infrastructure and monitoring above a site, including the safety zones that may be imposed around turbines.

Underground Storage Permitting for CO2 in the Netherlands

The implementation of CCS in the Netherlands is being driven not only by climate change concerns, but also by potential economic benefits of being a front-runner in this technology. There are many R&D efforts underway in the Netherlands, and the national government works along an organisational model of a privately run CCS market (where the initiative for action comes from the emitting operators themselves) and the government’s role is one of a supervisor. It is interesting to note that the ‘Inpassingsplan’ (July 2008) under the Spatial Planning Act gives the Dutch government the right to adapt spatial planning by district/local governments in the circumstance of projects of national importance. At present, this country is in the start-up phase of large-scale demonstration projects, aiming to store around 1 MT per year. The Dutch subsurface contains numerous gas fields and the policy of government is aimed at the use of depleted gas fields as CO2 storage facilities. Figures 3 and 4, below, show the theoretical storage capacity in the Netherlands.

FIGURE 3. Available theoretical offshore CO2 storage capacity based on expected end of field

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1000

900

800

700

600

500

400

300

200

100

02010 2014 2018 2022 2026 2030 2034 2038 2042 2046 2050

CO

2(M

ton)

FIGURE 4. Development of cumulative theoretical onshore storage capacity in northern Netherlands versus the base case scenario and the green scenario for CO2

There is the potential for competition within the surface and subsurface in the Netherlands, identified in the report. Using existing infrastructure is much more favourable than drilling new wells, but additional issues at the surface may arise, including land use conflicts, potential ground movements and induced seismicity. Public acceptance is likely the biggest barrier to CO2 storage in the Netherlands and for this reason, at this stage it is only being considered offshore. In the subsurface, most competition between users would arise in an onshore environment, where the storage of CO2 may prevent gas fields from being used for other storage (e.g. potential UGS sites), but UGS only puts a temporary claim on the rights. Other potential competition may arise from nearby geothermal producer and injector pairs, or salt production activities from layers directly above the storage reservoir. A key potential offshore conflict includes the issue of connectivity and pressure communication with adjacent fields under development or production.

Australia

In Australia, different jurisdictions follow different approaches to the design of CCS regulatory frameworks. The majority of Australia’s storage potential is located offshore (with the most potential residing in North West Western Australia), but ‘areas assessed to have greatest storage potential are not well-aligned with key electricity demand/load centres’. There is a limited scope for CO2 storage in depleted oil and gas fields, as the majority remain in production (and will do for many years) and high recovery rates mean there is little potential for CO2 EOR.

When discussing potential users and conflicts, it must be noted (as in all locations) that this will be highly site-specific. Offshore conflicts in Australia could include issues with other users, such as fisheries, shipping routes, infrastructure etc., but the greatest potential conflict is with the petroleum industry itself, who is concerned about compromising production. Onshore conflicts may arise from similar users as offshore, but one must consider additional uses such as agriculture. The subsurface issues raise the most concern. Groundwater impacts (an important community-wide issue) are a huge potential conflict, as are the usage conflicts with coal bead methane (CBM) operations – there is a strong coincidence between the CBM resource and potential CO2 storage sites.

The Australian government have adapted a range of onshore and offshore specific policy and regulatory responses to address storage management. Offshore CO2 storage is primarily governed by provisions of the government’s ‘Offshore Petroleum & Greenhouse Gas Storage Act 2006’ and its associated regulations. This Act provides for clear security of title for CO2 operators and also clarifies

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long term liability issues. The government has also developed detailed guidelines to help CO2 titleholders and there are clear legislative distinctions between the petroleum industry requirements and those for other users. It is interesting to note that the approach only considers that the projected stored plume must be contained within the injection licence title, but does not consider the potential extent of the pressure front. State governments are active in working to facilitate the onshore storage of CO2; Victoria, Queensland and South Australia have all enacted legislation. New South Wales and Western Australia have legislation currently under consideration. The regulatory and policy regimes adopted by state governments have addressed the issues of overlapping tenure and competing/conflicting use in detail.

The Role of CO2 EOR in Texas, USA

The ‘management of CO2 storage and EOR in the same footprint is generally beneficial to both processes’, perhaps why a large amount of recent work has looked further into CO2 EOR. Pressure elevation (see figure 5, overleaf, for a diagram of increased pressure when closely spaced injector and producer wells are used to ‘force seep’ the residual oil) is a benefit to a connected EOR reservoir (but a risk factor for CO2 storage), and EOR may assist in the management of pressure in the storage area. Another benefit is that in EOR-rich areas, there will be a wealth of data which could be used in site characterisation and pre-existing infrastructure, which could be used by other projects.

FIGURE 5. Sketch comparing the area of the CO2 plume and significantly elevated pressure at deep saline injection with an EOR flood, showing the role on injection and production well patterns in

managing and monitoring the flood

CO2 EOR has a fairly high success rate, but despite the strong technical background with this technology, it is often not economically viable (i.e. the availability of CO2, capital to construct a delivery pipeline, available financing etc.) and there is competition with other technologies, although there is uncertainty about the extent to which the sale of CO2 could offset capture costs (the sale of CO2 could lower this barrier for CCS projects). Other limits of CO2 EOR may be the nature of recycle; greenhouse gas emissions generated by compression and pressure lifting; well integrity; oil production; and size of the EOR market.

It was recognised that in most cases, the majority of storage capacity is stacked, overlapping and sometimes dynamically connected. There is great potential for CO2 EOR in such vertically stacked, multiple systems (stacked depleted oil and gas fields and deep saline aquifers) and in such systems, monitoring programmes could be integrated. However, projects undertaking this must be mindful of different risks/uncertainties needed to be considered for the different processes taking place. Potential issues with the joint use of EOR and CO2 storage could be that there may be documentation and

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investment in retention, subsurface trespass issues for EOR; and managing conflicts between the EOR and CO2 storage technologies and processes.

Managing the Pore Space in Alberta, Canada

Alberta’s 2008 Climate Change Strategy recognised CCS as a key mitigation technology to address greenhouse gas emissions and in 2009, the Carbon Capture and Storage Act was created to encourage the development of CCS projects in the province.

There are various activities and legislations to enable CCS and the storage of CO2. The Alberta government assumed long-term liability (a significant uncertainty for CCS) for a storage site once a closure certificate has been issued, thus improving the ability for operators to plan/execute and ensuring the protection of the public. Steps have already been taken by the government to manage the positive and negative interactions between CCS and hydrocarbon resources – it is explicitly mandated in legislation that ‘CCS projects will not interfere with or negatively impact oil and gas projects in the province’. The ‘pore space tenure’ process is the primary process to ensure that CCS development will not negatively impact the hydrocarbon industry in any way. Where there is high demand for pore space tenure in an area where pore space tenure has already been allocated, the government has to introduce policy and regulations to incentivise operators to allow access to their pore space for the storage of CO2. There are currently no regulations for this but portions of some Acts allow for the transfer of tenure and for Alberta, it is clear that ‘market considerations should be a primary driver behind third part access to sequestration tenure and CO2 injection’. The Albertan energy regulator has a well-developed process for evaluating and managing subsurface resource interaction, another process to encourage development in CCS.


The study was sent out for a peer review, and detailed comments were received from five expert reviewers in total. The reviewers were overall, very impressed with this study, and many felt that this report will be a valuable resource for operators, regulators and academics.

A few general comments on grammar were received and acted upon throughout the study, and suggestions to rephrase some sentences at various points throughout the report were taken into account, to minimise the chance of misunderstanding of the text by the reader. Specifics and further detail was added to various explanations of terms to ensure proper explanation of certain technological aspects, and further site-specific information has been added where requested and necessary. Several updated references and an updated figure were added as per the request of one reviewer.

Some suggestions were made to add information on the economics of the management scenarios, but this was considered out of scope for the study and therefore no action was taken. It was suggested that more detail and analysis should be added to the various case studies – unfortunately due to time constraints this wasn’t able to be done, but is potentially a path for future research.

The final report reflects the comments of IEAGHG and the expert reviewers. The contractors have provided a detailed tabulated summary of the comments received and their actions taken to address these comments, which can be made available to interested parties.

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Conclusions & Recommendations

There are many potential competing users of the surface and subsurface in onshore and offshore environments, and this study has demonstrated the potential for interactions between the possibly multiple pore space users.

There are various different approaches to storage management, which are highly dependent on the jurisdiction involved. All jurisdictions looked at in this report manage their pore space on a first-come, first-served (FCFS) basis, in which operators will be able to identify their preferred CO2 storage site. The operators’ decision on the preferred site will be based on their specific geological, technical and financial criteria.

Management of storage on this FCFS basis is likely to be sustainable in the short to medium term – especially in areas with abundant storage potential. There will, however, be competition for the pore space in all regions; an issue likely to become more pronounced as CCS develops and matures. In some jurisdictions there is already a determined hierarchy of uses or constraints but it must be noted that in some countries onshore storage is not considered due to public acceptance issues. Because of this, planning frameworks have already been developed to some extent in many countries considering the deployment of CCS.

Scale and impacts of subsurface interactions during CO2 storage

The main interaction that must be evaluated is the area, amount, rate and maximum reservoir pressure the storage formation will experience. The consequences of the increase in pressure with injection will vary site to site, depending on the characteristics of the area, the areas past history and other uses in the area – specifically the types of use and proximity to these uses. Pressure increases do not always result in detrimental effects, but pressure responses in open storage sites should be the focus of a detailed assessment in every potential CO2 storage case.

The scale and impact of a pressure rise will be site-specific. Although many simulations of CO2 injection into saline aquifers show a pressure response will occur through the connected pore volume, these simulations are often simplified representations of various factors (such as the local geology) and therefore aren’t always accurate.

The maximum pressures are experienced around injection wells and this dissipates (with distance) toward the formation boundaries of the connected pore volume. Permeability baffles will limit the amount and extent of the pressure footprint. Simulations suggest that after injection, pressures often dissipate quickly, hence the highest pressures will be observed during injection operations. A number of pressure management strategies are available and may be required to optimise the storage efficiency of a site (whilst maintaining pressures below a defined threshold).

Approaches to strategic management of the storage resource

It is crucial for the operator and regulator to understand the consequences of a pressure increase over an area much larger than the extent of the CO2 plume itself. It makes sense that an overview of the region (including future uses of the subsurface) is the responsibility of the relevant authority. The operator should be responsible for simulating the extent of the pressure footprint and the regulator for assessing the validity of this modelling.

Pressure increases resulting from CO2 injection/storage are likely to become an issue when there are multiple CO2 storage sites within a connected geological formation, injecting at the same time. The combined pressure response will limit the total capacity of the sites. This will decrease the injectivity and increase the need for pressure relief in the formation.

The main benefit of a FCFS approach is that the operator has the final decision on where to develop CO2 storage, and the approach should work for multiple-stacked sites. Potential drawbacks of this approach include possible reduced storage capacities (in adjacent future storage sites), difficulties for

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monitoring and a lack of regional storage optimisation. In addition, the FCFS methodology may not lead to a pathway of overall least cost development for storage. To avoid or reduce potential negative interactions, some strategy management is likely to be necessary in most regions.

This study by BGS, on behalf of IEAGHG and GCCSI, looked into scenarios for storage development; the development of clusters; knowledge requirements; defining lease areas; and resolving conflicts.

Knowledge, experience and research gaps

Developing strategic plans for efficient storage use

Consequences of a rise in pressure within a CO2 storage formation will be very site-specific. In the past, such recognised consequences have been specifically focussed on the geomechanical responses in the reservoir. However, the impacts of pressure increase in non-reservoir rocks should be looked into further. This would help to address the issue of the degree of communication between reservoir rocks in stacked systems.

This report demonstrates that a strategic managed approach to a large formation or regional area may be desirable in certain scenarios of future CO2 storage. The costs and benefits of such approaches have not yet been established, so studies that evaluate methods to optimise infrastructure for exploration will become increasingly important.

To understand the potential consequences of multiple storage scenarios occurring at the same time, a regional storage characterisation is recommended. These clusters of storage sites could be developed where regions have multiple, connected storage options. However, a current knowledge gap is the amount of pre-competitive characterisation needed to help develop policy for leasing. Along with this, a detailed techno-economic evaluation of storage clusters would also be required. The UK case study detailed in the report demonstrates that targeting fewer but larger, more geographically dispersed storage sites could meet future requirements as an alternative to clusters. Such large sites could provide sufficient storage capacity for multiple capture plants and in the USA, private pore space ownership may inhibit the development of clusters (if a lack of strategic policy occurs).

A potential option to mitigate many of the possible interactions is the ‘active reduction of pressure through production of water’. Many studies have looked into this but not evaluated the different approaches to pressure management onshore/offshore, or how pressure could be managed in regions of multiple, sequential CO2 injection. The optimisation of CO2 injection and timing (to maximise storage capacity and reduce costs) is required, especially in deep saline aquifers.

Issues of competition (for example in the Netherlands) show that consistent planning is required to ensure an optimal/sustainable use of subsurface space and resources. Australia has competitive legislation on the storage of CO2 in offshore sites. A key short term objective in all jurisdictions in Australia is to realise early demonstration projects. The government of Alberta has established ownership of the subsurface space/resources and the ability to issue rights to the pore space to potential CCS projects. The government of Alberta’s Regulatory Framework Assessment has identified several gaps relating to the management of pore space and this report provides recommendations to address these gaps.

A key challenge in all regions is to ensure regulators from different jurisdictions work together. A range of issues that would benefit from further regulatory guidance have been identified, including as examples: experience in the application of the SROSAI (‘significant risk of a significant adverse impact) test in Australia, including development of guidance notes to inform on the use of these tests; the development of a guidance on what constitutes ‘good CO2 storage practice’; and better understanding of the interactions that may occur in the subsurface with CO2 injection and storage.

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EOR as a step towards wider CCS

CO2 EOR as part of a storage programme can be considered as ‘one response to a GHG-driven need to lower barriers to capture’. A review of the benefits/ difficulties experienced by current CO2 EOR projects with other operations can be used to provide information on how future CO2 storage projects may interact with other uses. The potential for using CO2 EOR as a method of geological storage is high, and has been demonstrated by early deployments in the USA.

EOR sites have favourable attributes toward the long-term storage of CO2, including known top seals, well-quantified injectivity and storage potential. Such favourable aspects were identified within the report, including the high quality of storage, good site characterisation and dense monitoring potential, a positive economic signal (from additional oil production), well-known regulatory and liability aspects, and well-known public acceptance (in many areas). Limits to the potential use of EOR as storage include that the whole system response is perhaps weak in terms of emissions and the energy consumption required by EOR operations reduces storage efficiency. In addition to this, there are numerous well penetrations in EOR areas which could potentially lead to lowered storage effectiveness (but this is an area identified as needing further research). The impact of different types of well failure mechanisms were looked at and such types include acute, high volume, short duration events; the migration of CO2 into unintended areas, which could occur quickly or over a long period; and low-rate leakage through flawed well construction.

Uncertainties arise with EOR for CO2 storage for various reasons, one major issue being economics – there are unknown cost curves (of CO2 and future oil) and uncertainty with capital markets. Other uncertainties with CO2 EOR include the regulatory environments and public acceptance. Uncertainty is elevated for potentially ‘unconventional EOR’, so in offshore reservoirs, residual oil zones, fractured reservoirs and gravity-stable floods.

Adjustments are required when using CO2 for EOR (as opposed to water or other substances); the ‘hydrogeologically-connected reservoir must be unitized and operated together’. Any interference between EOR and injection operations could be problematic in that increased pressure is beneficial for the enhanced recovery of oil, but injection operations benefit from decreased pressure. CO2 EOR for the storage of CO2 is an interesting and attainable strategy, but would need much legal and regulatory management.

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IEA GREENHOUSE GAS R&D PROGRAMME

45th EXECUTIVE COMMITTEE MEETING

ASSESSMENT OF COSTS OF BASELINE COAL POWER AND HYDROGEN PLANTS

This study has been undertaken by Foster Wheeler and their final report has been received. The attached overview was sent to Members for approval, with a deadline of 4th April 2014, i.e. after the deadline for completion of this paper. Any comments received from Members will be taken into account in the final report, which is expected to be published in May 2014.

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CO2 CAPTURE AT COAL BASED POWER AND HYDROGEN PLANTS

Key Messages

• This study provides an up-to-date assessment of the performance and costs of coal-based power and hydrogen plants with and without CO2 capture.

• The thermal efficiencies of power plants with CCS based on pulverised coal firing with oxy-combustion or post combustion capture and IGCC with pre-combustion capture are all around 35% (LHV basis), which is around 9 percentage points lower than a reference pulverised coal plant without capture.

• The levelised cost of electricity is about 92 €/MWh for plants with oxy-combustion or post combustion capture and 115 €/MWh for IGCC plants with pre-combustion capture. This is about 75-125% higher than the reference pulverised coal plant without CCS.

• Costs of CO2 emission avoidance compared to the reference plant are 60-100 €/t.

• The rate of CO2 capture in oxy-combustion and IGCC plants could be increased from 90% to 98%, while reducing the cost per tonne of CO2 emissions avoided by 3%.

• Net CO2 emissions of a plant with post combustion capture could be reduced to zero by co-firing 10% biomass (on a carbon basis), without increasing the cost per tonne of CO2 avoided, depending on the price of biomass.

• The raw water requirements of the pulverised coal power plants with CCS could be reduced to near zero by using seawater or air cooling. For the ambient conditions considered in this study this would have little impact on the efficiency (<1 percentage point) and capital cost (<2%).

• The efficiency of producing hydrogen by coal gasification with CCS would be 58% LHV basis (65% HHV basis) and the levelised cost of production would be 16.1 €/GJ LHV basis (13.6 €/GJ HHV basis).

Background to the Study

In recent years IEAGHG has undertaken a series of studies on the performance and costs of plants incorporating the three leading CO2 capture technologies (post combustion, oxy-combustion and pre-combustion capture). In the time since those studies were undertaken there have been significant technological advances and substantial increase in estimated plant costs. IEAGHG decided to undertake a wholly new study on costs of capture at coal based plants producing the two leading low-carbon energy carriers, namely electricity and hydrogen. This study will provide a baseline for possible subsequent studies on other capture processes and capture in industries other than power and hydrogen generation. The study has been carried out for IEAGHG by Foster Wheeler.

It should be noted that the focus of this study is to provide an up-to-date technical and economical assessment of coal-fired power and hydrogen plants with CCS. The study does not aim to provide a definitive comparison of different technologies or technology suppliers because such comparisons are strongly influenced by specific local constraints and by market factors, which can be subject to rapid changes.

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Scope of Work Study cases

The study assesses the design, performance and costs of the following coal based power generation plants.

• Supercritical pulverised coal power plant without CO2 capture (reference plant)

• Supercritical pulverised coal power plant with post combustion capture based on CANSOLV solvent scrubbing

• Supercritical pulverised coal power plant using oxy-combustion

• IGCC plant based on GE slurry feed oxygen blown gasification and pre-combustion capture using Selexol solvent scrubbing

• IGCC plant based on Shell dry feed oxygen blown gasification and pre-combustion capture using Selexol solvent scrubbing

• IGCC plant based on MHI dry feed air blown gasification and pre-combustion capture using Selexol solvent scrubbing

The study also assesses the following hydrogen production plants, all based on GE oxygen blown gasification and Selexol solvent scrubbing:

• Plant with high net electricity co-production, including two 130MWe E class gas turbines

• Plant with intermediate net electricity co-production, including two 77MWe F class gas turbines

• Plant with low electricity co-production, including a PSA off-gas fired boiler.

All of these baseline plants are based on 90% CO2 capture. This is expected to be adequate for early CCS plants but some overall energy system models have shown that in the longer term, when national and global emission limits will be tighter, the emissions of the residual non-captured CO2 may be a significant constraint on the amount CCS, particularly coal-based CCS, that can be accommodated in the overall energy system. If CCS plants emit significant amounts of CO2 it will be necessary to apply even tighter emission controls to other areas of human activity, such as transport and agriculture, which could involve very high greenhouse gas abatement costs. Even if high levels of capture will not be required in CCS plants in the short-to-medium term it is important to identify whether high levels of capture could be achieved without excessive costs, to demonstrate that CCS has a long term future and to provide cost information that can be used by energy system modellers. This study assessed the technical feasibility and costs of achieving a higher level of CO2 capture (around 98%) in oxy-combustion and IGCC plants. In the oxy-combustion case this was achieved by passing the vent gas from CO2 purification through a membrane separation unit. For gasification based plants an additional MDEA solvent scrubbing stage was added.

