7th CSLF MINISTERIAL MEETING DOCUMENTS BOOK

Table of Contents

Meeting Information 1. Overall Schedule of Meeting 2. Meeting Venue Information 3. PIRT Task Force Meeting Agenda (December 3) 4. Technical Group Meeting Agenda (December 4) 5. Policy Group Meeting Agenda (December 5) 6. Ministerial Conference Agenda (December 6)

Policy Group Documents 7. Draft Minutes from Mid-Year Meeting (Abu Dhabi – May 3, 2017) 8. Recommended Revisions to CSLF Terms of Reference 9. Report from CSLF Regulation Task Force: Practical Regulations and Permitting Process for

Geological CO2 Storage

Technical Group Documents 10. Draft Minutes from Mid-Year Meeting (Abu Dhabi - May 1, 2017) 11. Status Summary of Technical Group Action Plan 12. Recommendations from Action Plan Working Group 13. Final Report from CSLF Offshore EOR Task Force

PIRT Documents 14. Draft Summary from Mid-Year Meeting (Abu Dhabi – April 30, 2017) 15. Recommended Revisions to PIRT Terms of Reference

CSLF Background Documents 16. CSLF Charter 17. 2017 CSLF Technology Roadmap 18. Active and Completed CSLF Recognized Projects (as of November 2017)

Meeting Information

7th CSLF Ministerial Meeting Abu Dhabi, United Arab Emirates

03-07 December 2017

Sunday 03 December 2017

Monday 04 December 2017

Tuesday 05 December 2017

Wednesday 06 December 2017

Thursday 07 December 2017

Morning Task Force Meetings

(Tentative) CSLF Technical Group

Meeting CSLF Policy Group

Meeting

Ministerial Conference and

Roundtable

Lunch (Ministers and Heads of

Delegation only)

Visit to Al Reyadah CCUS Project at Emirates Steel

Industries Facility (intended for Ministers and Heads of Delegations only)

Afternoon

Task Force Meetings

CSLF Technical Group Meeting (continues)

CSLF Policy Group Meeting (continues)

Ministerial Conference and

Roundtable (continues)

Press Conference

Evening Dinner and Awards Ceremony

Meeting Venue Information The venue for the 7th CSLF Ministerial Meeting is the Rosewood Hotel, located on Al Maryah Island, not far from downtown Abu Dhabi. All meetings will be held in the conference facilities, located on the First Floor of the hotel.

The 7th CSLF Ministerial Meeting runs from Sunday, December 3 through Thursday, December 7. Room reservations should be made using the downloadable form.

Rosewood Hotel

Other hotel options:

Other hotels are located in close proximity to the Rosewood. Farther away, in downtown Abu Dhabi, there are many hotel options.

hotels in close proximity to the Rosewood

hotels in downtown Abu Dhabi

Draft: 16 August 2017 Prepared by CSLF Secretariat

Draft Agenda

CSLF PROJECTS INTERACTION AND REVIEW TEAM (PIRT) Venue TBA

Abu Dhabi, United Arab Emirates 03 December 2017

14:30-16:45 1. Welcome and Opening Remarks (5 minutes)

Andrew Barrett, PIRT Chair, Australia

2. Introduction of Attendees (5 minutes) Meeting Attendees

3. Adoption of Agenda (2 minutes) Andrew Barrett, PIRT Chair, Australia

4. Approval of Summary from PIRT Meeting of April 2017 (3 minutes) Andrew Barrett, PIRT Chair, Australia

5. Report from Secretariat (10 minutes) • Review of Previous PIRT Meeting (Abu Dhabi, April 2017) • Summary of CSLF Recognized Projects

Richard Lynch, CSLF Secretariat

6. Preview of 2017 CSLF Technology Roadmap (TRM) (15 minutes) Lars Ingolf Eide, Norway

7. Recommended Updates to PIRT and CSLF Terms of Reference (20 minutes) Richard Lynch, CSLF Secretariat Andrew Barrett, PIRT Chair, Australia PIRT Delegates

8. Review of Project Proposed for CSLF Recognition: CO2CRC Otway Project – Stage 3 (30 minutes) Max Watson, CO2CRC, Australia

9. Update from Working Group on Evaluating Existing and New Ideas for Possible Future Technical Group Actions (15 minutes) Åse Slagtern, Technical Group Chair, Norway PIRT Delegates and Meeting Attendees

10. General Discussion and New Business (10 minutes) PIRT Delegates and Meeting Attendees

11. Action Items and Next Steps (5 minutes) Richard Lynch, CSLF Secretariat

12. Closing Comments / Adjourn (5 minutes) Andrew Barrett, PIRT Chair, Australia

CSLF Technical Group Meeting Monday, 4 December 2017 Rosewood Abu Dhabi Abu Dhabi, United Arab Emirates

08:00-09:00 Meeting Registration

09:00-10:30 Technical Group Meeting 1. Welcome and Opening Statement (3 minutes)

Åse Slagtern, Technical Group Chair, Norway

2. Host Country Welcome (5 minutes) Fatima Al Foora Al Shamsi, Assistant Undersecretary, Ministry of Energy, United Arab Emirates

3. Introduction of Delegates (10 minutes) Delegates

4. Adoption of Agenda (2 minutes) Åse Slagtern, Technical Group Chair, Norway

5. Approval of Minutes from 2017 Mid-Year Meeting in Abu Dhabi (2 minutes) Åse Slagtern, Technical Group Chair, Norway

6. Report from Secretariat (8 minutes) • Highlights from April 2017 Mid-Year Meeting in Abu Dhabi • Review of Mid-Year Meeting Outcomes and Actions

Richard Lynch, CSLF Secretariat

7. Update from the IEA Greenhouse Gas R&D Programme (15 minutes) Tim Dixon, Technical Manager, IEAGHG

8. Update from the Global CCS Institute (15 minutes) Jeff Erikson, General Manager for The Americas, GCCSI

9. Update from CO2GeoNet (15 minutes) Ceri Vincent, Executive Committee Chair, CO2GeoNet

10. Report on Mission Innovation Experts Group Workshop (15 minutes) Tidjani Niass, Saudi Aramco, Saudi Arabia

10:30-10:40 Refreshment Break

10:40-11:00 Continuation of Meeting 11. Report from Projects Interaction and Review Team (15 minutes)

Andrew Barrett, PIRT Chair, Australia

12. Preview of 2017 CSLF Technology Roadmap (TRM) (15 minutes) Andrew Barrett, Working Group Chair, Australia Lars Ingolf Eide, TRM Editor, Norway

13. Report from Off-Shore CO2-EOR Task Force (10 minutes) Lars Ingolf Eide, Task Force Chair, Norway

20 November 2017 • Prepared by CSLF Secretariat www.cslforum.org

14. Report from Bioenergy with CCS Task Force (15 minutes)

Mark Ackiewicz, Task Force Chair, United States

15. Report from Improved Pore Space Utilisation Task Force (15 minutes) Max Watson, Task Force Co-Chair, Australia Brian Allison, Task Force Co-Chair, United Kingdom

12:00-13:00 Lunch

13:00-14:45 Continuation of Meeting 16. Report from Industrial CCS Task Force (15 minutes)

Didier Bonijoly, Task Force Chair, France

17. Update from Working Group on Evaluating Existing and New Ideas for Possible Future Technical Group Actions (20 minutes) Lars Ingolf Eide, Working Group Chair, Norway

18. Report on Global CCS Symposium (15 minutes) Mike Monea, International CCS Knowledge Centre, Canada

19. Update on International Test Center Network (15 minutes) Frank Morton, National Carbon Capture Center, United States

20. Results from CSLF-recognized Project: ROAD (20 minutes) Harry Schreurs, RVO, Netherlands

21. Review of Project Nominated for CSLF Recognition: CO2CRC Otway Project – Stage 3 (20 minutes) Max Watson, CO2CRC, Australia

14:45-15:00 Refreshment Break

15:00-17:50 Continuation of Meeting 22. Results from CSLF-recognized Project: Plant Barry Integrated CCS

Project (20 minutes) Christopher Romans, MHI, United States

23. Results from CSLF-recognized Project: Lacq Integrated CCS Project (20 minutes) Dominique Copin, Total, France

24. Results from CSLF-recognized Project: Uthmaniyah CO2-EOR Demonstration Project (20 minutes) Ammar AlShehri, Ministry of Energy, Industry and Mineral Resources, Saudi Arabia

25. Regional Evaluation of the Complete CCS Value Chain (15 minutes) John Harju, University of North Dakota Energy and Environmental Research Center (EERC), United States

26. Overview and Status of the Carbon Storage Data Consortium (20 minutes) Sallie Greenberg, University of Illinois, United States

27. Outcomes and Messages from 2nd International Workshop on Offshore CO2 Storage (15 minutes) Tim Dixon, Technical Manager, IEAGHG