An alternative way of achieving near-zero net emissions of CO2 would be to co-fire some biomass, assuming that biomass that is produced in a sustainable way has near-zero net emissions of CO2. Biomass could be used in post, pre and oxy-combustion capture plants. This study assesses a plant with 90% post combustion capture and sufficient co-firing of woody biomass to achieve zero net emissions.

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Another possible constraint on the large scale application of CCS in some places may be water availability. To complement the base cases, which were based on natural draught cooling towers, sensitivity cases based on once-through sea water cooling and dry air cooling were assessed.

In addition to the sensitivities to percentage CO2 avoidance and the type of cooling system, the study also assessed the sensitivities to various economic parameters, including the coal price, capacity factor, discount rate, plant life, CO2 transport and storage cost and CO2 emissions cost.

Technical and economic basis

The technical and economic basis for the study is described in detail in the main study report. The main base case assumptions are:

• Greenfield site, Netherlands coastal location • 9C ambient temperature • Natural draught cooling towers • Eastern Australian internationally traded bituminous coal (0.86% sulphur a.r.) • Coal price: €2.5/GJ LHV basis (equivalent to €2.39/GJ HHV basis) • 2Q 2013 costs • Discount rate: 8% (constant money values) • Operating life: 25 years • Construction time: Pulverised coal plants - 3 years, Gasification plants – 4 years • Capacity factor: Pulverised coal plants – 90%, Gasification plants – 85% • CO2 transport and storage cost: €10/t stored

The pulverised coal plant without capture is based on a single boiler, a net output of around 1000MWe and state-of-the-art steam conditions (27MPa, 600/620C) as used in new large coal fired power plants in Europe and Japan. The pulverised coal plants with post combustion and oxy-combustion capture have the same coal feed rate but lower net power outputs of 820-840 MWe due to the energy consumption for capture. The coal feed rate of the IGCC plants is determined by the fuel feed rate of the two gas turbines, which are state of the art 50Hz F-class turbines suitable for high hydrogen content gas. The net power outputs of the IGCC plants are in the range of 800-880MWe, i.e. similar to the pulverised coal plants with capture.

Cost definitions

Capital cost

The cost estimates were derived in general accordance with the White Paper “Toward a common method of cost estimation for CO2 capture and storage at fossil fuel power plants”, produced collaboratively by authors from IEAGHG, EPRI, Carnegie Mellon University, MIT, IEA, the Global CCS Institute and Vattenfall1.

The capital cost is presented as the Total Plant Cost (TPC) and the Total Capital Requirement (TCR).

TPC is defined as the installed cost of the plant, including project contingency. In the report TPC is broken down into:

• Direct materials • Construction • EPC services

1 Toward a common method of cost estimation for CO2 capture and storage at fossil fuel power plants, IEAGHG Technical Review 2013/TR2, March 2013.

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• Other costs • Contingency

TCR is defined as the sum of:

• Total plant cost (TPC) • Interest during construction • Spare parts cost • Working capital • Start-up costs • Owner’s costs

For each of the cases the TPC has been determined through a combination of licensor/vendor quotes, the use of a Foster Wheeler’s in-house database and the development of conceptual estimating models, based on the specific characteristics, materials and design conditions of each item of equipment in the plant. The other components of the TCR have been estimated mainly as percentages of other cost estimates in the plant. The overall estimate accuracy is in the range of +35/-15%.

Levelised cost of electricity

Levelised Cost of Electricity (LCOE) is widely recognised as a convenient tool for comparing the unit costs of different technologies over their economic lifetime. LCOE is defined as the price of electricity which enables the present value from all sales of electricity over the economic lifetime of the plant to equal the present value of all costs of building, maintaining and operating the plant over its lifetime. LCOE in this study was calculated assuming constant (in real terms) prices for fuel and other costs and constant operating capacity factors throughout the plant lifetime, apart from lower capacity factors in the first two years of operation.

The Levelised Cost of Hydrogen (LCOH) is calculated in the same way except that it is necessary to take into account the revenue from the sale of electricity co-product. It was assumed that the value of the electricity co-product is the cost of production in the IGCC plant that uses the same gasification and CO2 capture technology as the hydrogen production plants, i.e. the GE gasification plant. If the lowest cost CCS power generation technology had been used to value the electricity output, the LCOH would have been higher.

Cost of CO2 avoidance

Costs of CO2 avoidance were calculated by comparing the CO2 emissions per kWh and the levelised costs of electricity of plants with capture and a reference plant without capture.

CO2 avoidance cost (CAC) = LCOEccs – LCOEReference CO2 EmissionReference – CO2 Emissionsccs

Where: CAC is expressed in Euro per tonne of CO2 LCOE is expressed in Euro per MWh CO2 emissions is expressed in tonnes of CO2 per MWh

A pulverised coal plant without capture was used as the reference plant in all cases because the current power plant market indicates that this would in most cases be the preferred technology for coal fired plants without capture. The cost of CO2 avoidance would be different if an alternative reference plant was used, for example an IGCC or a gas fired plant without capture.

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Findings of the Study Power generation plants

Plant performance

A summary of the performance of the baseline power plants with and without capture is given in Table 1.

Table 1 Power plant performance summary, pulverised coal plants

Net power output

CO2 captured

CO2 emissions

Efficiency Efficiency penalty for

capture (LHV)

HHV LHV

MW kg/MWh kg/MWh % % % points Pulverised coal

No capture (reference plant) 1030 - 746 42.2 44.1

Post combustion capture 822 840 93 33.6 35.2 8.9

Oxy-combustion 833 823 92 34.1 35.7 8.4

IGCC

Shell, oxygen-blown 804 837 93 33.9 35.5 8.6

GE, oxygen-blown 874 844 94 33.3 34.9 9.2

MHI, air-blown 863 842 104 33.2 34.8 9.3

The efficiencies and CO2 emissions of the plants with capture are all broadly similar. The difference between the highest and lowest efficiency is less than 1 percentage point. Future technology improvements, such as development of improved solvents, air separation units and gas turbines, could change the relative efficiencies of the processes. The efficiency penalties for oxy-combustion and post combustion capture are towards the bottom of the range in published data2, demonstrating the improvements in capture technologies and thermal integration. Most published studies compare the efficiencies of IGCC plants with capture against IGCC plants without capture, so the efficiency penalties are not comparable to those in this study. However, the average efficiency of IGCCs with capture in this study is similar that of published studies2.

CO2 capture almost eliminates SOx emissions and also reduces NOx emissions, except for the post combustion capture case which has specific emissions about 25% higher than the reference plant, due to the lower thermal efficiency.

Capital cost

The capital costs of the plants are summarised in Table 2 and breakdowns of the total plant costs are given in Figures 1 and 2.

2 Cost and performance of carbon dioxide capture from power generation. M. Finkenrath, IEA, 2011.

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Table 2 Capital costs of electricity generation plants

Total Plant Cost (TPC)

Total Capital Requirement

(TCR)

TPC increase compared to the reference plant

€/kW €/kW % Pulverised coal plants

No capture (reference plant) 1447 1887

Post combustion capture 2771 3600 91

Oxy-combustion 2761 3583 91

IGCC plants

Shell oxygen-blown 3157 4350 118

GE oxygen-blown 3074 4238 112

MHI air-blown 3046 4200 110 Figure 1 Specific Total Plant Cost of pulverised coal plants

Figure 2 Specific Total Plant Cost of IGCC plants Including capture increases the specific cost per kWe by 91% for the pulverised coal cases and 110-118% for the IGCC cases, compared to the pulverised coal reference plant. This cost increase is partly due to the cost of additional plant required for capture and partly due to the reduced net power output per unit of thermal capacity, e.g. boiler size. There is no significant difference between the specific capital costs of the post combustion capture (PCC) and oxy-combustion plants. The main cost of additional plant for oxy-combustion is the cost of the Air Separation Unit (ASU). The cost of the ‘CO2 compression’ unit is higher in the oxy-combustion plant than in the post combustion plant because the volume of gas to be compressed is greater, due to the presence of impurities, and due to the cost of the CO2 Processing Unit (CPU) which removes the impurities. The CPU is included in the ‘CO2 compression’ unit cost in Figure 2, although it could also be considered to be a type of ‘CO2 capture’ unit.

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The specific capital costs of the three IGCC cases are similar. The MHI air blown gasifier plant has higher costs for gasification, syngas treating and acid gas removal (AGR), which is to be expected due to the higher volume of the fuel gas but it avoids the cost of a large ASU3.

Levelised costs of electricity and CO2 avoidance cost

Levelised costs of electricity (LCOE) and CO2 avoidance cost (CAC) are shown in Table 3 and Figure 3. The costs of the IGCC plants are higher than those of the pulverised coal combustion plants, mainly because of higher capital costs and higher fixed operating and maintenance (O+M) costs, particularly maintenance costs.

Table 3 Levelised cost of electricity and CO2 avoidance cost

Levelised Cost of Electricity (LCOE)

CO2 Avoidance Cost (CAC)

€/MWh % increase compared to the reference plant

€/tonne

Pulverised coal plants

No capture (reference plant) 52.0

Post combustion capture 94.7 82 65.4

Oxy-combustion 91.6 76 60.8

IGCC plants

Shell oxygen-blown 116.5 124 98.9

GE oxygen-blown 114.4 120 95.8

MHI air-blown 114.5 120 97.4

Figure 3 Levelised Costs of Electricity

3 Note, the MHI gasifier plant includes a small ASU which provides nitrogen for coal feeding but the vendor included this in the cost of the gasification unit

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Hydrogen plants

Hydrogen is used by various industrial consumers such as refineries and it can also be used as an energy carrier for decarbonisation of distributed energy consumers, such as houses and transport. It may also be an attractive fuel for low-CO2 intermediate and peak load electricity generation.

A summary of the performance of the baseline hydrogen plants with capture is given in Table 4. The plants co-produce electricity, to satisfy the plants’ own consumption and to provide some net output, as described earlier. The ‘Net efficiency to hydrogen’ in Table 4 is calculated by assuming that the net power output displaces electricity generated by a GE gasification IGCC plant with CO2 capture. It should be noted that while the efficiencies of coal fired power plants are higher on an LHV basis than on an HHV basis, hydrogen plants have a higher efficiency on an HHV basis.

Table 4 Hydrogen plant performance summary

Hydrogen output

Net power output

Efficiency to hydrogen

Efficiency to net power

Net efficiency to hydrogen

LHV LHV HHV LHV MW MW % % % %

High electricity 659 448 26.3 17.8 60.9 53.8 Medium electricity 969 289 38.6 11.5 65.3 57.7 Low electricity 1390 37 55.4 1.5 65.5 57.9

Capital costs of the hydrogen production plants are shown in Table 5 and the levelised costs of hydrogen (LCOH) are given in Table 6. In order derive the specific costs of hydrogen production, values need to be assigned to the capital cost and the levelised production cost of the electricity that is also produced by these plants. For the calculation of LCOH, the electricity co-product is valued at 114.4 €/MWh, i.e. the production cost of the corresponding IGCC case (GEE gasifier). Similarly, the capital cost associated with electricity production in the IGCC plant is subtracted from the capital cost of the co-production plants to give the specific capital cost of hydrogen production.

Table 5 Capital costs of hydrogen plants



Total Capital Requirement

(TCR) M€ €/kWH net €/kWH net

High electricity co-production 2461 1646 2272 Medium electricity co-production 2390 1549 2137 Low electricity co-production 2101 1430 1974

Table 6 Levelised cost of hydrogen

Levelised Cost of Hydrogen (LCOH), €/GJ HHV basis HHLHV basis

High electricity co-production 15.4 18.2

Medium electricity co-production 14.4 17.0

Low electricity co-production 13.6 16.1

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The highest efficiencies and lowest cost of hydrogen production are achieved by the plant with the lowest amount of electricity co-production, which is based on feeding the PSA off-gas to an on-site boiler.

Plant design sensitivity cases

Near-zero emission plants

The performance and costs of the plants with near-zero emissions are summarised in Table 7, which also shows the change in costs compared to plants with 90% capture. Increasing the percentage CO2 abatement reduces the efficiency and increases the capital cost and LCOE. The largest increase in LCOE is for the biomass co-firing case and the lowest is for the oxy-combustion case. The CO2 abatement costs per tonne are lower for the near-zero emission cases than for 90% capture. In the case of oxy-combustion this is because capturing CO2 from the vent gas from the CO2 purification unit is relatively simple and low cost. In the case of IGCC, the reasons for the cost reduction are more complex. The cost of CO2 abatement comprises the cost of cost of capture (shift conversion, CO2 separation etc.) and the higher cost of the core IGCC process without capture compared to a pulverised coal plant without capture. Although the cost of capturing each extra tonne of CO2 may be higher in the near-zero emissions case than in the 90% capture case, the extra costs for the core IGCC units compared to a pulverised coal plant remain the same. This cost is spread over a greater number of tonnes of CO2 captured, resulting in a lower specific cost.

Table 7 Near-zero emission plants

Efficiency TPC LCOE CAC % % pt.

change €/kW €/kW

change €/MWh €/MWh

change €/t €/t

change PCC+biomass (100% abatement)

34.6 -0.6 2887 +115 100.5 +5.8 65.1 -0.3

Oxy-combustion (97.6% capture)

35.3 -0.4 2823 +62 94.2 +2.6 58.3 -2.5

IGCC (98.6% capture)

34.1 -0.8 3203 +128 119.2 +4.8 92.5 -3.3

It should be noted that biomass could also be used in oxy-combustion and IGCC plants and greater proportions of biomass could be used, thereby achieving ‘negative emissions’. However, availability of biomass fuel may limited due to competition with other land uses such as food production and natural habitats. Also, biomass may have a higher value for abatement of CO2 emissions in other sectors where other low-CO2 options are more limited, such as production of biofuels for transport. This study has shown that even if biomass availability is a constraint, CCS plants would be able to achieve near-zero emissions if required without increasing the specific cost of CO2 abatement.

Cooling system sensitivity

The net raw water requirements of the power plants with CCS are 22-28% higher than that of the reference plant without capture. However, alternative cooling systems can be used to reduce the net water requirement of power plants with CCS to near zero in the case of oxy-combustion and post combustion capture and by around 70% in the case of IGCC. For the ambient conditions considered in this study, using once-though seawater cooling instead of natural draught cooling towers increases the thermal efficiency of plants with CCS by 0.5-0.7 percentage points and using air cooling reduces the efficiencies by 0.2-0.7 percentage points. This is mainly due to the effects on the turbine condenser

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pressure. Both of these cooling systems reduce the total plant cost by 1.5%. However, at higher ambient temperatures air cooling is expected to have a more negative impact.

Economic sensitivities

The costs of CCS depend on economic parameters which will vary over time and between different plant locations. It is therefore important therefore to consider the sensitivity of costs to variations in the parameters. The sensitivity to the coal price, economic discount rate, plant life, cost of CO2 transport and storage, operating capacity factor and cost penalty for non-captured CO2 emissions. Sensitivities were assessed for all of the main study cases and the results for each parameter are presented in graphical format in the main report. As an example, the sensitivities to all of the parameters are shown in Figure 4 for the pulverised coal plant with post combustion capture. The results would be similar for the oxy-combustion plant.

Coal price can vary over a wide range due to local coal availability and mining costs to market variability, which is difficult to predict. Varying the coal price by ±1.5 €/GJ from the base case of 2.5 €/GJ changes the LCOE by ±15.5 €/MWh.

The operating capacity factor of the plant may be lower than the 90% base case assumption in this study, either because of poor reliability and availability of the plant or because of electricity system constraints, i.e. other power generators with lower marginal operating costs being operated in preference to CCS plants at times of low power demand. Reducing the capacity factor can have a substantial effect of the LCOE, Figure 4 shows that reducing the capacity factor from 90% to 70% would increase the LCOE by 15.6 €/MWh. If the plant operates at a low capacity factor because of electricity system constraints the impacts on plant profitability and rate of return may be much less significant because the times when the plants are forced to not operate would by definition be times of low electricity prices, so the impacts on net revenues and rates of return of not operating at such times may be small. However, this is difficult to assess because the electricity prices depend on the costs of the other generating plants in the overall electricity system.

Figure 4 Sensitivities of Levelised Cost of Electricity (plant with post combustion capture)

Costs of CO2 transport and storage are expected to vary considerably between different sites. At sites where CO2 can be sold, for example for enhanced oil recovery, the net cost may be zero or even negative. If the CO2 has to be transported a long distance in a relatively small pipeline for offshore

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storage the cost would be substantially greater than the 10 €/t base case scenario in this study. Sensitivities to costs in the range of zero to 20 €/t of CO2 stored are shown in Figure 4 but the range of costs may be higher in some circumstances.

The main economic evaluation in this study does not include a cost for emitting non-captured CO2 to the atmosphere. Including a cost that is equal to the cost of CO2 abatement by CCS in this plant, i.e. 65 €/t CO2, would increase the LCOE by 6 €/MWh.

The LCOE is relatively insensitive to increasing the plant life from 25 to 40 years, because of the effects of economic discounting.

The sensitivities of CO2 avoidance cost (CAC) to variations in the economic parameters are shown in Figure 5. It can be seen that variations in the CO2 emission cost, which has relatively little impact on the LCOE of the plant with capture, has by far the largest impact on the CO2 avoidance cost, because it has a large impact on the LCOE of the reference plant. Conversely, the coal price, which has a relatively large impact on the COE of the plant with capture has a relatively small impact on the avoidance cost, because it has broadly similar impacts on both plants, the only difference being due to the lower efficiency of the plant with capture. Apart from the emissions cost, the parameter which has the greatest impact on the avoidance cost, for the ranges considered in this study, is the CO2 transport and storage cost.

Figure 5 Sensitivities of CO2 avoidance cost (plant with post combustion capture)

Plot areas

Preliminary plot plans were produced for the baseline plants with and without capture. The area of the reference plant without capture is 20ha. The inclusion of CO2 capture increases the area to 26ha for the boiler-based cases and 29ha for the IGCC cases.

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Comments on the draft report were received from reviewers at six organisations in the power industry, CCS project development and research. The contribution of the reviewers is gratefully acknowledged.

In general the reviewers thought the report was of a high standard. The contractor provided responses to all of the comments and made appropriate modifications to the report.

The main critical comment was by a reviewer who said that if different gasifier designs had been selected for the IGCC and hydrogen cases, the results would have been more favourable. The choice of gasifiers for this study depended on the availability of licensors to support the study at the time it was carried out and the technology variants they wanted to offer. The CO2 purity specification was also questioned but CO2 purity is still a subject for debate. IEAGHG is currently undertaking a study to assess the effects of impurities on CO2 transportation.

Conclusions

• The thermal efficiencies of power plants with CCS based on pulverised coal combustion with post combustion capture, oxy-combustion and IGCC with pre-combustion capture are 34.8 - 35.7% LHV basis, which is around 9 percentage points lower than a reference pulverised coal plant without capture.

• The levelised cost of base load electricity generation is about 92 €/MWh for boiler-based plants with oxy-combustion or post combustion capture and 115 €/MWh for IGCC plants with pre-combustion capture. This is about 75-125% higher than the reference pulverised coal plant without CCS.

• Costs of CO2 emission avoidance compared to the reference plant are 60-65 €/t for boiler based plants with CCS and 95-100 €/t for IGCC plants.

• Increasing the rate of CO2 capture to 98% in oxy-combustion and IGCC plants would increase the cost of electricity by 3-5% but reduce the cost per tonne of CO2 emissions avoided by 3%.

• Co-firing biomass can be used to reduce net CO2 emissions of plants with CCS to zero, assuming biomass is regarded as a ‘zero CO2‘ fuel. In a plant with post combustion capture this increases the cost of electricity by 6% and has no impact on the cost of CO2 avoidance, but the cost depends strongly on the cost of biomass, which depends on the availability.

• The net efficiency of producing hydrogen by coal gasification with CCS is 57.8% on an LHV basis (65.5% HHV basis) and the levelised cost of hydrogen is 16.1 €/GJ LHV basis (13.6 €/GJ HHV).

• Alternative cooling systems could be used to reduce the water requirements of pulverised coal power plants with CCS to close to zero. The reduction would around 70% for IGCC. For the ambient conditions of this study, using sea-water cooling instead of cooling towers increases the thermal efficiency by a maximum of 0.7 percentage points and using air cooling reduces the efficiency a maximum of 0.7 percentage points. Both cooling systems reduce the capital cost by 1.5%. It is expected that air cooling would have more negative impacts at higher ambient temperatures.

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Recommendations

• The performance and costs of plants with without CCS will depend on local conditions, such as ambient conditions, fuel analyses and costs, and plant construction and operating costs. This study which is based on a site in the Netherlands could be extended to assess plants at other sites world-wide, particularly in developing countries which are expected in future to account for a large proportion of the global stock of coal fired power plants.

• Various new capture technologies are currently being developed, offering the prospect of lower energy consumptions and costs. When sufficient information becomes available further studies should be undertaken to assess such processes on a consistent basis to this study.

• This study assesses the relative costs of producing electricity and hydrogen with CCS, on a consistent basis. This information could be used as an input to further studies to assess the optimum low carbon energy carriers for different energy consuming sectors.

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CO2 STORAGE EFFICIENCY IN DEEP SALINE FORMATIONS: A COMPARISON OF

VOLUMETRIC AND DYNAMIC STORAGE RESOURCE ESTIMATION METHODS (IEA/CON/13/208)

This study was undertaken by Energy & Environmental Research Center (EERC), University of North Dakota. It was jointly funded through the EERC – US Department of Energy (DOE) Joint Program on Reseach and Development for Fossil Energy-Related Resources Co-operative Agreement No. DE-FC26-08NT43291 and IEAGHG. The work was completed by Charles D. Gorecki (Senior Research Manager), Guoxiang Liu, Jason R. Braunberger, Robert C.L. Klenner, Scott C. Ayash, Neil W. Dotzenrod, Edward N. Steadman and John A. Harju. The draft report was peer reviewed in January and the comments adopted in the final report. The following paper presents the draft Overview of the study.

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Key Messages

• CO2 storage efficiency starts low, rises quickly, and then levels off in an asymptotic trend to a maximum in much the same way as oil recovery changes in an oil field through time.

• Additional optimisation operations can be implemented to1) increase the rate at which storage efficiency increases or 2) increase the maximum storage efficiency.

• The dynamic results become roughly equivalent to the volumetric efficiency values after about 500 years. Volumetric efficiency values could be used if enough time were given for CO2 to be injected.

• The biggest single factor that increases storage capacity is extraction of formation saline. There are much bigger differences (P10 – P90) in the modelled capacity of an Open system compared with a Closed system.

• Between 15% to 33% of the injected CO2 could end up in solution in the first 50 years of injection, and this percentage could further increase by up to 16% to 41% after 2,000 years.

Background to the study The goal of this study was to compare the volumetric and dynamic CO2 storage resource estimation methodologies used to evaluate the storage potential of deep saline formations (DSFs). This comparison was carried out to investigate the applicability and validity of using volumetric methods, which typically require less data and time to apply, to estimate the CO2 storage resource potential of a given saline formation or saline system. The project has showed how different variables including saline extraction (pressure management), geological uncertainty, boundary conditions and trapping mechanisms affect storage capacity. Dynamic modelling also revealed how CO2 storage capacity changes over time. The project goals were accomplished by applying both volumetric and dynamic CO2 storage resource estimation methodologies to the open-system upper Minnelusa Formation in the Powder River Basin, of the United States, and a closed-system comprising the Qingshankou and Yaojia Formations in the Songliao Basin, of north-east China. These two saline systems were selected because they are representative examples of an open and a closed system. The upper Minnelusa Formation consists of aeolian sand dunes cemented and interspersed with carbonates which act as a single flow unit. The Qingshankou and Yaojia Formations consist of deltaic–fluvial deposits, with good storage properties, separated by lacustrine muds with low storage potential. These formations are representative of a linked stacked storage system and were modeled as one system. Both study areas are in intermontane basins; however, the Qingshankou and Yaojia system does not have areas of discharge and recharge while the Minnelusa does. This results in the Minnelusa Formation acting more as an open system, while the Qingshankou and Yaojia system is expected to behave in more of a closed or semiclosed manner. This contrast adds a further dimension and provides a better comparison between the volumetric and dynamic approaches. The volumetric methodology and open-system storage efficiency terms are described in the U.S. Department of Energy (DOE) Carbon Sequestration Atlas of the United States and Canada (U.S. Department of Energy National Energy Technology Laboratory, 2010, Carbon sequestration atlas of the United States and Canada [3rd ed.]) and the closed-system efficiency terms are described by Zhou and others (Zhou, Q., Birkholzer, J.T., Tsang, C.-F., and Rutqvist, J., 2008, A method for quick assessment of CO2 storage capacity in closed and semiclosed saline formations: International Journal of Greenhouse Gas Control, v. 2, no. 4, p. 626–639). Both these terms were used to estimate the effective CO2 storage resource potential and efficiency in both the upper Minnelusa and Qingshankou–Yaojia systems. Model development The dynamic CO2 storage resource potential and efficiency values were determined through the use of injection simulation. In both the volumetric and dynamic approaches, a geocellular model was

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constructed of the entire storage formation and the overlying sealing formations. In both the volumetric and dynamic approaches, the same geological model was used so that the assessments could be made on a consistent basis. For each system, the effective open-system and closed-system storage efficiency terms were calculated so they could be compared to the storage efficiency as determined using the dynamic approach. Storage efficiency is defined as the estimated storage capacity, determined by dynamic modelling, expressed as a percentage of the theoretical storage resource. The theoretical storage resource represents the absolute total pore volume within a rock formation. In this study the theoretical resource limit only considers the formation properties that make it amenable to CO2 storage, e.g., good porosity and permeability. The starting point for both approaches was the construction of a geocellular model. Background data was compiled on the selected formations from each basin. Data was retrieved from existing structure contour maps, isopach maps, facies maps, geophysical wellbore logs, core analysis data and general geological interpretation. Petrophysical analysis was then used to determine porosity and permeability properties which could be used to develop facies models that could then be used to determine CO2 storage potential. The final step is to scale up the facies models within the formation across the entire basin. The procedure is summarised in Figure 1.

Figure 1 Workflow for the construction of geocellular models to calculate the effective storage resource potential. Uncertainty analysis and reservoir optimization was also applied to the base line for the models. The high case for each example was a 90th percentile (P90) condition and contains more of the primary storage facies and more pore volume, while the low case was a 10th percentile (P10) condition which has less primary storage facies and less total pore volume. The mid case is represented by a 50th percentile (P50) and is similar to the base case condition. A further refinement was applied in this case by applying boundary conditions which determined the extent of suitable reservoir conditions determined by porosity and permeability thresholds (<5 mD in the Qingshakou–Yaojia system and <1 mD in the Minnelusa Formation). The geocellular model was comprised of interconnected cells

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which consisted of storage facies above these predetermined thresholds. The procedure is outlined in Figure 2.

Figure 2. Sequential reduction in total pore volume to the effective pore volume in the upper Minnelusa Formation (the model is shown in Simbox (i.e., all of the cells have the same size and the thickness) Model simulation results A total of twelve simulation cases were run for both the upper Minnelusa and Qingshankou–Yaojia models to investigate the effects of trapping mechanisms, geologic uncertainty, boundary conditions, well configuration, and injection and extraction strategies. In each simulation run, the entire formation extent and overlying formations were included within the models in order to better understand the pressure buildup effects. Initially, injection was simulated for 50 years, and then the maximum dynamic storage was estimated by running a few cases with continuous injection for up to two thousand years until the maximum storage potential was reached. Based on the results of these simulations, the upper Minnelusa Formation behaved as an open system with dynamic CO2 storage efficiency ranging between 0.55% to 1.7% after 50 years, 2.5% to 7.9% after 500 years, and 3.4% to 18% after 2,000 years of continuous injection in cases without water extraction (see Table 1). These results are in very close agreement with the calculated effective volumetric CO2 storage efficiency and indicate that the use of a volumetric methodology would be applicable in formations that behave in a truly open manner as long as enough time is given for the CO2 to be injected. However, in the first 50 years of injection, these results are on the low side of the volumetric CO2 storage resource potential, which could have implications for published CO2 storage estimates made with volumetric methods.

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Table ES-1. Minnelusa System Effective CO2 Storage Efficiency Low High Volumetric Efficiency – Closed System 0.21% 0.21% Volumetric Efficiency – Open System 2.9% 11% Dynamic Efficiency – 50 years’ Injection 0.55% 1.7% Dynamic Efficiency – 200 years’ Injection 1.9% 4.3% Dynamic Efficiency – 500 years’ Injection 2.5% 7.9% Dynamic Efficiency – 2000 years’ Injection 3.4% 18% In the case of the Qingshankou–Yaojia system, the dynamic approach resulted in the storage efficiency ranging between 0.28% to 0.40% after 50 years, 0.45% to 0.60% after 500 years, and 0.62% to 0.72% after 2,000 years of continuous injection in cases without water extraction (see Table 2). These results are in very close agreement with the calculated closed system efficiency values and indicate that the system is closed or semiclosed. This approach supports the use of a volumetric estimate for similar systems, as long as a closed-system storage efficiency is applied. Table ES-2. Qingshankou–Yaojia System Effective CO2 Storage Efficiency Low High Volumetric Efficiency – Closed System 0.21% 0.21% Volumetric Efficiency – Open System 1.3% 10% Dynamic Efficiency – 50 years’ Injection 0.28% 0.40% Dynamic Efficiency – 200 years’ Injection 0.39% 0.52% Dynamic Efficiency – 500 years’ Injection 0.45% 0.60% Dynamic Efficiency – 2000 years’ Injection 0.62% 0.72% The volumetric methodology was applied to the two systems, using both the open-system and closed-system efficiencies. This resulted in open-system effective CO2 storage efficiency in the upper Minnelusa Formation from 2.9% to 11% and the closed-system effective CO2 storage efficiency of 0.54%. In the Qingshankou–Yaojia system, the open-system efficiency was 1.3% to 10%, and the closed-system efficiency was 0.21%. This wide range in effective storage efficiency values is due to the large amount of uncertainty in both the geological properties and the flow properties of the system. This study also investigated the effects of geological uncertainty, boundary conditions, the number and types of wells used, and water extraction techniques on the effective CO2 storage efficiency. In both the open-system upper Minnelusa and closed-system Qingshankou–Yaojia system, the use of water extraction had the largest effect on CO2 storage potential, increasing the storage efficiency by as much as 475% in the Qingshankou–Yaojia system and by approximately 100% in the upper Minnelusa Formation after 50 years of operation. The extraction rate and therefore the estimated level of increased storage efficiency compared with a volumetric base case depends not only on the numbers of injection and extraction wells but also if they are horizontal or vertical. The other factors including geological uncertainty, boundary conditions and the number and type of wells, did not play as significant a role in increasing the storage efficiency, as local pressure buildup and the concomitant reduction in the rate of injection in the upper Minnelusa Formation. Modelling results showed that regional pressure buildup was by far the biggest limiting factor in the Qingshankou–Yaojia system. In open-system cases such as the Minnelusa Formation (see Figure 3), the dynamic CO2 storage resource potential is time-dependent, and it asymptotically approaches the volumetric CO2 storage resource potential over very long periods of time in the order of several hundred or thousands of years. This is very similar to resource industries, namely, mining and the oil and gas industries, where if CO2 is treated in an equivalent manner to a resource its maximum storage potential can only be fully realized by using advanced technology, notwithstanding time, economics, regulatory, and other

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considerations. In closed systems, the maximum efficiency is reached much more quickly, and the results are roughly equivalent to the volumetric results calculated using a closed-system storage efficiency term. These results indicate that the volumetric assessments can be used as long as an open- or closed-system efficiency term is applied appropriately, with the understanding that the effective CO2 storage efficiency of a formation will probably take hundreds of wells spaced throughout a formation’s area, and it could take decades or possibly thousands of years of injection to fully realize the effective CO2 storage resource potential.

Figure 3. The dynamic CO2 storage efficiency of open systems is very time-dependent and slowly reaches an asymptote over time which approaches the volumetric effective CO2 storage efficiency, as shown here with the open-system Minnelusa Formation Trapping mechanisms are likely to play different roles in storing CO2 in a formation throughout the life of the storage project. In this study, the main concern was how these trapping mechanisms affect the effective CO2 storage efficiency. A series of simulations were run to determine the relative effects of physical, hydrodynamic, residual gas, and solubility trapping on the effective CO2 storage efficiency of each formation. Over time, the trapping mechanisms lock CO2 in the reservoir and gradually decrease the amount of remaining storage potential. This principle holds true for all of the mechanisms except solubility trapping. As injected CO2 mixes with the native formation waters, a portion of the CO2 dissolves, taking up less space in the reservoir which increases the storage efficiency by decreasing formation pressure and allowing more CO2 to be stored in the same pore volume. This study indicated that, in both formations, anywhere from 15% to 33% of the injected CO2 could end up in solution in the first 50 years of injection, and this percentage could further increase by up to 16% to 41% after 2,000 years. The study also explored how boundary conditions might affect storage capacity. The dynamic models were run for both the upper Minnelusa and Qingshankou–Yaojia systems with modifications to the peripheral cells in the geocellular model to simulate “open” and “closed” conditions”. The “actual” boundary conditions were defined by constructing the geocellular model to cover the entire formational extent, including areas too shallow to inject CO2; areas of discharge, recharge, and outcrops; and all of the overlying sealing formations to the surface. The overlying seals were assigned realistic porosity, permeability, and relative permeability values based on these formation types found in the literature. Constant pressure boundaries were then assigned to the surface, as well

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as recharge, discharge, and outcrop areas. The lateral edges of the formations were assigned no-flow boundaries. The inclusion of these additional areas outside of those typically considered for injection in the model made it possible to assess whether the systems are open, closed, or semiclosed. The “open” boundary conditions were defined by taking the same model conditions described in the actual boundary conditions and adding infinite acting boundary conditions to all lateral edges of the formation—including those terminating deep in the subsurface and those that would otherwise be closed because of sealing faults or other features. “Closed” boundaries were assigned the same conditions as the actual boundary conditions except for reducing the permeability to the overlying formations by a factor of 100. If the permeability in the overlying seals is already in the nanodarcy range, the results will not look significantly different than the actual boundary conditions scenario, with both acting as closed systems. The results of these model simulations for both systems are presented in Figure 4 which clearly shows a distinct contrast between the two systems. In the case of the upper Minnelusa Formation the results show a divergence of between an efficiency of 18% for an “open case” and 7.2% for a “closed” case after 2,000 years. In addition, the permeability of the overlying seals in the actual and open boundary conditions cases increased the storage efficiency in the actual and open scenarios by 53% and 147%, respectively, illustrating the important role that the formation seals can play in influencing storage efficiency, even in open systems. By contrast, changing the boundary conditions of the Qingshankou–Yaojia cases did little to affect the resulting storage efficiency after 50 and 2,000 years. After 50 years of injection, the Qingshankou–Yaojia system’s boundary condition cases had effective storage efficiencies ranging from 0.34% to 0.37%. After 2,000 years, these had increased but still did not vary significantly, with a resulting range of 0.62% to 0.67%. This is probably due to the very low permeability at the lateral edges and overlying seals in the actual boundary condition. Minnelusa Qingshankou–Yaojia

Figure 4 The Dynamic effective CO2 storage efficiency over time for the actual, open, and closed boundary conditions cases in the Minnelusa and Qingshankou–Yaojia systems Expert Review Comments This study was reviewed by five experts. There was a general consensus that the study has been well-conceived, well-executed, well-written, well organized, and carefully compiled. There were some specific points raised including the selection of the 10,000 TDS threshold as an upper limit for formation water which should be excluded from CO2 injection. (This threshold is the US definition of formation water that can be used a source of potable water). The clear explanation of parameters used in models particularly the criteria for porosity cut-off and an explanation of model limitations including the pressure threshold used in models (20%> initial reservoir pressure) were added to the report. Other minor modifications included the clarification of units and footnotes in tables and the inclusion of well densities. The experts proposed the inclusion of key messages specifically analogies with extractive industries like oil and gas. CO2 storage is a constrained resource comparable to oil and gas production.

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Conclusions The dynamic CO2 storage resource potential and efficiency was determined through the use of reservoir simulation. In both the volumetric and dynamic approaches, a geocellular model was constructed of the entire storage formations and the overlying sealing formations all the way to the surface. The same geological model was used so that the assessments made could be compared on a consistent basis. For the purposes of this study, three DSFs were selected in different geographic regions, with different geological conditions, to try to determine the validity of the volumetric estimates and the level of agreement between the volumetric and dynamic approaches. The simulation results for the upper Minnelusa Formation shows that it behaves in an open fashion, with dynamic CO2 storage efficiency ranging from 0.55% to 1.7% after 50 years, 2.5% to 7.9% after 500 years, and 3.4% to 18% after 2,000 years of continuous injection in cases without water extraction. The dynamic results become roughly equivalent to the volumetric efficiency values after about 500 years, indicating that the volumetric efficiency values could be used if enough time were given for CO2 to be injected. In the Qingshankou–Yaojia system, the dynamic efficiency varied from 0.28% to 0.40% after 50 years, 0.45% to 0.60% after 500 years, and 0.62% to 0.72% after 2,000 years of continuous injection in cases without water extraction. These results are in close agreement with the calculated closed-system efficiency values and indicate that the system is closed or semiclosed. This supports the use of a volumetric approach for similar systems, as long as closed-system storage efficiency values are applied. In the open-system upper Minnelusa Formation, geologic uncertainty and heterogeneity and the use of water extraction had the biggest effect on the effective CO2 storage efficiency. The number and type of wells did not play such an important role, especially in the long-injection scenarios. In the closed Qingshankou–Yaojia system, the use of water extraction increased the storage efficiency by as much as 475% during a 50-year injection scenario. The other factors did not play much of a role in increasing the storage efficiency, as pressure buildup in the formation was by far the biggest limiting factor on the effective CO2 storage efficiency. In open-system cases, the dynamic CO2 storage resource potential is time-dependent, and it asymptotically approaches the volumetric CO2 storage resource potential over very long periods of time. This is very similar to other resource industries, namely, mining and the oil and gas industries. In closed systems, the maximum efficiency is reached much more quickly, and the results are roughly equivalent to the volumetric results calculated using a closed-system storage efficiency term. These results indicate that the volumetric assessments can be used as long as an open- or closed-system efficiency term is applied appropriately, with the understanding that the effective CO2 storage efficiency of a formation is likely take hundreds of wells spaced throughout a formation’s area. It is likely that it could take decades or, possibly, thousands of years of injection to fully realize the effective CO2 storage resource potential. Recommendations The results from this study are illustrative and only represent two contrasting depositional environments. It may be worthwhile to investigate additional formations to determine whether the results from this study compare with a wider cross section of geological conditions and depositional environments. Solubility trapping may also need to be investigated more in the future, as it may play an important role in the geological storage of CO2. One of the limitations of this study is the size of the cells used in the geocellular models. Models with a larger number of cells that model formations over the same areas should enhance the predictive results. However, there is a compromise between the modelling objectives and the sophistication and computational resources required to run a series of different cases. There are also concerns in this study as to whether or not the physics of the solubility trapping process are adequately captured by the grid dimensions and cell sizes used in this study.

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TECHNO ECONOMIC EVALUATION OF DIFFERENT POST COMBUSTION CO2

CAPTURE PROCESS FLOW SHEET MODIFICATIONS A reduction in efficiency penalty for solvent based post combustion CO2 capture can be achieved by improving the solvent properties as well as by improving the process design. There are different process flow sheet modifications with an improvement in process design reported in various literatures. These process modifications potentially can reduce the efficiency penalty of the overall process. Some of the promising process flow sheet modifications are multicomponent column, inter-stage temperature control, heat integrated stripping column, split flow process, vapor recompression, matrix stripping and various heat integration options. For this study a supercritical pulverized coal fired power plant (SCPC) and a natural gas combined cycle power plant (NGCC) were chosen to be evaluated for different CO2 capture process modifications. A technical evaluation of the different process flow sheet modifications is performed and additional aspects of interest were evaluated in a qualitative analysis. Moreover an economic evaluation of different process flow sheet modifications was performed. As well as major gaps were identified and future recommendations are made. This project is led by Group of Prof. Dr.-Ing. A. Kather at TuTech Innovation GmbH, The Hamburg University of Technology, Germany.