28. Update on Activities of ISO/TC265 (20 minutes) Sallie Greenberg, University of Illinois, United States

20 November 2017 • Prepared by CSLF Secretariat www.cslforum.org

29. Preview of Technical Group Presentation at Ministerial

Conference (15 minutes) Åse Slagtern, Technical Group Chair, Norway

30. Update on Future CSLF Meetings (5 minutes) Richard Lynch, CSLF Secretariat

31. Open Discussion and New Business (10 minutes) Delegates

32. Action Items and Next Steps (5 minutes) Richard Lynch, CSLF Secretariat

33. Closing Remarks / Adjourn (5 minutes) Åse Slagtern, Technical Group Chair, Norway

20 November 2017 • Prepared by CSLF Secretariat www.cslforum.org

27 November 2017 • Prepared by CSLF Secretariat www.cslforum.org

CSLF Policy Group Meeting Tuesday, 5 December 2017 Rosewood Abu Dhabi Abu Dhabi, United Arab Emirates

08:30-09:00 Meeting Registration

09:00-10:15 Policy Group Meeting 1. Welcome and Opening Statement (5 minutes)

Steve Winberg, Policy Group Chair, United States 2. Introduction of Delegates (5 minutes)

Delegates 3. Host Country Welcome (5 minutes)

H.E. Dr. Matar Al Neyadi, Undersecretary of the Ministry of Energy, United Arab Emirates

4. Adoption of Agenda (5 minutes) Steve Winberg, Policy Group Chair, United States

5. Review and Approval of Minutes from May 2017 Policy Group Meeting in Abu Dhabi (5 minutes) Jarad Daniels, Policy Group Chair, United States

6. Report from CSLF Secretariat (10 minutes) • Highlights from May 2017 Mid-Year Meeting • Review of Abu Dhabi Meeting Action Items • Other Updates TBD, CSLF Secretariat

7. Report from CSLF Stakeholders (10 minutes) Barry Worthington, United States Energy Association

8. International Energy Agency CCS Activities Update (15 minutes) Tristan Stanley, International Energy Agency

9. Global CCS Institute Update (15 minutes) Jeff Erikson, Global CCS Institute

10:15-10:40 Refreshment Break

10:40-12:00 Continuation of Meeting 10. Report from CSLF Technical Group (30 minutes)

Åse Slagtern, Technical Group Chair, Norway 11. Report on CSLF Technology Roadmap (TRM) (10 minutes)

Andrew Barrett, TRM Working Group Chair, Australia Lars Ingolf Eide, TRM Editor, Norway

12. Report from Regulatory Task Force (10 minutes) Ryozo Tanaka, Japan

13. Report from the Communications Task Force (10 minutes) Hamoud AlOtaibi, Task Force Chair, Saudi Arabia

14. Report from the Capacity Building Governing Council (10 minutes) Stig Svenningsen, Governing Council Chair, Norway

15. Report from the CSLF Academic Council (10 minutes) Sallie Greenberg, Academic Council Co-Chair, United States

27 November 2017 • Prepared by CSLF Secretariat www.cslforum.org

12:00-13:15 Lunch

13:15-14:55 Continuation of Meeting 16. Report from the Financing for CCS Projects Task Force (10 minutes)

Bernard Frois, Task Force Chair, France 17. Financing CCS (35 minutes)

Nataliya Kulichenko, World Bank Delegates

18. Mission Innovation: Capture Challenge Update (10 minutes) Tidjani Niass, Saudi Arabia

19. Clean Energy Ministerial Update (45 minutes) Jarad Daniels, Policy Group Chair, United States

14:55-15:10 Refreshment Break

15:10-16:35 Continuation of Meeting 20. 2017 CSLF Ministerial Meeting (5 minutes)

Jarad Daniels, Policy Group Chair, United States Delegates

21. Review of Policy Group Messages to Ministers (10 minutes) Jarad Daniels, Policy Group Chair, United States

22. Future CSLF Meetings (5 minutes) TBD, CSLF Secretariat

23. Review of Draft 2017 Ministerial Communiqué (45 minutes) Jarad Daniels, Policy Group Chair, United States

24. Open Discussion and New Business (5 minutes) Delegates

25. Action Items and Next Steps (5 minutes) TBD, CSLF Secretariat

26. Closing Remarks / Adjourn (10 minutes) Jarad Daniels, Policy Group Chair, United States

www.cslforum.org

CSLF Ministerial Meeting Wednesday, 6 December 2017 Abu Dhabi, United Arab Emirates Advancing the Business Case for CCUS