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TECHNO ECONOMIC EVALUATION OF DIFFERENT POST COMBUSTION CO2 CAPTURE PROCESS FLOW SHEET MODIFICATIONS

Introduction The post-combustion capture (PCC) technology is a promising possibility to reduce CO2 emissions from fossil fuel fired power plants. One of the main concerns for the PCC is the rather large efficiency penalty. A reduction in efficiency penalty for solvent based PCC can be achieved by improving the solvent properties as well as by improving the process design. The solvent determines the process behavior and the efficiency penalty. A lot of solvents have been modelled and tested in pilot plants. Important interface quantities for the overall process are the specific reboiler heat duty and the reboiler temperature, which strongly depend on the solvent CO2 absorption characteristics. There are different process flow sheet modifications with an improvement in process design reported in various literatures. These process modifications potentially can reduce the efficiency penalty of the overall process. Some of the promising process flow sheet modifications are multicomponent column, inter-stage temperature control, heat integrated stripping column, split flow process, vapor recompression, matrix stripping and various heat integration options. A detailed comparison of the overall efficiency for different process flow sheet modifications with an improved solvent is necessary because most evaluations of these processes in literature are based on different boundary conditions and different solvents. Therefore, there is a requirement to evaluate these process modifications on similar solvent and process conditions. For this study a supercritical pulverized coal fired power plant (SCPC) and a natural gas combined cycle power plant (NGCC) were chosen to be evaluated for different CO2 capture process modifications. In this study, a technical evaluation of the different process flow sheet modifications is performed and additional aspects of interest are worked out in a qualitative analysis. In an economic evaluation, different process flow sheet modifications are compared. Based on this major gaps are identified and recommendations are made. SCPC Power Plant To facilitate comparisons with currently planned power plant projects, the model used in this work is based on a state-of-the-art supercritical pulverised coal power plant. The power plant is modelled with the commercial software tool EBSILON®Professional. The coal-fired power plant with high-pressure and high-temperature steam (295 bar, 600 °C) has a gross electrical power output of 900 MW. At its design point (full load operation without CO2 capture), the net efficiency is 45.2%, related to the LHV. The ambient air, which is taken from the inside of the boiler building, is split into primary air and secondary air. While the secondary air is sent directly to the boiler, the primary air is used for preheating a feed water bypass and then used as mill air. A steam preheater is foreseen to increase the air temperature at the air preheater inlet and thus also to increase the flue gas temperature and thereby avoiding local passing below the dew point. The flue gas cleaning consists of the common three cleaning steps:

• DeNOx • Electrostatic precipitator (ESP) • Flue gas desulphurisation (FGD)

The preheating train consists of five LP-preheaters, the feed water tank and three HP-preheaters. Just before entering the boiler unit, the feed water is heated to 300°C. The cooling system is based on a natural draught cooling tower which supplies cooling water at 16°C. With a temperature gain in the condenser of 10K and a temperature approach of 3 K the condenser pressure is determined to be 40 mbar. The major characteristics of the SCPC model are summarised in Table 2. The flue gas data downstream of the FGD unit serve as interface quantities between the power plant and the capture plant models. For the overall process evaluation, the Greenfield case was taken into consideration. In this case the power plant is designed for the operation with CO2 capture. A retrofit of an existing power plant would be very site specific and could influence different CO2 Capture process flow sheet modifications in different ways, making a comparison of the modifications impossible. The water-steam-cycle is adapted

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so that the steam pressure in the IP/LP crossover matches the extraction pressure required for CO2 capture at full-load operation.

Table 1 Characteristics of the SCPC model without CO2 capture

This eliminates the losses induced by steam conditioning measures such as a throttle or a pressure maintaining valve that occur in the retrofit integration case. Note that a perfect match of IP/LP steam pressure and extraction pressure required for CO2 capture is only valid for one operational point. As soon as the power plant load or the process parameters of the capture unit are changed, the throttle or the pressure maintaining valve must be activated leading to an additional energy penalty. The pressure drop ∆pext in the steam pipe between IP/LP crossover and reboiler is assumed to be 0.3 bar. Furthermore, the mean temperature difference ∆Treb in the reboiler is assumed to be 10 K. The reboiler condensate is returned to the preheating route where the feed water shows the closest temperature. To avoid hot spots in the reboiler which could lead to thermal degradation of the solvent or increased fouling in the reboiler, the steam for solvent regeneration has to be almost saturated (superheated steam 15K above boiling temperature). This is realised by recycling and injecting reboiler condensate into the superheated steam (spray attemperation). The pressure levels of the steam tappings for the preheating train are optimised using a nested one-dimensional iterative solution method. For each desired IP/LP crossover pressure the pressure levels of the steam tappings are adapted to ensure an equivalent comparison among different reboiler temperatures. The boiler island is not affected by the CO2 capture unit and is thus identical to the case without CO2 capture.

SCPC Reference Power Plant Values Heat input 1835.44 MWth Net output 830.48 MWel Gross output 900.00 MWel Net efficiency 45.2% Gross efficiency 49.0% Specific CO2 emissions 769 g/kWh Live steam temperature 600 °C Live steam pressure 295 bar Hot reheat temperature 620 °C Hot reheat pressure 55 bar Condenser pressure 40 mbar Flue gas downstream of FGD Mass flow 869.64 kg/s Pressure 1.018 bar Temperature 50 °C CO2 13.5 Vol% H2O 12.0 Vol% N2 70.2 Vol% O2 3.5 Vol% Ar, SOx, NOx 0.8 Vol%

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Figure 1 Waste heat integration for the SCPC case

Besides the steam extraction and optimised integration of the reboiler condensate (Basic integration), waste heat sources are identified and used for feed water preheating. A typical waste heat source within the capture process is the overhead condenser, where the CO2 stream is cooled to condense remaining steam. In this case the temperature level is around 10-20 K below the reboiler temperature. Another reasonable waste heat source is the intercooling of CO2 compression. The temperature level depends on the number and position of intercoolers and can hence be directly influenced. The higher the temperature level, the more efficient the waste heat can be integrated in the power plant. However, a higher temperature level leads to an increased electrical power duty of the engine drive. The energetic optimum of these two opposing effects lies between the two extreme cases (minimal electrical power duty and maximal temperature level). Therefore, both effects have to be included into the overall process optimisation. As heat sinks the combustion air and the water steam cycle of the power plant are available. Preheating of the combustion air is realised by air preheaters where sensible heat from the flue gas is transferred to the combustion air. Furthermore, a steam preheater is provided to increase the air temperature at the air preheater inlet and thus also the flue gas temperature to avoid local passing below dew point. Even if waste heat integration could (from the energetic point of view) substitute the steam preheater, the control of the flue gas temperature at the preheater outlet still requires a steam preheater. To maximise the effect of waste heat integration for combustion air preheating, enormous capital expenditures are required. Thus, the combustion air does not represent a realistic heat sink for waste heat integration. Another heat sink is the preheating route of the water steam cycle (see Figure 1). The low pressure condensate has a pressure of less than 20 bar and can (as a parallel stream) be transported to the waste heat sources. The amount of waste heat, which can be integrated in the preheating train, strongly depends on the available condensate mass flow. Therefore, a high heat duty of the capture process leads to a limited potential of waste heat integration. The temperature level is limited by the feed water tank. An

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undercooling of 5 – 20 K is required to ensure degasification in the feed water tank. Further approaches for heat integration (e. g. district heating) are classified to be very special and are thus neglected in this study. NGCC Power Plant The model used in this work is based on a state-of-the-art natural gas combined cycle plant (NGCC). The power plant is modelled with the commercial software tool EBSILON®Professional. The plant consists of two gas turbines, each of which is equipped with a heat recovery steam generator (HRSG) to use the heat of the flue gas downstream the gas turbine. The steam produced in the two HRSGs is lead to a common steam turbine. The whole plant has a gross electrical output of 883 MW, consisting of 278 MW from each of the gas turbines and 327 MW from the steam turbine. The net efficiency of the power plant in full load operation without CO2 capture is 58.2%, related to the LHV. The gas turbine is a sequential combustion gas turbine delivering high flue gas temperature for the subsequent HRSG. The water-steam cycle is a three pressure level process (live steam 585 °C, 159 bar) with a reheat (585 °C, 40 bar). The cooling system is based on a mechanical draught cooling tower which supplies cooling water at 19 °C. With a temperature gain in the condenser of 11 K and a temperature approach of 3 K the condenser pressure is determined to be 45 mbar. The CO2 concentration in the flue gas of an NGCC plant is very low compared to the flue gas of an SCPC plant (4.2 Vol.-% for NGCC, 13.5 Vol.-% for SCPC).

Table 2 Characteristics of the NGCC model without CO2 capture

Parameters NGCC plant with FGR NGCC plant w/o FGR

Heat input 1520.79 MWth 1504.49 MWth

Net output 874.00 MWel 874.00 MWel

Gross output 884.34 MWel 883.85 MWel

Net efficiency 57.47% 58.09%

Gross efficiency 58.15% 58.75%

Specific CO2 emissions 356 g/kWh 356 g/kWh

Compressor pressure ratio 34 34

Gas turbine exhaust temperature 619 °C 619 °C

Live steam temperature 585 °C 585 °C Live steam pressure 159 bar 159 bar Hot reheat temperature 585 °C 585 °C Hot reheat pressure 40 bar 40 bar Condenser pressure 45 mbar 45 mbar Flue gas downstream of FGR/HRSG

Mass flow 621.75 kg/s 1321.79 kg/s

Pressure 1.018 bar 1.018 bar

Temperature 84.8 °C 85.2 °C

CO2 9.1 Vol.% 4.2 Vol.%

H2O 10.1 Vol.% 8.7 Vol.%

N2 76.7 Vol.% 74.3 Vol.%

O2 3.2 Vol.% 11.9 Vol.%

Ar, NOx 0.9 Vol.% 0.9 Vol.%

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This is equivalent to a reduced partial pressure of CO2 which increases the energy requirement for the capture plant. In order to minimize this energy requirement for the capture plant, flue gas recirculation (FGR) is used. Part of the flue gas downstream the HRSG is recirculated, cooled down in a direct contact cooler and led back to the compressor inlet, where it is mixed with fresh air. At a recirculation rate of 0.54 (ratio of recirculated flue gas to flue gas leaving the HRSG), the CO2 concentration in the flue gas is increased to 9.1 Vol.%. Higher recirculation rates are not reasonable, since the O2 concentration in the combustion chamber would be too low to ensure stable combustion conditions. The major characteristics of the NGCC model with and without FGR are summarised in Table 3. The flue gas data downstream of the HRSG unit serve as interface quantities between the power plant and the capture plant models. In conformity with the SCPC case, the Greenfield case is taken into consideration also for the NGCC process. The water-steam-cycle is adapted so that the steam pressure between the IP and the LP steam turbine matches the extraction pressure required for CO2 capture at full-load operation. The pressure drop ∆pext in the steam pipe between steam turbine and reboiler is assumed to be 0.3bar and the mean temperature difference ∆Treb in the reboiler is assumed to be 10K. The simplified flow sheet of the basic reboiler integration is shown in Figure 2. As for the coal case, reboiler condensate is injected into the superheated steam (spray attemperation) to reduce the temperature and prevent hot spots in the reboiler. The remaining reboiler condensate is partially returned to the water steam cycle upstream the economiser of the heat recovery steam generator to increase the temperature to 60°C and thus prevent condensation of vapour in the flue gas. The rest of the condensate is returned downstream the economiser.

Figure 2 Basic integration for the NGCC case

A more complex waste heat integration is not applied for the NGCC case. The potential waste heat sources are similar to the sources available for the coal case, but there are no heat sinks available. Preheating the condensate, as it is done for the coal case, is possible, but does not have a positive effect on the efficiency, since an increased feed water temperature leads to an increased exhaust gas temperature. The benefit of the additional heat source is thus counterbalanced by increased exhaust gas losses. This is especially crucial for the NGCC plant with CO2 capture, since the flue gas has to be cooled to 40°C for good absorption. An increased exhaust gas temperature results in higher cooling duties in the capture plant.

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Solvent Selection In the chemical solvent based post-combustion CO2 capture process, the solvent determines the process behaviour. A lot of work has been done in the field of solvent development and there are various solvent type available for CO2 absorption. The characteristics of some of these solvent with respect to the key factors relevant for CO2 capture are listed in Table 1.

Table 3 Overview of various amine based solvent properties

Amine based solvent Heat of absorption*

Absorption rate

CO2 capacity

Degradation tendency

Primary amines ● ● ◑ ● Secondary amines ● ◑ ◑ ◑ Tertiary amines

◑ ○ ● ○ Sterically hindered amines ● ◑ ● ○ Polyamines ● ● ◑ ○ Alkali salts ○ ○ ● ○ Ammonia

◑ ◑ ● ○ ● = high; ◑ = medium; ○ = low; * Note that the heat of absorption represents only a fraction of the total energy requirement for the

regeneration of the solution. It can be seen in Table 1 that no existing solvent excels the others, in all properties. Tertiary amines, for example, have a low degradation tendency and high CO2 capacity, but the absorption rate is low. A promising approach is therefore to blend different solvents in order to combine the positive properties of both solvents. One of these blends for example is a mixture of the tertiary amine methyldiethanolamine (MDEA) with the polyamine piperazine (PZ), which has higher rates of absorption in the absorber compared to MDEA, while maintaining its low heat of regeneration in the desorber. In accordance with the technical specification of this project, the absorption process shall use a generic improved solvent, representing a future solvent, with improved CO2 absorption properties probably available in the coming years. Improvements are possible for the above mentioned CO2 absorption properties, as well as for the solvent corrosion behaviour, the vapour pressure and the viscosity. It is not reasonable, though, to design a solvent with better values compared to all existing solvents for all above mentioned properties. Therefore a solvent for this study called Solvent2020 was developed. It is an artificial solvent which has the same CO2 absorption mechanisms as amines (carbamate and bicarbonate formation). The properties like density, viscosity or heat capacity are assumed to be similar to those of a solution with 7mole MDEA and 2mole PZ per kg H2O. Thus, the corresponding ASPEN Plus® property model is used for the simulations. The CO2 absorption loading of the solvent is an important parameter for the process design and is shown in Figure 3 where the CO2 partial pressure is plotted against the CO2 loading of the aqueous amine based solution for different temperatures. The CO2 loading range of this solvent for a typical process condition is between 0.2 and 0.4mole CO2/mole amine. The heat of absorption differs for relevant temperatures and loadings ranging between 60 and 75 kJ/mole CO2.

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Figure 3 CO2 partial pressure against CO2 loading of Solvent2020 for different temperatures

The absorption of CO2 in Solvent2020 is assumed to be very fast, which results in chemical reactions that are not kinetically hindered. This is one of the main property improvements compared to other solvents for Solvent2020. This assumption is used for modelling of desorbers with state-of-the-art solvents, as well. Due to the high temperatures, which catalyse the chemical reactions of CO2 desorption, this is found to be a reasonable approach. The absorber is generally not assumed to be in chemical equilibrium, though. Despite the chemical equilibrium, the columns are not in total equilibrium, since mass and heat transfer are calculated by rate based modelling. Solvent2020 is assumed to be thermally stable up to approximately 150°C, which is the same temperature as for PZ. Thus, thermal degradation is not expected to occur when operated at temperatures below this limit. Oxidative degradation is assumed to be negligible, as well. CO2 Capture Reference Case In order to have the current state of CO2 absorption process incorporated in this study, two important process improvements were considered one is intercooling in the absorber and second is the ability to operate at higher stripper pressure due to improvements in solvents stability. These two effects were evaluated for both reference cases for SCPC and NGCC case are discussed below. Effect of intercooling in Absorber The change in absorber temperature affects the CO2 absorption. The loading in the absorber without intercooling increases from the top of the absorber until a steady state is nearly reached at approx. half height. Downstream, the loading increases only very slowly until it starts to increase faster near the bottom of the absorber due to the lower temperature. Due to the lower temperature of the solution in the intercooled absorber, the CO2 absorption capacity of the solution is increased which results in a higher rich loading. In the upper half of the absorber, the loading is lower compared to the absorber without intercooling. This results from a lower CO2 partial pressure in the flue gas since more CO2 has already been absorbed in the lower half. The effect of the absorber intercooling on the specific thermal duty and the specific auxiliary duty of the capture process can be seen in Figure 4, where the specific thermal duty and the specific auxiliary power of the capture process with and without intercooling are plotted against L/G. It can be seen that all three

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specific duties for the intercooled case, are reduced compared to the case without intercooling. The lowest specific heat duty is reduced by 0.27 MJ/kg CO2, from 2.41 MJ/kg CO2 to 2.14 MJ/kg CO2. At the same operating point, the specific cooling duty is reduced by 0.34 MJ/kg CO2, from 3.09 MJ/kg CO2 to 2.75 MJ/kg CO2, and the specific auxiliary power is reduced by 0.01 MJ/kg CO2, from 0.079 MJ/kg CO2 to 0.069 MJ/kg CO2.

Figure 4 Specific thermal duty and specific auxiliary power of a capture plant in combination with

an SCPC plant (A1) with and without intercooling (IC)

Despite the additional cooler and pump required for intercooling, the specific cooling duty and the specific auxiliary power do not increase when intercooling is used. This is due to the fact that the heat transferred in the intercooler has to be removed from the process by other means for the absorber without intercooling, mainly in the lean solvent cooler. The increase in auxiliary power needed for the pump is compensated by the reduced auxiliary power for other pumps, since the L/G is reduced from 9.93 kg/kg to 6.96 kg/kg. This reduction is possible due to the higher rich loading with the lean loading being nearly constant. Effect of stripper pressure The stripper pressure is an important process parameter. The CO2 partial pressure in the stripper determines the lean loading of the solution. When the pressure in the stripper is increased and all other process values are kept constant, the CO2 partial pressure would increase as well. In order to reach the same CO2 partial pressure, and thus the same lean loading, for a higher stripper pressure the steam partial pressure has to be increased further. This is achieved by a higher reboiler temperature. In addition, higher stripper pressures lead to an increased power demand of the rich solution pump, while the power demand of the CO2 compressor is reduced.

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Figure 5 Specific heat duty and reboiler temperature of a capture plant in combination with an SCPC plant (A1) for different stripper pressures

Reducing the stripper pressure reduces the reboiler temperature, but leads to an increased specific heat duty, as can be seen in Figure 5. Higher stripper pressures are not beneficial for the overall process, since the decrease in specific heat duty is slowed down, while the reboiler temperature increases almost linearly. Similar effect was also noticed for NGCC base case (B1). Hence, a stripper pressure of 5 bar is chosen in this study. This results in a reboiler temperature of 128 °C. Definition of Interface Quantities To enable an effective procedure of overall process analysis, a clear definition of all energetic interface quantities is required. The interface quantities defined in this section will be listed for each CO2 capture process flow sheet modification, allowing a direct comparison (see Table 4).

Table 4 Energetic interface quantities

SCPC NGCC Basic integration Heat duty qreb (MJth/kg CO2) Heat duty qreb (MJth/kg CO2) Cooling duty qcool (MJth/kg CO2) Cooling duty qcool (MJth/kg CO2) Power duty waux (MJel/kg CO2) Power duty waux (MJel/kg CO2) Desorber pressure pdes (bar) Desorber pressure pdes (bar) Reboiler temperature treb (°C) Reboiler temperature treb (°C) Flue gas temperature upstream of

the capture plant tflue (°C) Heat integration Temperature level of waste heat thi (°C) Waste heat qhi (MJth/kg CO2) Technical Evaluation of Different Process Flow sheet Modifications For this study, different process flow sheet modifications of post combustion CO2 capture unit in combination with SCPC and NGCC power plant have been evaluated. A generic optimised solvent has been chosen including a solvent property model for the simulation of the process in ASPEN Plus® software. Reference CO2 capture plants for the SCPC and the NGCC plant were defined and simulated. For each SCPC and NGCC power plant, a CO2 capture plant base case was simulated to have a common

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basis for all process modifications. An energetic evaluation and optimisation has been performed for the following process flow sheet modifications:

• Vapour recompression • Multi-pressure stripper • Interheated stripper • Split flow process • Matrix stripping • Overhead condenser heat integration • Reboiler condensate heat integration • Combination of vapour recompression and split flow process • Combination of inter-heated stripper and overhead condenser heat integration

The most important interface quantities specific heat duty, specific cooling duty, specific auxiliary power, reboiler temperature, and desorber pressure were obtained from the process energetic evaluation. These were used to conduct an overall process evaluation for every process flow sheet modification in order to quantify the influence of the modified CO2 capture plant on the overall process performance. The overall efficiency penalty was used as a characteristic value to rate the effect on the overall process performance. This is defined as the difference between the net efficiency of the reference power plant and the net efficiency of a power plant equipped with a CO2 capture plant incorporating the respective process flow sheet modification. The overall efficiency penalty for different process modifications is shown in Table 4.

Table 4 Overall efficiency penalty for the evaluated process flow sheet modifications

Process Flow sheet Modifications SCPC ID

SCPC case in %-points

NGCC ID

NGCC case in %-points

Base case A1 6.11 B1 5.93

Vapour recompression A2 6.09 B2 5.86

Multi-pressure Stripper A3 6.25 B3 5.86

Heat-integrated stripping column A4 6.18 B4 5.92

Improved split flow process A5 5.99 B5 5.46

Matrix stripping A6 6.41 B6 6.04

Overhead condenser heat integration A7 5.84 B7a 5.28

Reboiler condensate heat integration - B7b 5.83

Combination of vapour recompression and split flow process A8 5.99 B8 5.46

Combination of inter-heated stripper and overhead condenser heat integration A9 5.88 B9 5.34

The process with the lowest overall efficiency penalty is the overhead condenser heat integration. Compared to the base case, a reduction of the overall efficiency penalty by 0.37%-points for the SCPC case and 0.65%-points for the NGCC case compared to the base case was obtained. The results for the improved split flow process show a considerable reduction of the overall efficiency penalty, especially for the NGCC case. The other modifications do not improve the overall process, for some modifications the overall efficiency penalty is even higher compared to the base case. This was noticed in almost all process flow sheet modification cases due to the higher reboiler temperatures, making it necessary to use steam of a higher quality to heat the reboiler. This effect over compensates the positive influence of the

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reduced specific heat duty, which was observed for almost all process flow sheet modifications. This illustrates the importance of an overall process evaluation. A comparison of the results for SCPC and NGCC cases shows that the NGCC case generally benefits more from the process flow sheet modifications. This is mainly due to the fact that the SCPC base case is designed with a waste heat integration using heat from the overhead condenser and the CO2 compressor for the preheating of the feed water. Modifications that reduce the temperature in the desorber head are thus less effective for the SCPC case since the amount of available waste heat is reduced. It has to be noted that these results strongly depend on the properties of the selected solvent and as well as on the boundary conditions selected for the processes. Therefore a general conclusion regarding to the benefit of one of the process flow sheet modifications cannot be drawn. For a new solvent, a similar evaluation has to be performed to be able to rate the most potential process flow sheet modifications. Economic Evaluation of Different Process Flow Sheet Modifications Each process flow sheet modification was evaluated from the economic point of view, highlighting which additional equipment items are required along with their costs and which repercussions the modified process will produce on the costs of the items of the base case capture plant. These changes affect the Purchased Equipment Costs. Due to the fact that CAPEX are directly proportional to PEC, the contribution factor ΔCoECAPEX (i.e. increase of the Cost of Electricity due to additional capital costs) is also proportional to PEC.

Table 5 Economic data used for the SCPC and NGCC power plant

Parameters Value Units

Project Life Time tPL 25 yr

Interest Rate i 8 %

Specific Capital Investment SCPC Case 1,700 € / kWel (net)

Specific Capital Investment NGCC Case 750 € / kWel (net)

Operating hours per year t 7,446 h / yr

Fuel Price SCPC Case 2.4 €/GJ

Fuel Price NGCC Case 7.5 €/GJ

Man power 80 -

Labour cost 60,000 € / (man yr)

Cost of Electricity (w/o capture) SCPC Case CoEref 42.22 €/MWh

Cost of Electricity (w/o capture) NGCC Case CoEref 59.50 €/MWh Moreover, differences with regard to OPEX will be presented, affecting the contribution term ΔCoEOPEX (i.e. increase of the Cost of Electricity due to additional operating costs), as well as with regard to the power plant net efficiency, which affects the contribution terms ΔCoEoutput (increase of the Cost of Electricity due to the decrease of net power output) and ΔCoET&S (i.e. increase of the Cost of Electricity due to transport and storage costs of the captured CO2; 10€/tonne CO2 stored) and the specific CO2 emissions eCO2. In this way the influence of each flow sheet modification on the economic indicators CoE (Cost of Electricity) and costs of CO2 avoidance will be explained and justified. Relevant economic data for the calculation of the different flow sheet modification economic indicators are shown in Table 5 below for SCPC and NGCC case. In the SCPC base case capture plant in combination the major equipment costs are represented by the following components, accounting for about 75% of the Purchased Equipment Costs:

• CO2 compressor (49% of PEC)

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• Absorber packing (9.7% of PEC) • Reboiler (9.3% of PEC) • ID fan (5.9% of PEC)

The other components account for less than 5% of PEC each. OPEX amount to 27.26 M€/yr. An alternative Base Case capture plant with higher desorber pressure has also been investigated. Higher costs for desorber shell, rich/lean heat exchanger and rich solution and intercooler pump motors lead to higher CAPEX (+2.8%). The net efficiency penalty of the process is also higher than for the Base Case, resulting in higher CoE (68.93 €/MWh) and costs of CO2 avoidance (39.31 €/tCO2). Table 6 gives a summary of the Cost of Electricity and of CO2 avoidance costs for the SCPC modifications obtained from the evaluation process. CoEref is the original value for the SCPC power plant without CO2 separation and stated for better comparability.

Table 6 Economic indicators for SCPC power plant flow sheet modifications

ID SCPC Cases CoEref CoE relative change of CoE CO2,avoided

€/MWh €/MWh % €/tCO2 A1 Base case 42.22 68.29 61.7% 38.32 A2 Vapour recompression 42.22 68.43 62.1% 38.54 A3 Multi-pressure stripper 42.22 69.53 64.7% 40.17 A4 Heat-integrated stripping column 42.22 68.39 62.0% 38.48 A5 Improved split flow process 42.22 67.87 60.7% 37.69 A6 Matrix stripping 42.22 68.95 63.3% 39.33 A7 OHC heat integration 42.22 67.65 60.2% 37.35 A8 Vapour recompression + split

flow 42.22 67.78 60.5% 37.57 A9 Heat-integrated stripper + OHC

heat integration 42.22 67.71 60.4% 37.45 As can be seen in Table 6, CO2 separation increases the CoE relatively by 60.2 to 64.7%. The base case shows an increase of 61.7%, which can be converted to CO2 avoidance costs of 38.32 €/tCO2. The process modifications vapour recompression, multi-pressure stripper, heat-integrated stripping column and matrix stripping show even higher increases of the CoE and of the CO2 avoidance costs, respectively, with multi-pressure stripper being by far the most expensive one (40.17 €/tCO2). The process modifications improved split flow process, OHC heat integration, vapour recompression + split flow and heat-integrated stripper + OHC heat integration yield cost reduction potential compared to the base case. The first combination of process modifications benefits from both single modifications, showing a bigger cost reduction potential than the single modifications alone. The second combination of process modifications benefits from the cost reduction for the OHC heat integration, but results however more expensive than the OHC heat integration alone. The modification OHC heat integration shows the lowest CoE (67.71 €/MWh) and CO2 avoidance costs (37.35 €/tCO2). In the NGCC base case capture plant the major equipment costs are represented by the following components, accounting for about 75% of the capture plant PEC:

• CO2 compressor (46% of PEC) • Absorber packing (10.1% of PEC) • Reboiler (7.9% of PEC) • ID fan (7.8% of PEC)

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The other components account for less than 5% of PEC each. Note that the cost-setting equipment is the same as for the SCPC power plant, although the numbers are slightly different. OPEX amounts to 16.21 M€/yr. Table 7 gives a summary of the Cost of Electricity for the NGCC modifications obtained from the evaluation process. CoEref is the original value for the NGCC power plant without CO2 separation and stated for better comparability. As can be seen, CO2 separation increases the CoE relatively by 27.3 to 30.2%. The base case shows an increase of 29.1%, which can be converted to CO2 avoidance costs of 54.76 €/tCO2. The process modifications vapour recompression, multi-pressure stripper and matrix stripping show even higher increases of the CoE and of the CO2 avoidance costs, respectively, with multi-pressure stripper being the most expensive one by far (56.76 €/tCO2). The process modifications heat-integrated stripping column, improved split flow process, OHC heat integration, vapour recompression + split flow, heat-integrated stripper + OHC heat integration and reboiler condensate integration yield cost reduction potential compared to the base case. The modification OHC heat integration shows the lowest avoidance costs (51.21 €/tCO2).

Table 7 Economic indicators for NGCC power plant flow sheet modifications

ID NGCC Cases CoEref CoE Relative change of CoE

CO2 avoided

€/MWh €/MWh % €/tCO2 B1 Base case 59.50 76.82 29.1% 54.76 B2 Vapour recompression 59.50 76.99 29.4% 55.27 B3 Multi-pressure stripper 59.50 77.46 30.2% 56.76 B4 Heat-integrated stripping column 59.50 76.51 28.6% 53.77 B5 Improved split flow process 59.50 75.92 27.6% 51.85 B6 Matrix stripping 59.50 77.39 30.1% 56.57 B7a OHC heat integration 59.50 75.73 27.3% 51.21 B7b Reboiler condensate integration 59.50 76.73 29.0% 54.46 B8 Vapour recompression + split

flow 59.50 75.95 27.6% 51.94

B9 Heat-integrated stripper + OHC heat integration

59.50 75.80 27.4% 51.46

Qualitative Analysis of Different Process Flow Sheet Modifications In the qualitative analysis, the CO2 capture process flow sheet modifications are investigated under aspects that differ from the energetic evaluation but are also important for overall analysis. The main aspect is the behaviour of the capture unit and the overall process in the whole operation range and under varying conditions. For the base, case a number of different aspects is analysed and for the modifications the main points are elaborated. The aspects on the limitation from the solvent, the operational flexibility in part load, the process control requirement and issues regarding the retrofitting are discussed for the different flow sheet modifications in detail and an overview is given in Table 8. The other aspects are discussed for the modifications in general in the description of the base cases. Effect of increased CO2 capture rate The behaviour of the process at higher capture rates than in the reference case are relevant because capture rates of more than 90% could be temporarily necessary to reach an average capture rate of 90% during the year. The reference capture rate is 90%; reducing the capture rate leads to lower reboiler heat duties, while higher capture rates increase the reboiler heat duty significantly. This is due to the higher or lower lean loading required for lower respectively higher capture rates.

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Table 8 Impacts of the key parameters on the different flow sheet modifications

Process flow sheet modification

Limitations from solvent properties

Operational flexibility in part

load

Process control requirement

Retrofitting to an existing power

plant

SCPC Cases

Case A1 ○ ○ ○ ○

Case A2 -- - ○ ○

Case A3 - -- - ++

Case A4 - ○ ○ --

Case A5 ○ ○ - -

Case A6 ○ + -- +

Case A7 ○ + - -

Case A8 - - - -

Case A9 - + - -

NGCC Cases

Case B1 ○ ○ ○ ○

Case B2 -- - ○ ○

Case B3 - -- - ++

Case B4 - ○ ○ --

Case B5 ○ ○ - -

Case B6 ○ + -- +

Case B7 ○ + - -

Case B8 - - - -

Case B9 - + - -

Notes: ++: very positive +: positive ○: neutral -: negative --: very negative SCPC cases were evaluated with advanced heat integration

For the solvent 7 m MEA the specific heat duty increases by 3% for a capture rate of 95%. A reduction to a capture rate of 70% reduces the heat duty by 3%. The consequences for an SCPC overall process are a higher power loss for higher heat duties or a generation of additional electric energy for lower capture rates. For 7 m MEA, a higher capture rate of 95% leads to an additional power loss of approximately 3%. With a reduced capture rate of 70% there is the possibility to generate around 5% additional power. These values, especially the values for the overall process, are very site specific. For the base case of the SCPC power plant with Solvent2020 used in this study, the additional heat duty is around 4% to reach a capture rate of 95%. The additional losses in the overall process is expected to be in the same order of magnitude. The capture plants with the different process modifications are expected to behave in the same way. All modifications cover improvements at the desorber but not at the absorber. This means that for a higher capture rate the solution mass flow and the lean loading have to be manipulated, because the rich loading is coupled with the absorber. Processes which integrate the heat more efficiently will benefit from higher solution mass flows and processes with a flat response of the specific heat duty on the L/G or the lean loading will benefit from a further reduction of the lean loading.

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Size of power plant The power plant size is a boundary condition and therefore very variable. To examine the impact of the power plant size on the process equipment requirement, a possible variation in the power output is shown in the following. Due to the possibility to build multiple parallel trains, there is no limitation in power plant size by the capture plant. The determining factor for the number of parallel trains is the absorber, in the base case for an SCPC plant the absorber diameter is around 17.6 m with a limit of 18 m. For an SCPC with power output of more than 900 MWel, this will result in more than two trains. The base case of an NGCC plant results in an absorber diameter of 14.5 m. For the modifications there are no further limitations. The components within the process of the different modifications can be built in parallel trains. Impact of solvent properties In some cases the solvent properties can limit the performance of the process flow sheet modification. The characteristic solvent properties are described in chapter. For the overall process analysis, the most important solvent property is the interaction between the specific interface quantities and the process parameters desorber pressure, lean loading and reboiler temperature. The reboiler temperature is limited by the degradation potential and the desorber pressure. In the base cases, no limitations of the solvent properties are significant. The vapour recompression could be more efficient if the solvent has a better CO2 regeneration performance and less CO2 will be in the vapour downstream the flash. This behaviour is also negative for the multi-pressure stripper. In the heat-integrated stripping column, the reboiler temperature is a real limit because in some cases the temperature could exceed 150 °C. The improved process flow sheet modifications which include either a vapour recompression or a heat-integrated stripping column are therefore also limited by the solvent properties. The issue of the suitability of commercially available improved solvents on the performance of different process modifications is of interest. Most available solvents are suitable for the most of the process modifications evaluated in this study. The benefit between the performance of the modification and the reference case could be larger, especially the vapour recompression could be more promising, see section but with the actual solvents the reference case would not be that efficient. For a reliable conclusion, the solvents have to be modelled and examined in detail with the capture plant and an overall process analysis is necessary. The solvent characteristics in degradation, solvent make-up and corrosion depend on the impurities of the flue gas and the temperature level in the reboiler. In this study a mixture of tertiary amine and polyamine is used. The degradation potential is lower than for primary amines. A lower degradation potential is beneficial for the solvent make-up rate, the fouling of the system, the corrosion rate and the reclaimer waste. The corrosivity is also lower for these solvents. For a better behaviour a pre-treatment column for lower SOx and NOx concentration in the flue gas could be necessary. The impact of the impurities is similar for all process modifications. For capture plants with multi-pressure stripping and matrix stripping the reboiler temperature is higher and therefore the solvent degradation potential is higher. Effect of power plant operation flexibility at part load conditions Another important issue is the operational flexibility requirement for part load operation of the power plant. In part load, the boundary conditions for the capture plant deviate from those for full load. The flue gas composition and mass flow are different for varying loads. For an SCPC the CO2 content decreases due to a higher air excess and the mass flow decreases. This leads to a lower specific reboiler heat duty in part load because of a closer approach to equilibrium in the absorber and a lower LMTD in the RLHX, both caused by overdesigned equipment. But for the overall process the efficiency penalty increases because of higher losses in the steam conditioning process in part load. In part load the IP/LP crossover pressure decreases according to Stodola’s law. Therefore a pressure maintaining valve is necessary to guarantee a certain steam pressure level for the reboiler. Also the specific auxiliary power of the CO2-compressor depends on the load. In part load, the specific auxiliary power is higher due to lower

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efficiencies of the compressor. A further efficiency reduction occurs due to a bypass operation of the compressor, which could extend the operation range. For an NGCC plant similar results regarding the steam extraction can be expected, since the steam turbines and the steam conditioning behave like in an SCPC plant. The impact on the different flow sheet modifications is shown in Table 8. It can be expected that the vapour recompression and the multi-pressure stripping will have higher losses in part load, because the efficiency of fans decreases in part load operation. Processes with heat exchangers can operate more efficiently at part load, because the heat exchangers are overdesigned and the temperature approach is smaller in part load operation. Modifications with heat integration benefit from smaller temperature differences and reduced losses. The matrix stripping has an advantage in part load. The pressure of the first desorber, which influences the necessary steam pressure, can be reduced easily without influencing the compressor much and therefore the reboiler temperature decreases as well as the losses for the steam conditioning. Process control requirement The process control is necessary to reach a value for the control variable by setting the actuating variable. At normal power plant operating conditions the most important control variable is the capture rate. The capture rate should be 90% and can be reached by manipulating the solvent flow and the reboiler heat duty. The control has to respect the overall efficiency of the power plant and should operate the capture plant in an operation regime with the lowest efficiency penalty for a capture rate of 90%. Other control variables are in subsidiary controls, like certain levels of temperature in heat exchanger. The requirement in control of the capture plant rises with more complexity in the flow sheet modifications and the choice of free variables. As shown in Table 8 the most complex modification is the matrix stripping. Here, the degree of freedom is the largest and the split factor and the pressure level need a control loop. Most of the modifications have a slight increase in the complexity compared to the base case. Retrofitting to an existing power plant All process analysis in this section were done for the case of a Greenfield power plant. When retrofitting an existing power plant, other issues like space and available utilities have to be considered and the IP/LP crossover pressure is of major importance. The design crossover pressure of the power plant influences the choice of the optimal process flow sheet modification. The temperature of the reboiler gets a higher sensitivity; at lower crossover pressures a lower reboiler temperature is significantly beneficial due to lower losses in steam conditioning and the other way round. The multi-pressure stripper has a very low temperature level in the reboiler compared to the base case and is therefore adequate for lower IP/LP crossover pressure. The matrix stripping has a reboiler temperature between the base case and the multi-pressure stripper. The heat integrated stripping column has the highest reboiler temperature and is therefore suitable for higher IP/LP crossover pressures. The other modifications show slight increases in the reboiler temperature. The available space for a retrofit is very site specific. The different flow sheet modifications are similar in the required space compared to the base case. A general conclusion on this point cannot be drawn. The retrofit of a capture plant into an existing NGCC plant is more complicated than into an SCPC plant, because a flue gas recirculation has to be installed to enrich the CO2 content. This will lead to an adaptation of the whole gas turbine which may not be applicable for a retrofit. For the water-steam-cycle of an NGCC plant similar behaviour like in an SCPC plant is expected. Further issues are site specific limitations like water availability, environmental conditions, etc. The process has a neutral water balance, therefore the capture process itself does not need water in normal operation condition. However, the water availability is important for the cooling section and therefore lower cooling duties in the process flow sheet modifications are beneficial in this point. Environmental conditions influence the efficiency of the power plant significantly, especially the gas turbine efficiency, but this influence is found to be equal for all process modifications.