08:30-09:00 Welcome Rick Perry, Secretary of Energy, United States, & CSLF Ministerial Co-Chair Host Country Address H.E. Suhail Mohamed Al Mazrouei, Minister of Energy, United Arab Emirates, & CSLF Ministerial Co-Chair Ministerial Introductions Ministers and Heads of Delegation

09:00-10:00 Scene-Setting Presentations Chair: Ingvil Smines Tybring-Gjedde, State Secretary, Ministry of Petroleum and Energy, Norway • Accelerating Future Deployment of CCUS

Laszlo Varro, Chief Economist, International Energy Agency • The Global Status of CCUS 2017

Brad Page, Chief Executive Officer, Global CCS Institute • CCUS in Industry

Angus Gillespie, Oil and Gas Climate Initiative Executive Committee

10:00-10:30 Key CSLF Perspectives • CSLF Stakeholders

Barry Worthington, Executive Director, United States Energy Association • CSLF Technical Group

Åse Slagtern, CSLF Technical Group Chair, Norway • CSLF Policy Group

Jarad Daniels, CSLF Policy Group Chair, United States

10:30-11:05 Ministerial Photo and Break

11:05-12:05 Panel Session 1: CCUS Infrastructure Development Chair: Leonardo Beltrán Rodríguez, Deputy Secretary for Planning and Energy Transition, Secretariat of Energy, Mexico • The Opportunity for Anthropogenic CO2 and Enhanced Oil Recovery

Patricio Rivera, Occidental Petroleum • Decoupling Capture from Transport and Storage

Gardiner Hill, Vice-Chair, European Zero Emission Technology and Innovation Platform (ZEP)

• Enabling Hubs and Clusters John Gale, General Manager, IEA Greenhouse Gas R&D Programme

• Leveraging Innovative Approaches to Advance Carbon Capture and Conversion Technologies Frank Des Rosiers, Assistant Deputy Minister, Innovation and Energy Technology Sector, Natural Resources Canada, Canada Goran Vlajnic, Executive Director, Carbon Capture and Conversion Institute, Canada

www.cslforum.org

12:05-12:55 Panel Session 2: CCUS Project Showcase – Regional Highlights Chair: H.E. Khalid A. Al-Falih, Minister of Energy, Industry and Mineral Resources, Saudi Arabia • Middle East – Al Reyadah Project in the United Arab Emirates

Arafat Al Yafei, CEO, Al Reyadah, United Arab Emirates • Asia – Tomakomai CCS Demonstration Project in Japan

Jiro Tanaka, Associate General Manager, International Relations Dept., Japan CCS Co., Ltd., Japan

• Europe – Industrial CCS Projects in Norway Ingvil Smines Tybring-Gjedde, State Secretary, Ministry of Petroleum and Energy, Norway

12:55-14:30 Participants Lunch Separate Ministers-Only Lunch

14:30-15:30 Panel Session 3: National and International Policies to Build Business Cases for CCUS Chair: Rick Perry, Secretary of Energy, United States • CCUS Opportunities in the United States

Steven Winberg, Assistant Secretary for Fossil Energy, United States • The Future of CCUS in the United Arab Emirates

H.E. Suhail Mohamed Al Mazrouei, Minister of Energy, United Arab Emirates • CO2 Utilization as a Market Enabler

Ahmad Al Khowaiter, Chief Technology Officer, Saudi Aramco, Saudi Arabia • CCUS in the United Kingdom’s Clean Growth Strategy

Ashley Ibbett, Director of Clean Electricity, Department for Business, Energy and Industrial Strategy, United Kingdom

15:30-16:15 CSLF Ministerial Discussion: International Collaboration, Opportunities, and Actions Needed for CCUS Deployment Chair: H.E. Suhail Mohamed Al Mazrouei, Minister of Energy, United Arab Emirates Summary of the Panels Statements / Remarks from Ministers and Heads of Delegation Potential Actions Identified

16:15-16:45 CLOSED SESSION: Ministerial Communiqué

16:45-17:05 Press Conference

Policy Group Documents

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Draft Minutes of the Policy Group Meeting

Abu Dhabi, United Arab Emirates May 4, 2017

LIST OF ATTENDEES Policy Group Delegates Australia: Sarah Chapman Brazil: Maria Cristina de Castro Martins Canada: Kathryn Gagnon China: Ping Zhong Czech Republic: Lubomir Mazouch European Commission: Jeroen Schuppers France: Didier Bonijoly, Bernard Frois Italy: Sergio Persoglia, Paolo Deiana Japan: Takashi Kawabata Korea: Chong Kul Ryu, Mi Hwa Kim Netherlands: Harry Schreurs Norway: Stig Øyvind Uhr Svenningsen Saudi Arabia: Hamoud AlOtaibi (Vice Chair) South Africa: Landi Themba United Arab Emirates: Meshayel Omran AlAli, Fatima Alfoora Alshamsi United Kingdom: Brian Allison (Vice Chair) United States: Jarad Daniels (Chair) Representatives of Allied Organizations Global CCS Institute: Jeff Erikson IEA: Tristan Stanley CSLF Secretariat Stephanie Duran, Richard Lynch Invited Speakers Australia: Andrew Barrett (PIRT Chair) Tania Constable, CO2CRC Lebanon: Radia Sedaoui, United Nations ESCWA Norway: Åse Slagtern (Technical Group Chair) Lars Ingolf Eide United Arab Emirates: Arafat AlYafei, Abu Dhabi Carbon Capture Company Mohammad Abu Zahra, Masdar Institute United Kingdom: Emrah Durusut, Element Energy United States: Sallie Greenberg, University of Illinois Dipka Bhambani, United States Energy Association

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Observers Australia: Max Watson* China: Yi-Ming Wei India: Shishir Tamotia Korea: Chang-Keun Yi* Japan: Ryozo Tanaka*, Jiro Tanaka Saudi Arabia: Pieter Smeets, Wolfgang Heidug South Africa: Tony Surridge* United Arab Emirates: Ahmed AlHajaj, Reshma Francy United Kingdom: Jon Gibbins, Tom Howard-Vyse *CSLF Technical Group Delegate 1. Welcome and Opening Statement

Jarad Daniels, Policy Group Chair, United States, called the meeting to order and thanked the Ministry of Energy for hosting.

2. Introduction of Delegates Delegates around the table introduced themselves.

3. Meeting Host’s Welcome Eng. Fatima Alfoora Alshamsi, Assistant Undersecretary for Electricity, Renewable, and Desalination of Water, Ministry of Energy, United Arab Emirates, welcomed the attendees and provided the host country remarks. Her remarks highlighted the UAE’s investments and leadership in carbon capture, utilization, and storage (CCUS) technologies and their role in the country’s Energy Strategy 2050. She also stressed that CCUS technology must play an important role in the energy and environment. The CSLF plays an important role as a forum for collaboration.

4. CCUS in the Middle East Arafat Al Yafei, Abu Dhabi Carbon Capture Company, spoke on CCUS in the Middle East and current activities aimed at furthering development. Saudi Aramco, Abu Dhabi National Oil Company (ADNOC), and Masdar recently signed an MOU to collaborate more closely on CCUS in the Gulf Region. The UAE is hosting a Qatari delegation to Abu Dhabi to highlight CCUS, and will also meet with Kuwait on CCUS in the autumn. In addition, the Gulf Cooperation Council will meet in October on CCUS in the region. There are a number of key reasons why the UAE is pursuing CCUS: 1) there is demand for carbon dioxide (CO2) in the oil and gas industry; 2) the UAE has the capacity and resources to invest in CCUS efforts and there is a will to invest in this space; 3) the UAE now has experience with CCUS and other clean energy technologies and has geopolitical interests in sharing knowledge globally; 4) geographically, the UAE is relatively small so it is possible to obtain CO2 from sources close to the oil fields, thereby reducing the cost of transportation; 5) the UAE has a commitment to reduce carbon emissions by 70% by 2050; 6) high growth rates are expected, and demand for power will increase, therefore, there is a need for new investments in energy; and 7) the population is small and young with a willingness to accept new technologies. Generally, the will to cooperate in the UAE is very high.

5. Adoption of Agenda The agenda was adopted with minor changes to the timing and order of presentations.

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6. Review and Approval of Minutes from Tokyo Meeting

The Minutes from the CSLF Policy Group Meeting on October 7, 2016, in Tokyo, Japan were approved with one minor change. There was a suggestion from the Secretariat to modify the meeting minutes to change the wording in item #25 on future CSLF meetings, specifically regarding the planned Ministerial Communiqué. The word “greater” should be replaced with “lower.”

7. Report from Secretariat Stephanie Duran, CSLF Secretariat, provided a brief summary of the action items from the CSLF Policy Group Meeting on October 7, 2016, in Tokyo, Japan. All action items have been completed or are currently in progress.