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Identification of Gaps and Future Recommendations The process modifications analysed in this study are suitable for the application of post combustion capture in power plants. The reliability has to be investigated for all process modifications to ensure that no negative implications on the power plant process occur. One of the most challenging point is the development of a solvent with a very good performance. This solvent has to be tested in pilot plants and it is necessary to develop an exact property model of the solvent which describes the solvent with the effects of all process modifications. Also a very good behaviour in degradation and corrosion is necessary. A solvent with a very good energetic performance is not applicable when the tendency for degradation is very high. The interaction between different solvents and process modifications is the crucial point. While some solvents with a certain modification can show an improvement in efficiency other solvents might not reach this improvement. The different process modifications have to be realised in pilot plants and the reliability of the process modification has to be high to ensure an application in power plants. In certain campaigns long-time tests in pilot plants with flue gas of power plants have to be done to estimate the behaviour in operation. To evaluate the process modifications it is very important to do an overall process analysis. A number of process modifications leads to a reduced specific heat duty, while the reboiler temperature is increased, resulting in no positive effect on the overall process. The sensitivity of the logarithmic temperature difference of the RLHX is very high. For all modifications a temperature difference of 5 K is set. This could lead to very large heat exchangers but this is technically feasible. In the cases with vapour recompression the compressor which reintroduces the vapour into the column is a large electrical consumer. The efficiency and the operation regime of the component are relevant for the best operating point and the overall efficiency. This applies also to the multi-pressure stripping. Limitations of the solvent can influence the process strongly and inhibit improvements. In the cases with the heat-integrated stripping column this is an important factor that affects the process. During the evaluation of solvents these limits have to be considered and solvents have to be improved from this point of view. There is a possibility of various numbers of improved split flow processes. In this study the most promising modification is analysed. For other solvents, different split flow processes might by more efficient. In the matrix stripping case losses occur due to the fact that the CO2 compressor inlet pressure is adapted to the lowest pressure. The CO2 compression could be more efficient using the higher CO2 outlet pressure of the desorber columns without throttling. The highest temperature of different reboilers specifies the steam pressure of the steam extraction and the steam to the reboiler with lower temperature is throttled down. The difference between the reboiler temperatures should thus be as small as possible. In the heat integration cases the temperature differences in the heat exchangers define the usable heat and therefore it is an important key process parameter. A reduction of the temperature difference could improve the process. This is very important for processes with solvents which have significant higher specific energy demands. The flue gas recirculation for the NGCC process is not state-of-the-art and therefore disputable but the use of the recirculation is necessary for the post combustion capture to increase the CO2 content in the flue gas and improve the CO2 absorption process. Without flue gas recirculation the CO2 capture processes are not efficient and are leading to higher efficiency penalties. Therefore the development and improvement of an NGCC plant with flue gas recirculation is necessary. In this study, the power plants are considered as Greenfield and the IP/LP crossover pressure is optimised for the full load nominal point. It could be necessary to evaluate the behaviour in part load and optimise the IP/LP crossover pressure for this operation regime. This could lead to a higher IP/LP crossover pressure in full load, but the efficiency in part load would be better.

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GEOMECHANICAL STABILITY DURING PRESSURE BUILD-UP

(IEA/CON/13/214)

This study was undertaken by the Norges Geotekniske Institutt (NGI) The work was completed by Bahman Bohloli, Lars Grande, Jung Chan Choi, Hans Petter Jostad, Nazmul Haque Mondol and Joonsang Park. The final report has been received and is out for peer review. The following paper presents the early draft Overview of the study which is before any peer review comments have been received and incorporated. The final Overview will be sent to members for approval.

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Key Messages

• Faults typically consist of two sub-structures: a fault core; and fault damage. Faults in low porosity rocks have a fine-grained fault core whereas faults in coarse-grained, high porosity rocks, usually have low porosity deformation bands that can develop into high permeable slip surfaces.

• Fault zone permeability increases with increasing fluid pressure but permeability varies both across and along faults. Hydraulic properties also vary between the damage zone and the core where gouge material is concentrated. This concentration of fine grained minerals also reduces the mechanical strength of faults.

• Mechanical failure or reactivation occurs either when shear stress exceeds normal strength or when hydraulic fracturing is induced.

• Fault deformation can be either brittle or ductile. The former leads to the formation of cataclastite (fine grained granular) material which can reduce permeability. In contrast ductile deformation may have no effect on permeability.

• Reactivation of faults can be assessed using both analytical and numerical approaches, but assessment is usually based on the Mohr-Coulomb failure criterion. This method can be used to determine the critical injection pressure.

• Numerical modelling can provide predictions of fault stability at different scales and incorporate different parameters such as the geometry of different faults. Numerical methods can be effective for identifying leakage potential and seal failure especially where dilatancy and stress dependent permeability changes occur.

• Experimental tests on minerals and rock samples exposed to CO2 tentatively indicate that the coefficient of friction is not radically changed, however, this conclusion is based on limited exposure to the gas.

• There is limited observational data on stress regimes and direct pore pressure measurements from core samples from cap rocks and fault zones. Acquisition of key data would enhance stress regime modelling and fault behavior.

Background to the study

The storage of CO2 in geological reservoirs requires relatively permeable conditions bounded by very low permeable layers. Reservoirs can be bounded by faults that can act as seals if, for example, an impermeable formation is juxtaposed against it. The presence of faults in virtually all geological formations is a key consideration as their stability is crucial for the integrity of storage sites. Fault stability is affected by multiple factors including fault structure, material properties, geochemical reactions between CO2 and fault gouges and pore pressure changes. Injection operation and pressurization of reservoirs usually changes the state of the in-situ stresses which may cause destabilization of previously stable faults. Instability occurs in the form of slip along pre-existing fault or fracture systems, which may be associated with seismicity. In addition, movement along fault planes, and the generation of factures, may create open conduits that breach the integrity of the storage site. Understanding how faults might respond to stress conditions caused by CO2 injection is therefore fundamental.

Recent geomechanical studies for CO2 geological storage have focused on initialising stresses in the overburden based on all available geological and well engineering data, modelling the impact of fluid/gas pressure build up on stresses in the storage formations, the caprock and the overburden in general. The challenge is to predict the acceptable overpressure before shear failure, or reactivation of a fault/natural fracture occurs. The prediction process begins by using a verified geomechanical model to calculate the effective normal stresses and shear stresses occurring along all the faults/fractures. These stresses are evaluated in the context of fault cohesion and sliding friction to

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predict the pre-injection state of stress on these features and to determine the critical fluid/gas pressure required to initiate shear failure on what may have previously been a stable fault/fracture. Stress and fault properties can vary in space and time.

Scope of work

This report highlights the key factors affecting fault stability and reviews the methodologies generally used to evaluate geomechanical stability of faults during CO2 storage. It focuses on fault structure, hydro-mechanical properties of fault planes and the methodologies generally employed to assess fault stability. The objective of the report is to provide an overview of conditions that affect faults and highlight the essential components affecting mechanical stability of faults due to CO2 injection and pressure build-up in reservoirs.


Faulting is the response of brittle material to a stress field that exceeds its strength threshold. Faults nucleate from micro-fractures or deformation bands in a critically stressed region and accumulate strain over time to grow. As faults extend, they can interact with neighbouring faults of various sizes and can form special features important in the context of CO2 storage. A fault zone typically consists of two sub-structures: the fault core; and the fault damage zone. The fault core generally comprises gouge material, crushed particles/cataclasite or ultracataclasite (or combination of the two). The damage zone typically contains fractures at different scales. Faults in low porosity rocks have a fine-grained fault core surrounded by a fracture dominated damage zone. Faults in coarse-grained, high porosity rocks, usually have low porosity deformation bands that develop into high permeable slip surfaces (Figure 1).

Figure 1 Schematic representation of a fault zone comprised of a fault core and damage zones in a strike-slip fault.

Leakage through faults is a function of the permeability of the fault zone. The fault zone permeability increases with increasing fluid pressure towards a critical threshold. However, fault permeability varies both across and along faults. The hydraulic properties of fault cores and damage zones can be quite different as exemplified in Figure 2. These differences are attributed mainly to the properties of fault gouge material. The gouges are either granular or clay-rich. The permeability of granular material depends on the grain size distribution and sorting of grains. The permeability of clay-rich gouges is a function of the type of clay, clay percentage, and its distribution. The deformation along the fault zone also reduces the strength of the fault core material due to the concentration of clay minerals and micro fractures in the fault core.

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Figure 2 Permeability and mechanical properties of fault zone material.

Faults are usually the weak links in the rock mass and control hydraulic and mechanical behaviour of surrounding rock bodies. Mechanical failure or reactivation of faults may occur either: when shear stress exceeds shear strength of fault zone material; or when hydraulic fracturing (in case of cohesive faults) takes place. Under these conditions pore pressure exceeds the sum of the minimum in-situ stress and tensile strength of the fault. In the case of shearing, post failure deformation may be brittle or ductile, depending on the shear strength properties of the fault core and the level of the effective confining stress. In the brittle regime, deformation is associated with dilation which strongly contributes to the enhancement of permeability and therefore an increased risk of leakage. Ductile deformation may not significantly change permeability.

Reactivation of faults and fracture systems can be assessed using analytical and numerical approaches. The analytical approach considers static normal and shear stresses on a fault plane and relies on the Mohr-Coulomb failure criterion to evaluate stability of the fault. By applying this method the critical injection pressure can be calculated from the difference between the current stress state and the predicted failure envelope. The critical injection pressure, also called the maximum sustainable pressure, can be calculated for all possible fault orientations at given in-situ conditions.

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Figure 3 Schematic representation of stress fields on a fault plane and a representation of a change in effective stress due to injection (Mohr diagram) where τ = sheer stress, σ= normal stress, θ = dip angle of fault and Pf is the pore pressure

The critical pressure along faults within a reservoir can be calculated and then plotted on a polar stereographic projection to determine the predominant orientation of faults with susceptibility to shear (least stable).

An analytical approach is a simple and valuable tool for preliminary assessment of fault reactivation potential during injection or depletion. The analytical approach requires the following essential components:

• Magnitude and direction of in-situ stress • Fault orientation (dip and strike) • Shear strength, especially friction coefficient • Initial pore pressure and pressure change

The limitation of this approach is that it is based on many assumptions and simplifications and may not necessarily capture complex physical processes that occur in the reservoir during injection. The stability of faults in the cap rock and overburden as well as reservoirs is crucial for storage reservoir integrity. Consequently fault stability analysis needs to apply to faults within the storage unit and the surrounding formations. The analysis should include the ability to predict the extent of reactivation into the caprock. This may require local modelling of faults in the interface region which could be difficult to capture with variable pore pressures and lithologies. Analytical approaches may be further limited by changes in the magnitude and direction of principal stress directions during repressurisation. These limitations may be overcome by using numerical tools.

Numerical analyses of fault stability can provide fault simulations at different scales and within different geological constraints. Faults can be presented in a global model as single discontinuities, e.g. as a zero-thickness element, in order to explore their general behaviour. If a fault is prone to instability, and the detailed behaviour of the fault zone is of interest, it may be modelled as a rock mass of continuum material. This may require a local model where detailed properties and geometry of the fault zone are assigned to the components of the model. Furthermore, post-failure behaviour of faults is important for determining the potential for fault leakage and seal failure which can be studied using numerical methods where dilatancy and stress dependent permeability are taken into account. In a brittle regime, deformation occurs with associated dilation which can lead to lower permeability and possible leakage. In contrast ductile deformation is more diffuse and can lead to contraction with no change in permeability.

Following preliminary analysis a refined geomechanical model may be necessary. To progress to this more advanced stage a series of parameters will be required including:

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• A geometrical description of the reservoir and surrounding rock formations • Mechanical properties of reservoir and surrounding formations • Spatial distribution of pore pressure stresses and temperature usually acquired from core and

log data • Loading conditions (time history of a pore pressure field during injection)

To build a more comprehensive model of fault behaviour and the potential for reactivation three main geomechanical components need to be determined:

• In-situ stresses (vertical (σv), maximum horizontal (σHmax) and minimum horizontal (σHmin)), • Fault zone strength • Pore pressure profile

To determine in-situ stresses real data on formation geomechanical properties are required. Different techniques can be used to measure or infer the direction and magnitude of in-situ stresses. Horizontal in-situ stresses can be determined from borehole caliper logs, borehole image logs and televiewers. Vertical stress can be inferred from the depth of the overburden. Density measurements can be made from core samples and calculated from density and sonic logs. Determining horizontal stresses is more challenging by comparison. Leak-Off tests, formation integrity tests and minifrac tests can be used to assess the minimum in-situ stress. The maximum horizontal stress can be deduced from hydraulic fracture tests, however values recorded from deep cased wellbores can be very uncertain. If exact stress values are not available they can be estimated using the Stress polygon method which is based on the frictional strength of faults. The upper bound of horizontal stresses can be determined by plotting the limits of fault stability in the form of a stress polygon (Figure 4).

Figure 4 Stress polygon method used to define ranges of stress magnitudes at a specific depth.

A key component that needs to be included in any fault slip or reactivation scenario is the strength and friction coefficient of faults. The strength of faults (τ) can be calculated as a function of depth provided the correct value of friction coefficient (μ) and pore pressure (P) for the fault plane are known:

τ = μ(σn – P)

Data from laboratory tests and field observations show that friction coefficient of faults generally varies between 0.6 and 0.85, although values as low as 0.2 have also been reported in the literature for clay material. The strength of faults in a CO2 storage reservoir may be affected by the presence of CO2 but not substantially. A few studies tentatively indicate that the coefficient of friction of the

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fault-filling minerals does not change pre- and post-CO2 treatment. This observation is, however, based on a few laboratory studies where the effects of CO2 on rocks and minerals was only performed over short time spans.

Experimental work has shown that the presence of water decreases friction in cap rocks but not necessarily reservoir sandstones. An investigation into the effects of carbonic acid on carbonate reservoir rock indicated that there was a reduction in the frictional and tensile strength of the lithology which can be inferred from the Mohr circles and failure envelop for pre- and post-CO2 treated carbonate illustrated in Figure 5. Another test using supercritical CO2 on the frictional behaviour of simulated anhydrite fault gouge revealed that the friction coefficient of the material at 0.65 and 80°C can be reduced to 0.55 with an increase in temperature to 150°C.

Figure 5 Failure envelop for pre- and post-CO2 treated carbonate.

Conclusions

• Fault zone permeability depends on the type of deformation (brittle or ductile) and lithology (mineral composition).

• Fault zone permeability increases with increasing fluid pressure. Hydraulic properties vary between the core and the damage zone.

• Mechanical failure or reactivation occurs either when shear stress exceeds normal shear strength or when hydraulic fracturing is induced.

• The Mohr-Coulomb failure criterion can be used to determine shear strength and critical injection pressure but its application is limited by the pattern of stress regimes near faults and changes during depletion / injection. As an analytical method it can only be applied to reservoir formations because of the contrast in cap rock lithology and pore pressure regime.

• Numerical methods can be effective for identifying leakage potential and seal failure especially where dilatancy and stress dependent permeability changes occur.

• Experimental tests on minerals and rock samples exposed to CO2 tentatively indicate that the coefficient of friction is not radically changed, however, this conclusion is based on limited exposure to the gas.

• There is limited observational data on stress regimes and direct pore pressure measurements from core samples from cap rocks and fault zones.

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In summary, the Mohr-Coulomb failure criterion is the major technique employed to determine stress-strength relationships and stability analysis of faults. It can be applied to assess fault stability during and after injection of fluids such as CO2, or depletion of hydrocarbons. Analytical methods combined with the numerical solutions provide the best approach for assessing geomechanical stability of faults. Modelling can be used to determine the relative stability of different faults in reservoirs subject to repressurisation and the pressure thresholds required to maintain fault stability.

Knowledge Gaps

The study has highlighted a number of knowledge gaps in the understanding of fault stability analysis:

• Faults within reservoirs are generally well characterised in terms of stress regime and orientation but there is less detail on fault properties that transect cap rocks and extend into the overburden. Changes to mechanical and hydraulic properties of faults that extent into cap rocks and the overburden, that become reactivated during and post CO2 injection, are not fully understood.

• In-situ stresses on a fault in a sealing formation may be different from those within a reservoir because of pore pressure differences. Insitu tests, such as leak-off tests or laboratory measurements from core samples, would be ideal but are rarely obtained because historically sealing formations have been of limited interest.

• Geomechanical modelling of faults requires detailed data on fault properties however detailed core samples of fault material are usually limited and the geometry is not necessarily known. This can lead to uncertainties in modelling results. Better calibration is necessary to develop constitutive models to predict various failure modes caused during fault reactivation.

• Fault stability and movement is strongly dependent on pore pressure. The pattern of pore pressure change within fault zones is not usually known. The CO2 entry pressure into a fault zone might differ compared with the overburden. More detailed knowledge of pore pressure distribution between permeable and less-permeable formations, including fault zones, would improve modelling and reduce uncertainty.

• Relatively few studies have been completed on the influence of CO2 on the frictional properties of different rock types. Longer exposure times, under experimental conditions, might provide more representative results.

• Observations from oil and gas reservoirs have revealed that the same stress path during depletion is not followed during repressurisation. This phenomenon is important for estimating reservoir compaction/expansion, surface movement and identification of minimum pore pressure required to cause fault reactivation.

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SOCIAL RESEARCH NETWORK MEETING & IEAGHG SUMMER SCHOOL 2014

Social Research Network The following is a brief summary of the 2014 meeting of the IEAGHG Social Research Network. The usual report of the meeting will be published in the spring of 2014. Background The overall aim of the Social Research Network is “to foster the conduct and dissemination of social science research related to CCS in order to improve understanding of public concerns as well as improve the understanding of the processes required for deploying projects”. This 2014 meeting, the fourth of the IEAGHG Social Research Network, was held in Calgary, Canada from the 14th to 15th January. Hosted by the Institute for Sustainable Energy, Environment and Economy (ISEEE) at the University of Calgary, the meeting was sponsored by ISEEE, PTRC and IEAGHG. Forty delegates attended the meeting over the two days, from 9 different countries. Recent work and results were presented in sessions on: Setting the Scene; Policy and Practice in Canada; Social Science Trends and the International Atmosphere; Methodologies; the Communication of CCS and Scientific Issues; Risk Perception; Responses to CCS; and Social Science Research Related to Transport/Pipelines Highlights of Results and Discussions Session 1 looked at setting the scene for social science research in CCS. It is important that climate policies that can cope with uncertainty are developed and it is certain that risk adaptation will play a major role in the future of CCS projects. EOR is one method of facilitating and perhaps encouraging the implementation of CCS, but researchers are still missing the good visual tools to communicate each component. There is a potential role for CCS with old assets, when the hidden value of current assets are factored in, but the EOR ‘jury’ is still out given the total project lifecycle. Presentations on the policy and practice in Canada (Session 2) showed that structural arrangements, considerable preparation and a bit of scepticism (!) do matter. The policy environment is a driver and provides an important context for the entry of new technology into the public arena. Legal, regulatory and financial decisions can help to frame the significance of an issue. For practising communicators who want to build a stronger base for practice it is imperative to prepare – to start where the public is, to explore their perceptions, to understand their concerns and use these to inform communication approaches. It is equally as important to understand the framers’ interests and strategies for amplifying or attenuating risk. When looking at social science trends and the international atmosphere (Session 3), a survey (about CCS and risk/returns) of Chinese bankers showed that there is an improved understanding of CCS over the last 7 years, but that there are still concerns regarding cost and energy penalties. The prioritisation of risks has been acknowledged as a key aspect but there is no policy in place for large CCS projects. A catastrophic event such as the Fukushima nuclear incident (2011) can cast a negative light over other, similar technologies. It is important to understand the limitations of risk assessments and the different views of experts – science and policy need to be ‘bridged’ to enable decision-making. It is interesting (but not unexpected) to see that after such an event, the public will often change its opinion – in Japan, the public became more energy-aware, had some appetite for increased

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costs for cleaner (and safer) energy and preferred more renewable energy sources (e.g. solar) over coal and nuclear. Session 4 looked into the methodologies used in social science research and CCS. The Q methodology illustrates how people value subjective topics and the individual versus group ranking showed the impact of a deliberative process. It was demonstrated that the active use of social media can create an enhanced learning environment and interest in action, without increasing (or decreasing) the content learned. The attitudes of those within the environment suggested the value of community formation and deliberation was high. An online interactive tool has been utilised successfully to gain views on energy sources and costs; a tool which requires the users to consider trade-offs and that could be considered as an analogue for deliberative process. Communicating CCS and science (Session 5) is a hugely important aspect to consider. It is important to know what elements of a risk message regarding CCS are viewed by people as persuasive, but unfortunately it is much easier to persuade someone with negative arguments than with positive ones. It is key to know how people perceive the sources of scientific information – some groups may not be as credible and trustworthy as we think or hope. There are potential pitfalls associated with three of the common risk communication strategies for CCS – scattering, emphasis framing and greening. The perception of risk (Session 6) is a key topic in communications and is extremely important with CCS. A protocol for response to claims of the leakage of CO2 has been developed by researchers as a potential way to avoid many communication problems and is beneficial to avoid long running allegations, to avoid unqualified sources reaching incorrect conclusions and to prevent (or minimise the amount of) inaccurate information influencing the public. It is well known that public acceptance impacts implementation success and that the emotional reaction to complex technologies is important, as it affects people’s ability to make a decision. If there are more perceived risks, it is likely that the public will find it more difficult to form an opinion, which is important to the formation of closed attitudes. Stakeholder engagement and decision support was looked at in Session 6, which considered risk communication as a boundary process (so merging content and intent). CCS is being considered by the public, but their concerns are centred on costs, greenhouse gas emissions and air quality. Much research has been done on the responses to CCS (Session 7), including work on social site characterisation which noted the similarities (i.e. understanding that CCS is part of climate policy) and differences (risk perception or economic benefit being of most importance) in the local public’s opinions on two potential CCS sites in different countries. It was recognised that an open dialogue is key. In developing countries such as South Africa, the development of basic infrastructure is still an issue. The language problem for communication should be addressed and stakeholder engagement is especially important; the government and head of the local community concerned should be involved from the very beginning. It was recognised that the perceptions of pipelines (Session 8) was similar to CCS in general and seemed to centre around specific themes including trust, safety, visibility and local impact. The risk profiles for a project evolve with the stages of operation and it is crucial that the safety record of a project is explicit. It was observed that the terminology used in communications can present challenges with many different projects – something which can perhaps be further looked into. Issues recognised at pipelines were similar to those seen in CCS projects – approval, land use, proximity to other activities and regulations. Outcomes and Recommendations Gaps It was observed that much of the current work into social science and especially when related to CCS is happening in the Western or more developed countries context. The current methodologies would therefore benefit from a revitalisation. There seems to be a lack of research into how to communicate on and about a science that is seen as metaphysical. In this notion, it is important to look at when personal opinions become group opinions. There is little research work looking into the ethics of CCS, a topic that is hugely important and should be a research priority.

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Recommendations The following recommendations were made at the end of the fourth IEAGHG Social Research Network Meeting:

- Putting conclusions & results together from different levels to allow connections to be seen, for example qualitative and quantitative research, different theoretical frameworks, hand on focus groups etc. Physically drawing these connections together in real time as they occur, perhaps in a virtual space where all can contribute ideas would be beneficial

- A database for research instruments and papers relevant to social science and CCS was recommended – a repository for instruments, measures and researchers carried out by those in the network, which would be useful on many levels

- This network brings together lots of disciplinary perspectives to look at CCS (which is very valuable), but it may be useful to expand the network to other specialities

- The topic of CCS could be reframed by placing it into a larger context that may make it easier for the public to understand, which may also help to expand the network

- Further work in less developed countries

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IEAGHG Summer School 2014 The 8th IEAGHG International CCS Summer School will be held in Texas, USA and hosted by the University of Texas at Austin, from the 6th – 12th of July 2014. Selected students will participate in this week long International Summer School with presentations and discussion led by international experts in the field of CCS. At the time of print for ExCo, organisation of the Summer School is well underway. Over 230 registrations were received, up by 76% on last year, 140 complete applications were received and IEAGHG staff are currently analysing these applications to select the 60 successful students. The programme covers the full chain of CCS; providing up-to-date information in each field; including technical information on capture technologies, storage site selection, capacity and modelling, wellbore integrity and transport; as well as other issues such as regulations, health and safety, and public communication. The week is fully funded (travel, accommodation, meals and the course) by our Series and Local Sponsors. In addition to the existing Series Sponsors (Shell, Statoil, Schlumberger, Alstom, Gassnova, DECC, Ciuden, and CO2CRC) further sponsors are invited. Review of Phase 2 The 2014 School is the last in Phase 2 of the Summer School Series. A review of this phase will be undertaken and discussed with members at the 46th ExCo and with the International Steering Committee at GHGT-12. This committee is for the Series Sponsors of the Summer School to be able to influence the strategy and direction of the Summer School series. Expressions of interest for hosting for 2015 have been received from Mexico and Australia.

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STATUS REPORT ON GHGT

GHGT-12 remains very much on track both regarding the logistical time line and also to maintain its position of the leading CCS conference globally. Since the last report, the call for abstracts has closed with a submission of 1,174 abstracts for consideration. These have since been peer-reviewed, each by two independent experts (a panel of approx 130 experts were involved in the reviews). The GHGT-12 conference has seen the addition of a Technical Advisory Group (TAG) whose role was to assist the Technical Programme Committee (TPC) in specific subject areas to encourage abstract submission and analyse the reviewer’s scores and comments in order to form the abstracts into suggested sessions for consideration by the TPC. At the time of writing the abstracts have been sent to the TAG and their recommendations will go to the TPC before the meeting in Austin 8th-9th April. The outcome of this meeting will be a draft technical programme having selected the abstracts for both oral and poster presentation. The TPC are looking to accommodate an extra 44 oral presentations into the conference by adjusting the start and lunch times. This will increase the number of oral presentations from 297 to 341. From the reviewers scores, 449 abstracts have been recommended for oral presentation, we therefore feel confident that the additional presentation slots will be filled with high quality papers. Authors will be notified of the status of their abstract on the 2nd May. Following a thorough review by IEAGHG of the process and options for proceedings publication, an agreement has again been made with Elsevier to publish on the Energy Procedure website. Numerous changes to the process have been agreed with the publishers to expedite the production and ensure a delay to the publication is not repeated. In addition to the proceedings, Elsevier will also be providing free of charge, the use of their ‘Poster in my Pocket’ app allowing poster presenters to add a QR (Quick Response) code to the pdf of their poster and upload enabling delegates to instantly view this online both before, during and after the conference enhancing the two poster sessions and increasing the value of making a poster presentation. The TPC will also look to compliment the sessions with recommendations for the six Technical Plenaries and six allocated discussion panels. These will be presented along with a brief session breakdown at the ExCo. Formal invitations to attend and give a plenary speech have been sent to US Secretary of Energy Ernie Monitz, and Lord Stern (chair of the Stern report on the Economics of Climate Change), IEAGHG are currently waiting both responses. The third key note speaker is confirmed; Prof David Victor (Univ. Cal. at San Diego, CLA for Chap 1, IPCC WG3, Fifth Assessment Report. His speech is titled Global Climate Policy and the future of CCS. Financially, the conference is on target to meet the $300k sponsorship target with Chevron, Southern Company, Denbury, Battelle/PNNL, Korea CCS R&D, ExxonMobil, EPRI, URS Corp, Schlumberger and Gassnova/TCM all having committed to sponsoring. The sponsorship target does not include the $300k loan from US DOE.

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Registration opened on the 7th March with fees set at Registration type Fee Early Bird $850 Student Early Bird $400 Full $1,150 Student Full $550 The early bird offer will close on the 13th June allowing authors of accepted abstracts to arrange travel approvals before the deadline. An update on registration will be provided at the ExCo. GHGT-13: The MoU is currently in draft format and will be finalised by the summer.

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PRIORITISATION OF NEW STUDIES

Prioritisation of new studies 13 proposals for new studies were sent to members and sponsors for voting. These consisted of:

• 4 proposals re-submitted from the previous round of voting (one from a member) new proposals, 4 from members and 5 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 28 of the 40 members and sponsors, representing a 70% 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

45-07 Criteria for Depleted Oil and Gas Fields to be Considered for CO2 Storage 12 6 24

45-06 Fault Permeability 15 0 15 45-01 Regional Variation of Capture Costs 3 5 13 Other proposals

45-11 CO2 Small Scale Storage and Utilisation: Potential and Techno-Economic viability 7 3 13

45-10 Geochemical Effects of Impurities in the CO2 Stream on Formation Rocks and Well Cements under In-situ Conditions

9 2 13

45-04 Techno Economic evaluation of CO2 Capture in Liquefied Natural Gas Process 8 2 12

45-13 LCA of Synthetic Fuel Production with CCS 3 4 11

45-03 CCS for Waste-to-Energy (WTE) Plants 7 2 11 45-05 Model Comparison and Development 11 0 11 45-08 Leakage into the Overburden 6 2 10

45-12 GHG and Water Footprints in the Power Sector 8 1 10

45-09 Application and Advances in Monitoring at Different CO2 Storage Sites 6 1 8

45-02 Computational Tools and Models for Carbon Capture 7 0 7

After reviewing the outstanding studies waiting tendering and our current study commitments we will be able to take on up to 3 new studies. The outline proposals for the 3 studies which received the most votes (over 13 weighted votes or over 12 weighted votes and over 4 first choices) have been included here for members to consider. Following the presentations of the outline study specifications, the Committee will be asked to decide:

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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 basis for a decision on whether to progress to propose a full Technical Study. Some 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 Biomass Based FT Synthesis Process for Aviation Fuel 40 Low voting. New

topic so look at TR first. 43rd ExCo proposed scope to be refined and recirculated to members.

Hubs and Clusters Source EON. Agreed at 43rd ExCo to review existing work. Work now underway, to be be presented at 46th ExCo.

PCC technology based upon Bio-based material Agreed at 43rd ExCo, to proceed after Hubs and Clusters, as TR

CO2 Storage Wells/Site Abandonment 42, 41 The EU CO2CARE project covers this topic. Study deferred until CO2CARE completes.

Fuel Cells for Power generation with CCS 43 Agreed at 43rd ExCo, was proceeding as TR, now needs to be reallocated.

Patents Review 44 Being developed on capture, collaborating with IEA.

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CRITERIA FOR DEPLETED OIL AND GAS FIELDS TO BE CONSIDERED FOR CO2

STORAGE 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 45-07 Meeting 45th ExCo, April 2014, Vienna Title Criteria for depleted oil and gas fields to be considered for CO2 Storage Subject area Storage and Utilisation of CO2 Originator Total Description

Depleted gas fields are often thought of as a potential early step in CO2 geological storage. They are of a relatively known capacity, have been mostly well characterised, or have much data on the subsurface available and may also be associated with existing infrastructure, which may be able to be reused for the purpose of CO2 injection. However, there are other potentially negative factors that need to be considered. A field where there has been production will have several wells penetrating the storage formation and the overlying caprock. These will be of varying age and varying quality of abandonment. The pressure history of a reservoir is important to know to determine the likely effect of re-pressurising the reservoir by CO2 injection. A depleted gas field may initially be extremely depressurised, which will affect the initial injection of CO2. The data availability will differ over different fields depending on length of production, size of the field, how many operators have been active and how willing they are to share data. Site selection criteria have been produced for CO2 storage sites (2009/10), which also need to be applied to depleted oil and gas fields; however, this study would look at aspects particular to depleted fields and assess what criteria needs to be fulfilled for a depleted natural gas or oil reservoir to be considered eligible for CO2 storage. Such criteria include the number, density and history of wells; data availability; production history; current pressure and pressure history of the reservoir and observed compaction of the reservoir. The use of such criteria would allow sites to be ranked appropriately.

Resources required

Financial: Average Management: Average

Links with other on-going or proposed studies

CCS Site Selection and Characterisation Criteria (2009/10) CO2 Storage in Depleted Gas Fields (2009/01) CO2 Storage in Depleted Oil Fields (2009/12)

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FAULT PERMEABILITY

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 45-06 Meeting 45th ExCo, April 2014, Vienna Title Fault Permeability Subject area Storage and Utilisation of CO2 Originator IEAGHG/ Modelling and Risk Management Networks Description It is well known that a potential leakage pathway for CO2 from the storage

reservoir is via faults. Hence there is a need to include an assessment of faults in the characterisation of a storage site. However there is still a need for more understanding of fault characteristics, specifically permeability within fault structures and associated deformation zones in relation to CO2 transmissivity, and there is a lack of data This is required for the risk assessments of geological storage sites and to develop leakage flux rate scenarios. This lack of data was identified by the Modelling and Risk Management Networks meeting (Trondheim June 2013). As well as being potential leakage pathways because of higher permeability, faults can also act as barriers to flow and hence can be important factors in compartmentalisation and resulting operation of the reservoir. Fault characterisation within reservoir, especially where they extend into caprock and other overlying formations, needs to be thoroughly understood. There is some work that has been done to develop models of leakage along faults based upon current understanding and estimates of permeability, and there is work looking at measuring fluxes of natural CO2 seeps from faults, (eg by LANL, LBNL, Quintessa). Some of this work concludes that likely fault transmissivity scenarios would not result in significant leakages of CO2 from geological storage. This study would review the modelling work, the work on natural seepages, and available data, to investigate what is known regarding fault permeabilities, including assessment of different fault geometries and permeability distribution, and draw conclusions on implications for CO2 transmissivity and leakage rates. The study will identify knowledge gaps of significance to CCS projects, and recommendations on how these could be addressed.

Resources required



Fault geomechanical stability study - ongoing

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REGIONAL VARIATION OF CAPTURE COSTS

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 45-01 Meeting 45th ExCo, April 2014, Vienna Title Regional variation of capture costs Subject area CO2 Capture - Power Originator IEAGHG Description IEAGHG is completing a study to assess the performance and costs of baseline

coal fired power generation and hydrogen production plants with CO2 capture. This study assesses post combustion capture, oxy-fuel and gasification plants, plants with near-zero emissions including a biomass co-firing plant and sensitivities to the type of cooling system. In common with most of IEAGHG’s studies it is based on a hypothetical site in the Netherlands. Although Europe may be one of the first regions where large scale CCS plants are built, there will be greater potential for CCS elsewhere, where coal consumption is greater and is increasing. The performance and costs of plants with CCS will be different at different locations, but there is currently a shortage of information on a consistent basis, particularly for emerging economies. This proposed study will assess the performance and costs of coal fired power plants with CO2 capture in various countries. The plant performance and costs will be affected by physical criteria such as ambient conditions, fuel analysis, water availability and emission limits, and the costs will also be affected by economic criteria such as labour costs and productivity, construction materials and equipment costs and fuel prices. It will obviously not be possible to provide a comprehensive analysis of the costs of capture in all countries. Even within individual countries, particularly large countries such as the USA and China, there will be large variations in the physical criteria. The study will therefore only be able to provide a set of ‘snapshots’ of capture costs worldwide but this will still be worthwhile. The total number of cases will be determined by the budget for the study. There will need to be a trade-off between the number of locations that are assessed and the number of technologies, for example all three leading capture technologies could be analysed at a limited number of locations or a single capture technology could be analysed at a larger number of locations. The ExCo will be invited to comment on this trade-off. It is expected that the study will be carried out by the engineering contractor that carried out IEAGHG’s current baseline plants study, to minimise costs and ensure consistency.

Resources required



This study would follow on from IEAGHG’s coal fired baseline plant costing study, which will be completed before the 45th ExCo meeting.

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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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ISO TC265

The 3rd meeting of the ISO Technical Committee 265 on CCS was held in in Beijing on the 23-25 September. This ISO committee was proposed by Canada and set up in 2012 with a Canadian Chair and Canadian and Chinese Secretariat. There are 16 participating countries, 11 observer countries, and 6 Liaison organisations including IEAGHG. Its objective is to prepare standards for the design, construction, operation, environmental planning and management, risk management, quantification, monitoring and verification, and related activities in CO2 capture, transportation, and geological storage. It consists of six working groups: WG 1 Capture (lead by Japan); WG 2 Transport (lead by Germany); WG 3 Storage (lead by Canada and Japan); WG 4 Quantification and Verification (lead by China and France); WG 5 Cross-cutting issues (lead by France and China); WG 6 CO2-EOR (lead by USA and Norway). WGs 1, 4 and 5 met in Beijing, WG 3 met the week before in Toronto, and WG 2 met in June in Germany. Work is commencing on the development of international standards for CO2 pipelines, for geological storage (using the Canadian standard CS Z741), and on CCS Vocabulary. Work is commencing on Technical Reports on Capture and on Quantification and Verification for GHG emissions. A new working group was proposed by the USA on CO2 EOR, to separate it out from the storage working group, with USA and Norway to lead. This was adopted at the meeting, so a new WG 6 on CO2 EOR will commence. IEAGHG is a Liaison Organisation to TC265, and also a member of WG 1, WG 3, WG 4 and WG 5. Information on the work is available at http://www.iso.org/iso/iso_technical_committee?commid=648607 . The next meeting of TC265 and working groups will be the 31 March - 3 April 2014, hosted by Germany in Berlin. IEAGHG will participate and report back to ExCo 45.

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ECO2 press issues

Klaus Wallmann: [email protected] ECO2 is an EU project to establish a framework of best environmental practices to guide the management of offshore CO2 injection and storage. Its duration is 2011-2015. Its specific objectives are: • To investigate the likelihood of leakage from sub-seabed storage • To study the potential effects of leakage on benthic organisms and marine ecosystems • To assess the risks of sub-seabed carbon dioxide storage • To develop a comprehensive monitoring strategy using cutting-edge monitoring

techniques • To define guidelines for the best environmental practices in implementation and

management of sub-seabed storage sites IEAGHG participates in the Stakeholder Dialogue Board of ECO2, whose purpose is “Providing advice on the scope of the project, ensuring the research is grounded and relevant from a broader perspective; and assisting in disseminating research results to key stakeholders”.

At the AGU conference in December 2013 a presentation was given by Klaus Wallman of GEOMAR, project coordinator of ECO2. This was noticed by a journalist from Nature and generated an article which contained unduly negative messages, which was then picked up by some media.

The Nature article was titled “Seabed scars raise questions over carbon-storage plan - Unexpected fractures above the world’s biggest storage site could provide path for leaks”. One excerpt from it says “We are saying it is very likely something will come out in the end,” says Klaus Wallmann, ECO2 coordinator.” The negative messages are not substantiated by the abstract or the ECO2 work itself. These occur in the first parts of the article, the main parts are more reasonable descriptions of the work and results. The article can be found at http://www.nature.com/news/seabed-scars-raise-questions-over-carbon-storage-plan-1.14386is . IEAGHG has been in contact with Klaus Wallman since. He says he was misquoted from his interview. We recommended ECO2 issue a media response to rebut the negative messages and to promote the positive aspects of their work, which the ECO2 team did. Media responses were also made by the Scottish Centre for CCS (SCCS) and the University of Edinburgh. The response from ECO2 is copied below, along with the abstract of the talk. This is the second time Klaus Wallman has generated adverse headlines from ECO2 work. The first time was in September 2012, and prompted IEAGHG to issue a short briefing to ExCo members in September 2012. This is also copied further below, and is still a valid view from IEAGHG. The ECO2 project has many benefits, and is significantly advancing the development and demonstration of offshore monitoring techniques for shallow overburden and seabed. IEAGHG will use its position on the ECO2 Stakeholder Dialogue Board to advise the project to use caution on issuing results to the media by press release or interview. Results are better

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disseminated by following appropriate scientific peer review and appropriate checks on any media material. IEAGHG sought media training in 2011 following the Kerr Farm allegations at Weyburn. ECO2 Response Nature report about ECO2’s research on offshore CO2 storage

2014-01-17 19:33 by Anja Reitz (ECO2)

ECO2 partners from National Oceanography Centre (Southampton, UK) convened a special session entitled “Fluid Conduits and Biogeochemical Impacts of Sub-Seabed Carbon Storage (CCS) Leakage” at the AGU 2013 Fall Meeting (9th – 13th Dec) in San Francisco, USA. A journalist from Nature listened to the talks and interviewed several ECO2 partners during the subsequent poster session. The consortium highly appreciates the coverage by Nature (the article). It should, however, be noted that the report was produced by a journalist and was not previewed by ECO2 scientists. The headline and first paragraphs are written in a rather alarmist style to attract the attention of a broad audience. The members of the ECO2 consortium would have preferred the unspectacular but more precise scientific code and would like to make the following points in order to avoid confusion among the readership:

1. Despite extensive surveys, the ECO2 project has not found any indication that CO2 has leaked from Sleipner in its 17 years of operation.

2. The Hugin fracture is located 25 km north of the Sleipner injection site and it is extremely unlikely that CO2 will ever come closer than a few kilometres of it, and therefore it is considered that the probability of a CO2 leak through this structure is negligible.

3. ECO2 is currently evaluating the propensity to leak from Sleipner taking into account all seabed and overburden macroscopic features in the area. This work is still on-going, and at the present time, we don`t know how likely or unlikely it is that leakage may occur in the future.

4. The available data strongly suggest that, if leakage did occur, leakage rates and impacts would be minimal, and the overall net emissions reductions benefit of the CO2 storage project would still be very positive.