8. Report from CSLF Technical Group

Åse Slagtern, Technical Group Chair, Norway, provided a summary of the Technical Group activities from the recent CSLF Technical Group Meeting on May 1, 2017. At the Technical Group Meeting, technical CSLF topics included an update on the 2017 CSLF Technology Roadmap (TRM), which is undergoing a “refresh,” with the rollout set for the 2017 CSLF Ministerial meeting. There were also updates from four Technical Group task forces: the Off-Shore CO2-EOR Task Force, the Bioenergy with CCUS Task Force, the Improved Pore Space Utilization Task Force, and the Industrial CCUS Task Force. Representatives from allied organizations such as the International Energy Agency Greenhouse Gas Programme (IEAGHG), the Global CCUS Institute (GCCUSI), and ISO/TC265 also provided updates; this was followed by a preview of the upcoming Mission Innovation Capture Challenge Experts’ Workshop. Invited presentations included the following topics: an overview of CCUS-related activities in UAE; CO2 utilization in industry (overview, prospects, and recommendations); non-EOR CO2 utilization (brine extraction and storage); results from CSLF recognized projects (Uthmaniyah CO2-EOR Project and Illinois Industrial CCUS Project); and an update on carbon storage data consortium. Meeting outcomes included the draft TRM 2017 being open for comments, three new projects recommended for CSLF recognition, a timeline for three task forces to give recommendations at the upcoming Ministerial meeting, a working group to revisit the Technical Group Action Plan (including new and prioritized actions), and a revision of the CSLF submission form and engagement form templates (to include purpose of recognition). A group of consisting of the Technical Group Chair, the PIRT Chair, the Communications Task Force Chair, and delegates from Italy and the Netherlands will explore definition of criteria for project recognition; if necessary, language in the PIRT TRM and CSLF Charter will be evaluated to determine criteria for future project recognition. The Group will make recommendations at the next Policy Group meeting on criteria for recognition and any changes that may need to be made to governing documents. Three new projects were recommended for CSLF recognition: Al Reyadah CCUS Project; the Carbon Capture Simulation Initiative/Carbon Capture Simulation for Industry Impact (CCUSI/CCUSI2); and the National Risk Assessment Partnership (NRAP). The Policy Group accepted the Technical Group’s recommendation and approved all three projects as CSLF-recognized projects.

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As part of a discussion on project recognition, several countries voiced concern about CCSI and NRAP, raising the possibility that the projects may not necessarily fit the project criteria. Other countries noted that while some previously recognized projects did not fit the criteria, it is worth focusing on the results of projects, and their ability to add value and fill knowledge gaps. There is support for reviewing and revising the criteria for recognition and project classification, but additional steps need to be taken. The Communications Task Force may be well placed to play a role in supporting PIRT to determine project recognition criteria.

9. Summary of CSLF Workshop

Mohammad Abu Zahra, Masdar Institute, UAE, provided a summary of the 2017 Technical Workshop on May 2, 2017. The technology-oriented workshop featured three sessions: Status of CCUS—Current and Future Global Developments; Spotlight on Carbon Capture; Carbon Utilization—Challenges and Opportunities; and How to Get Cost-Effective CCUS at Industrial Scale. These sessions included case studies on established projects in the Middle East as well as those in other regions. The workshop drew speakers and participants from industry, research groups, government, and academia.

10. Summary of CCUS Workshop in Bahrain

Radia Sedaoui, United Nations Economic and Social Commission for Western Asia (UNESCWA), provided a summary of the Workshop on Deployment of Carbon Capture, Use and Storage in the Arab Region, organized by UNESCWA and held in Bahrain on February 19, 2017. The workshop’s objective aimed to explore challenges and opportunities for wide-scale deployment of CCUS and examine its effect in the region within the broader context of economic concerns and regional and international environmental law. Topics at the workshop included: global perspective and role for climate response; accelerating CCUS deployment (challenges and opportunities); obtaining value from CO2 (economic perspective and experience from GCC countries); and CCUS as a platform for Arab regional collaboration. A key conclusion focused on the necessary role of the energy-water nexus, especially in the GCC region.