5. ECO2 project public perception studies have found no evidence that offshore storage will always be preferable to onshore storage; publics understand that environmental systems are complex and do not want reassurance that a site will never leak but want to know that all provisions have been taken to minimize the risk.

An overview on our current knowledge and the scientific work performed by ECO2 can be found in the abstract summarizing the introductory talk of the AGU session (add link to abstract).

Abstract:

Sub-seabed CO2 Storage: Impact on Marine Ecosystems (ECO2)

by Klaus Wallmann and the ECO2 consortium

The European collaborative project ECO2 sets out to assess the environmental risks associated with storage of CO2 below the seabed (http://www.eco2-project.eu). It includes 28

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partners from 7 European nations assessing the likelihood of leakage and impact of leakage on marine ecosystems. ECO2 studies the sedimentary cover and the overlying water column at active CO2 storage sites (Sleipner, Snøhvit) to look for any leakage pathways through the overburden and locate any seep sites at the seabed. High-resolution seismic data have been interpreted to feature a large number of vertical pipes and chimney structure cutting through parts of the sedimentary overburden at both storage sites. Formation waters are released through a 3 km long fracture 25 km north to the Sleipner platform while both natural gas and formation water are seeping through three abandoned wells located in the Sleipner area, as through many other old wells in the North Sea. The currently available data indicate that gases and fluids seeping at the seabed in the vicinity of the storage complex originate from the shallow overburden while CO2 stored at Sleipner and Snøhvit is fully retained in the storage formation. However, the observed geological features pose a number of important questions that are currently addressed by ECO2 via field work, data evaluation and numerical modelling: Are there any high permeability pathways for gas and fluid flow cutting through the overburden and linking the storage formation to the seep sites discovered at the seabed? Are seepage rates amplified by the ongoing storage operation at Sleipner? May CO2 stored at Sleipner and elsewhere ultimately leak through the overburden via seismic pipe and chimney structures, fractures and abandoned wells? CO2 release at the seabed was studied at three natural seep sites (Salt Dome Juist, Jan Mayen vent fields, Panarea) and via deliberate CO2 release experiments conducted in the vicinity of the Sleipner storage complex. The field work confirmed previous modelling results predicting that CO2 gas bubbles and droplets are rapidly and completely dissolved in ambient bottom waters. The efficient dissolution inhibits CO2 release into the atmosphere and produces a significant pH drop in ambient bottom waters. A high degree of temporal and spatial variability was observed in, both, CO2 emission rates and bottom water pH values. The response of different biota to bottom water and pore water acidification was studied at natural seep sites and in shore-based mesocosm experiments. The ongoing biological studies revealed that a limited number of species which are highly abundant at natural CO2 seeps are resilient to elevated pCO2. Other more sensitive species are trying to avoid and escape CO2 affected areas. Harmful effects of CO2 include alterations in early ontogeny of echinoderms, a phenomenon overlooked in previous studies. The field campaigns in 2012 and 2013 included 16 marine expeditions to offshore storage and seepage sites with a total ship time of 220 days. The large data sets assembled over the first project phase will be further evaluated by the ECO2 consortium to provide a comprehensive environmental risk assessment for the Sleipner storage site, to improve monitoring strategies, and to develop guidelines for the environmentally safe operation of sub-seabed storage sites. IEAGHG Briefing to ExCo members 25 September 2012 To ExCo 25/09/12 The ECO2 project is an EU-funded seabed monitoring project, and their investigations around Sleipner had found a seabed fracture system 25 km North of the Sleipner CO2 injection. The ECO2 project has now issued a press release on this, see, http://www.eco2-project.eu/newsarticles/items/north-sea-fracture-discovered.html . This has been picked up by Reuters http://www.reuters.com/article/2012/09/17/us-ccs-nsea-fracture-idUSBRE88G0LK20120917. At our Environmental Assessment of CO2 Storage workshop in July, there was a presentation from ECO2 which includes some information on this feature. The slides from the workshop can be seen at http://www.ieaghg.org/index.php?/2012-environmental-impacts-of-co2-storage-workshop.html , presented by Klaus Wallman in Session 5.

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http://www.eco2-project.eu/newsarticles/items/north-sea-fracture-discovered.html

http://www.reuters.com/article/2012/09/17/us-ccs-nsea-fracture-idUSBRE88G0LK20120917

http://www.reuters.com/article/2012/09/17/us-ccs-nsea-fracture-idUSBRE88G0LK20120917

http://www.ieaghg.org/index.php?/2012-environmental-impacts-of-co2-storage-workshop.html

http://www.ieaghg.org/index.php?/2012-environmental-impacts-of-co2-storage-workshop.html

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The facts: Fracture system is 25km north of Sleipner CO2 injection. Fracture system is approx 3km long, up to 200m deep (so doesn't reach CO2 storage formation at 800m). Detected by AUV equipped with a synthetic aperture sonar (SAS) measuring the acoustic back-scatter intensity of the seafloor. Fluids and methane have since been detected being transmitted from subsurface, but no CO2 detected. My conclusion: No CO2 leakage here. Demonstrates need for site characterisation and baseline monitoring, especially characterising the overburden around the plume area. Sleipner injection was started before any regulations requiring such site characterisation and baseline monitoring were developed. Research projects like ECO2 are valuable to develop and demonstrate new monitoring techniques, such as the AUV-mounted synthetic aperture sonar (SAS) here, which will make such monitoring easier and lower cost for CCS projects. Acknowledgements go to Statoil for sharing their overburden data with the ECO2 project.

North Sea fracture discovered

ECO2 Media Release 2012-10-02 08:00 by Anja Reitz

A large fracture, 3km in length, has been discovered during a scientific research cruise in the central North Sea. The discovery was made with the aid of an autonomous underwater vehicle (AUV) in 2011, deployed by University of Bergen from the research vessel G.O. Sars during an ECO2 Project survey to study the potential short-term and long-term impacts of CO2 storage on marine ecosystems.

The AUV was equipped with a synthetic aperture sonar (SAS) measuring the acoustic back-scatter intensity of the seafloor. With this new approach, the large branched seabed fracture was revealed. The intriguing structure was revisited during two ECO2 cruises later in summer 2012, led by the University of Bergen and GEOMAR. Seismic and sonar data obtained during these cruises revealed that the 1 – 10 m wide fracture penetrates 150 - 200 m deep into the sub-surface.

The fracture serves as a conduit for the ascent of methane gas from the deep subsurface which then dissolves in near-surface pore fluids. Where the fracture meets the seabed it is covered with soft sediments and up to 3 m wide patches of bacterial mats. Surface sediment samples were taken at these bacterial mats by a remotely operated vehicle (ROV). Sediment analyses combined with measurements on the sea floor revealed that the microorganisms completely convert the dissolved methane into CO2. When the entire fracture area is considered, about 1 ton of methane-derived CO2 is released into the overlying seawater per year. Similar natural seeps, where methane ascends from sub-seabed geological formations to fuel rich and diverse microbial ecosystems at the seabed, have previously been documented in the North Sea. Together with other available evidence, this indicates that the fracture is a natural structure that formed in the geological past.

The newly-discovered fracture is 25 km north of the Sleipner CO2 storage site. Computer models and observations from monitoring surveys imply that the CO2 stored in the Utsira Sand at Sleipner will never reach the fracture area. Furthermore, the available seismic data show that the fracture is vertically separated from the Utsira Sand by several thick, low permeability sedimentary seals. However, the chemical composition of gases ascending through the fracture indicates that a significant portion originates from deeper geological reservoirs. The ECO2 project will continue to investigate and monitor the fracture in order to evaluate its permeability for methane gas and CO2. According to the ECO2 project coordinator Klaus Wallmann “This discovery shows that there are still surprises awaiting us as we further investigate the seabed, even in waters we think we know well. It demonstrates the importance, both for ongoing and planned storage projects, to map and monitor the seabed using available cutting-edge technologies.”

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INTERACTIONS WITH WPFF AND OTHER IA’S

The 65th meeting of the Working Party on Fossil Fuels (WPFF) was held in December 2013 at IEA’s offices in Paris. IEAGHG (General Manager) attended and presented at the meeting. His notes on the meeting and any developments were outlined in Information Paper IP/1 2014 a copy of which is appended for member’s reference. The Energy Technology Network will meet after the ExCo papers were drafted. An update on the outcomes of the first network meeting will be presented to members at the meeting. The interaction between IEAGHG and the IETS IA are discussed in the following paper (GHG/14/30)

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IEAGHG Information Paper; 2014-IP1: IEA 65th Working Party on Fossil Fuels

The 65th meeting of the Working Party on Fossil Fuels (WPFF) was held in December 2013 at IEA’s offices in Paris. IEAGHG (General Manager) attended and presented at the meeting. My summary notes on the discussions/activities presented at the WPFF meeting are listed below: Meeting Process

• This was the first meeting of the WPFF where all 4 of the Implementing Agreements (IA’s) under the WPFF had been invited to attend and present on their activities to my knowledge. This marks a step change in the way the WPFF has worked and brings more involvement by the IA’s in the WPFF which can only be welcomed.

• The mandate of the WPFF has been extended for a further 3 years, with the existing three elements continuing: Large Scale CCS Implementation, Future Fossil Fuels and Outreach

• Jared Daniels of the USDOE was elected as Vice Chair to the WPFF on Task 2 CCS implementation.

IEA Activities • The IEA presented a summary of its Medium Term Gas Markets Report of 2013.

(http://www.iea.org/publications/medium-termreports/) Key points to note were: o US gas production has been a game changer in terms of gas production o Air pollution issues in china are leading to increased demand for gas, o Gas demand is forecast to be much lower in Europe due the impacts of the

economy, renewables policies and gas prices. Coal is often cheaper than gas for electricity generation.

• IEA launched this year for the first time an annual Energy Efficiency Market report, see http://www.iea.org/topics/energyefficiency/

• IEA’s Energy Technology Perspectives (ETP)will now be published annually in a slimmed down form. The first version of the new report will come out in May/June 2014. The 2014, issue will offer a global focus on developments in low carbon technology, fossil fuels, energy demand, system integration, and policy and finance It will have a thematic focus which will be :the age of electrification and there will be a country focus which for 2014 is India. The 2015 ETP’s thematic focus will be The Role of Technology and Innovation in Climate negotiations, with China as the partner country. For 2016, it will be Urban Energy systems and Mexico as the partner country.

• In addition, IEA presented an overview of World Energy Outlook 2013 (http://www.worldenergyoutlook.org/) and a new initiative it has launched a Policy and Measures Database. There was a request for assistance in populating this data base from member countries and other IA’s IEAGHG has offered to assist as required although this is more relevant to the IEA CCS unit.

IEA CCS Unit • The CCS unit presented on the seven key findings from the CCS Road Map of 2013.

There is a desire on the CCUs Units part to not let it gather dust but keep it alive by tracking progress annually. They suggested a contact group be formed to help develop detailed metrics, assess available information and data, assess sources for missing data and then the IEA CCS unit can gather, organise, analyse the data. This information will then feed into publications like ETP. Jared Daniels was invited to lead the contact group IEAGHG were invited and agreed to participate also.

• Juho Lipponen presented the IEA’s perspective on the CSLF Ministerial in November 2013. Four ministers (US, CA, UK, NO) were present as well as several high-level ministry the head of the IEA and GCCSI. HE felt that the CSLF communique was forward-looking communiqué with active statements on way

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forward. One of the key emphases: was that action NOW is critical for future success

• Juho also presented on recent activities with China, a work shop on CCS in industry with MOST/NRDC had been held in December 2013. IEAGHG had been invited but could not attend. He indicated that the NDRC are getting more active in CCS space that early phase policy development starting and interest to collaborate with IEA is growing.

High-Level Dialogue on Large-Scale CCS Implementation • This section on the agenda involved 4 presentations on CCS status. One from myself

(focusing on what had happened at an R,D&D level in 2013 – presentation on members web site). The Global CCS Institute presented a summary of its 2013 Annual CCS Status Report. The EU presented on funding opportunities for CCS in its new Horizon 2020 R&D Programme. Jared Daniels p[resented on the status of the RCSP programme and industrial CCS demonstration projects in the USA.

Next Generation Fossil-Fuel Technologies • Although this theme is not core to IEAGHGs work programme, it is more relevant to

IEACCC, there was some discussion with regard to “low hanging fruits for CCS” as some of the processes like CTL this group is looking at can produce high purity CO2 emissions. I volunteered to share the study we have in hand on this topic at the next working party meeting.

Energy Technology Network • The first presentation in this section was from the IEA’s End use Working Party, who

were proposing a cross Working Party Industry Initiative. The aim was to get IA’s in different WPs talking together on common issues which are clearly a good idea. One such issue was CCS in Industry the two key groups here are IEAGHG and IETS who we are already collaborating with. No meeting as such are planned but cross IA webinars are then to be established in May/June 2014. IEAGHG are happy to participate and explore how well this works.

• John Topper presented on IEA CCA’s recent activities, there is little cross over between ours and CCC’s current and planned activities

• The Chair of the IEA EOR agreement gave an interesting presentation on their work focus. They are a cost shared agreement that meets annually. Interest in participation from China and Mexico amongst other is growing. There is no direct focus on CO2-EOR in the group although that may change.

• There was an interesting but unrelated update from the Fluidised Bed Conversion IA. • With regard to the Gas and Oil Technologies IA there was little development to

report. The IA is still developing, they have appointed an operating agent and are looking to populate all 5 task areas with lead organisations, and so far they have only one lead on the gas markets task. Their first ExCo is in Italy in April. IEAGHG offered to attend and o present on our activities but were told it was too early for that as the Safe and Clean Hydrocarbons task had not yet been set up.

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CSLF

IEAGHG and the CSLF Technical Group have a ‘Collaborative Arrangement’ in place since 2007. This agreement allows CSLF to suggest studies into the ExCo voting system. To date, three studies suggested by CSLF have been undertaken: • ‘Development of Storage Coefficients for CO2 Storage in Deep Saline

Formations’. IEAGHG Report 2009/13. Presentation at CSLF TG Mar 2010 • ‘Geological Storage of CO2 in Basalts’, IEAGHG Report 2011/TR2. Presentation

at CSLF TG Sep 2011 • Potential Implications of Gas Production from Shales and Coal for CO2

Geological Storage. IEAGHG Report 2013/10. Presentation at CSLF TG Nov 2013

Two CSLF meetings have been held since the 44th ExCo, the Washington meetings in November 2013 and a Technical Group meeting in Seoul in March 2014. This paper refers to the November meetings, and an update will be given to ExCo on the March meeting by presentation. November 2013 meetings The Carbon Sequestration Leadership Forum (CSLF) held its Fifth Ministerial Meeting in Washington, D.C. This included meetings of the CSLF Technical Group, CSLF Policy Group, related CSLF Task Forces, and the CSLF Ministerial meeting itself. The Ministerial meeting produced a Communique on “Re‐energizing Global Momentum for CCS and Identifying Key Actions Needed for CCS Deployment”. CSLF Technical Group IEAGHG presented an update on activities to the CSLF Technical Group, and presented the IEAGHG study on ‘Implications of Gas Production from Shales and Coal on CO2 Storage’ (undertaken by ARI) which was originally proposed to IEAGHG by CSLF under the ‘Collaborative Arrangement’. The Technical Group presented completed work on a new CCS Technology Road Map, a report on CCS technology status and gaps, a report on transitioning EOR to storage, a report reviewing best practice guides, guidelines and standards. The CSLF Technical Group agreed to re-establish a Task Force on storage capacity characterisation and capacity estimation. The Technical Group discussed new activities on energy penalty, CCS on industrial sources, competition with other resources, negative emission technologies (bio-CCS), and on CO2 transport. Other topics covered in the CSLF meetings were discussions on a new task force on offshore CCS [this is to commence from March 2014], the role of communication on CCS, the role of scientific collaboration on projects. IEAGHG undertakes work in these areas discussed and will assist in the future work in these. IEAGHG’s extensive activities in the Technical Group were also acknowledged and welcomed in the CSLF Policy Group meeting.

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Projects Five new projects were approved as CSLF Recognised Projects. The Uthmaniyah CO2-EOR Demonstration Project is in Saudi Arabia, will capture and store approximately 800,000 tonnes of CO2 per year from a natural gas production and processing facility, and will include a 70km pipeline to the injection site. The project duration is expected to be 4-5 years total, starting in 2013/2014. The Alberta Carbon Trunk Line Project will collect CO2 from two industrial sources (a fertilizer plant and an oil sands upgrading facility) in Canada’s Province of Alberta industrial heartland and transport it via a 240km pipeline to depleted hydrocarbon reservoirs in central Alberta for utilization and storage in EOR projects. Pipeline right-of-way clearing began in February 2013 with commissioning expected in 2014 and start of operations in 2015.

The Kemper County Energy Facility, located in the U.S. state of Mississippi, will use a 582MWe innovative Integrated Gasification Combined Cycle (IGCC) technology with low cost lignite. The project is expected to capture at least 65 percent of the CO2 produced, around 3 Mt pa, which will be used for EOR. As an air-blown IGCC process for power generation, it offers a simpler method for use of low-rank coal than most existing coal-gasification technologies.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) Development Phase Project is designed to inject one million metric tons of carbon dioxide during a span of roughly four years. This project leverages existing enhanced oil recovery operations to inject CO2 into a small number of oil fields located within a carbonate pinnacle reef complex in order to assess potential storage capacity, validate static and numerical models, identify cost-effective monitoring techniques, and develop system wide information to further understanding of other similar rock formations throughout the region. The MRCSP is a multi-year research program led by Battelle.

The Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test and Plant Barry Carbon Dioxide Capture and Storage Project is the largest pilot project of a fully-integrated pulverized coal-fired CCS project in the United States to date, pulling together components of capture (using Mitsubishi Heavy Industries technology on 25MW slip-stream), transportation (15km dedicated pipeline), subsurface storage, and monitoring, verification, and accounting. Project partners include Southern Company, Denbury Resources, and others. It has injected around 100,000t of CO2 to date into the Paluxy saline formation within the Citronelle oil field.

Ministerial Meeting

The CSLF Ministerial Conference included views of leading CEOs relating to projects, and an interesting Ministerial discussion, chaired and lead by Ernest Moniz, the Secretary of Energy for the US. The Ministerial day concluded with a Communique on “Re‐energizing Global Momentum for CCS and Identifying Key Actions Needed for CCS Deployment”. This emphasizes the role of research (which is IEAGHG’s main role in the international CCS arena) amongst other actions. The Communique states that “the research and development (R&D), demonstration and global deployment of Carbon Capture and Storage (CCS) must be accelerated”. It states that key actions are needed on the following areas (summarized here):

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• development of financial frameworks and incentive mechanisms • demonstration and deployment strategies in both the power and industrial sectors, • coordinated efforts on coherent and optimal CCS R&D and demonstrations, and

opportunities through bilateral and multilateral collaboration with other key bodies and organizations including the IEA, the IEAGHG program, and the GCCSI.

• continue to establish permitting frameworks • the need for pre‐commercial geological storage validation • improve understanding among the public and stakeholders of CCS technology • support efforts to grow capacity in CCS and foster appropriate steps in knowledge

sharing. March meeting The CSLF Technical Group and associated Task Forces will meet in Seoul 24-25 March. A new Task Force on Offshore Storage will start, led by the USA. IEAGHG will participate, including giving an update on IEAGHG activities. More information on the CSLF meetings and Communique can be found at http://www.cslforum.net/

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FEEDBACK MEMBERS ACTIVITIES

NOTES

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DATE OF NEXT MEETING

The next scheduled meeting will be the 46th ExCo will be held on the 3rd – 4th October in Austin, Texas, USA prior to GHGT-12 (dates have been revised to accommodate Boundary Dam official opening which will be attended by the Chairman and General Manager. The 47th ExCo will be held spring 2015 Le, Havre France and will be hosted by ADEME. The 48th ExCo will be held in Paris, in the autumn of 2015 hosted by the IEA

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Documents

VIENNA, AUSTRIA - IEAGHG ExCo Papers_email.pdf · Vienna, Austria 29 thto 30 April 2014 ITEM FIRST DAY (08.30 – 17.30hrs) Paper Number 0) Opening Address by Host No Paper 1) Welcome,