11. Report on CSLF Technology Roadmap (TRM) Andrew Barrett, TRM Working Group Chair, and Lars Ingolf Eide, TRM Editor, provided a report on the CSLF Technology Roadmap (TRM). This presentation covered an overview of the update process, main changes from the 2013 version of the roadmap, findings, and recommendations. The main recommendations included government and industry collaboration on implementing large-scale projects; developing policy incentives, markets, and business models; accelerating legal and regulatory frameworks for CCUS; develop strategic infrastructure (hubs, clusters, and storage sites); improve outreach, education, and communication; support research, development and demonstration (RD&D) for emerging technologies; and continue to map opportunities, perform assessments, and resolve barriers to implementation. An open discussion followed on several topics, including: gauging and achieving realistic goals; managing use and revision of figures; simplifying language and standardizing use of CCUS throughout the report; and integrating coverage of hydrogen production and use in the roadmap. July 1st has been set as the deadline for comments from Technical Group delegates, with the final draft on track to be submitted to the Secretariat on September 15th. The final version will be ready for publication on November 1st.

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12. Report from the Financing for CCUS Projects Task Force Bernard Frois, Task Force Chair, provided a report on the Financing for CCUS Projects Task Force. This presentation highlighted factors required for financing: market pull, technology push, and regulatory and business drivers. The Petra Nova, Boundary Dam, and Al Reyadah projects are cited as examples where one or more of these factors played a role. Financial institutions are hesitant for a variety of reasons, including policy shifts, little or no progress in some areas, economic risks, and lack of incentives and regulatory framework. Therefore, a stable energy policy is necessary for financing CCUS projects. A study by the Coal Utilization Research Council lists several findings, some of which note that: regulatory and business drivers play major roles; an over-reliance on government subsidies may be risky; successful projects have used multiple financing components; and projects with shorter timelines may be more successful. Overall, there is reasonable optimism due to the success of commercial projects such as Al Reyadah and the considerable experience of CO2-EOR technology, but financing will require stability and clear business models. The group discussed potential paths forward, such as increasing outreach and engagement with the financial community, while noting that governments may also benefit from this approach, especially in a situation where projects face difficulty in securing private investment.

13. Business Case for Industrial CCUS Clusters

Emrah Durusut, Element Energy, spoke on enabling the deployment of industrial CCUS clusters, drawing on two completed projects--one for IEAGHG and the IEA CCUS Unit (“Enabling Industrial CCUS Clusters”) and another for a group of oil and gas companies on CCUS market mechanisms—and a third project, currently in progress, for the European Climate Foundation (“European Funds and Financing Mechanisms for Industrial CCUS Clusters in Europe”). Large-scale CCUS projects, delivered on time and on budget, are required to educate project developers, governments, and investors. Several steps need to be taken: address the issue of carbon leakage; provide certainty to motivate investment industrial capture through subsidies; de-link transport and storage from capture business; and provide government back-stops to ensure sufficient public-private risk sharing. Key actions were suggested, including recommendations to: clarify specific role(s) of CCUS in each region considering decarbonization pathways/timelines; decide whether further demonstration or education is required for each application; focus on the value of CCUS (such as job losses or gains, tax revenues); and engaging in collaboration to enable timely deployment of CCUS.

14. Large Scale Pilot Projects Study (CURC/NEDO)

Jarad Daniels, Policy Group Chair, United States, provided a summary of the Carbon Utilization Research Council study on options for funding large-scale pilot plants, which aimed to investigate options to overcome barriers to financing large-scale pilot projects for fossil fuel-based power plants with CCUS. The April 2017 report (in draft form) follows on an earlier March 2016 report on lessons learned, and a November 2014 workshop focused on gaining private sector perspective on support for large pilot scale power projects with CCUS; phase 2 of the report is due in May 2017. The study found that while large pilots are a critical step in technology development, barriers still remain, including financial challenges, demonstrating a persuasive business case, and low government priority compared to other low-carbon technologies. Policy and financial incentives are necessary, in addition to government support of large pilot projects; non-traditional sources of financial support should also be pursued. Multilateral collaboration

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on financing may be important, but will need to be targeted. The long-term nature of collaborations and projects will need policy stability.

15. Pinpointing Risk to Cut CCUS Regulatory Costs

Tania Constable, CO2CRC, spoke on managing risks to decrease the regulatory costs of CCUS. This presentation specifically noted the developing case for the Otway Stage 3 Project, where monitoring demonstration is addressing several key aspects of CCUS regulation. Due to time constraints, this presentation will be moved to the next Policy Group meeting which will take place in December 2017.

16. Report from the Communications Task Force

Hamoud AlOtaibi, Task Force Chair, provided an update from the CSLF Communications Task Force. The task force’s current strategy is aimed at expanding strategic engagement, simplifying CSLF messaging, identifying a message delivery mechanism, and refreshing the CSLF’s digital profile through its website. Key activities completed recently included:

• Joint Ministerial letter to UNFCCC at COP22 • CSLF Ministerial Side-Event at COP22 • Media Kit (CSLF Background Briefing) • Global Media List • Forward CCUS Calendar

Ongoing activities include website development, CSLF Ministerial and stakeholder liaison, key message development (in context of 2017 CSLF Ministerial Communique), and facilitation of media and stakeholder briefings on CSLF activities. There are several upcoming events to target, which include the Clean Energy and Mission Innovation ministerial meetings (June), four CSLF regional stakeholder workshops (May-December), UNFCCC at COP23 (November), and the 7th CSLF Ministerial Meeting (December). The task force will continue work on media strategies for COP23 and the CSLF Ministerial Meeting.

17. Report from CSLF Stakeholders

Dipka Bhambani, United States Energy Association, provided a CSLF Stakeholders’ Message to the Policy Group. The CSLF Stakeholders proposed a new approach to conduct four regional meetings before the 2017 CSLF Ministerial Meeting. Each meeting will follow a set format governing panels, topics, and discussions; a regional action will be spearheaded by a nominated champion. As part of each meeting, a universal survey will also be distributed to all meeting participants to gather baseline data; results will be displayed collectively on the CSLF website to ensure a transparent and consistent mechanism for stakeholder feedback. Information from taskforces, the secretariat survey, and written statements from regional meetings will be synthesized by all four champions into a set of recommendations to be delivered at the ministerial meetings. Regional stakeholders were selected, and dates have been set for three meetings; to date, the Americas meeting, scheduled for late May, has been recently completed.

18. Report from the CSLF Academic Council

Sallie Greenberg, University of Illinois, provided a report from the CSLF Academic Council. The presentation highlighted progress in the three focus areas: Student Training, Practical Learning, and Curriculum Development; Communications and Outreach; and Academic Community and Capacity Building. Area 1 activities included: updated baseline survey and plan of action; draft gap analysis; identification of modularized

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content; and identification of internships and potential for government to host interns. Area 2 activities included: creation of a dedicated webpage; launch of a quarterly webinar series; creation of linkages to resources; acting as a repository for academic materials and funding information; and identifying country specific contacts for continuous updates. Area 3 activities included: refining of stakeholder engagement strategy and communications plan; collaboration with Capacity Building Governing Council; discussion of development of study tours; and development of stakeholders guidelines and engagements objectives document. The following recommendations to the Policy Group were identified:

• Leverage existing synergies between task forces to strengthen messaging • Evaluate and refine understanding of community stakeholder engagement needs • Design and conduct consultation process to generate CSLF guidelines for

community stakeholder engagement, with support from CSLF • Further engage and explore connections for Academic Council to support Policy

Group 19. Report from the Capacity Building Governing Council

Stig Svenningsen, Acting Capacity Building Governing Council Chair, Norway, summarized the status of the CSLF Capacity Building Program. The CSLF Capacity Building Fund was established by the CSLF Ministers at the 2009 CSLF Ministerial in London, and contributions committed total US $2,965,143.75, with donors from Australia (via the Global CCUS Institute), Canada, Norway, and the United Kingdom. To date, the Governing Council has approved 19 capacity building projects in 6 countries, with 13 projects completed and 6 projects in progress. Since October, the Governing Council met via teleconference on March 17th and in person on May 3rd to review in-progress projects and to discuss revisions to the Terms of Reference. One proposal submitted by SANEDI (South Africa) in late March—requesting utilization of remaining funds from an earlier project to fund travel to a workshop—was approved by the Governing Council and the Global CCUS Institute. Current next steps include negotiation of two tentative proposed project, a review of proposed revisions to the Terms of Reference by Governing Council members, creation of list of target countries for potential engagement, and a teleconference which is likely to be held in June or July. The CSLF Capacity Building Governing Council will also engage the CSLF Academic Taskforce to seek synergies.

20. Report on Proposed Regulatory Task Force

Takashi Kawabata, METI, Japan, provided a report on the Regulatory Task Force. This task force was proposed by Japan at the 2016 CSLF Annual Meeting, with the purpose of defining reasonable regulations on CCUS. This was prompted by the suspension of CO2 injection at the Tomakomai project offshore storage site following an increase in CO2 levels. The objective of the task force is to explore practical CCUS regulations that contribute to smooth planning, development, and operation of CCUS projects. The outcomes will include a report of case studies, findings, and recommendations. Throughout the late spring and summer, case studies will be finalized, submitted, and compiled; a draft report will be created in the fall and circulated in the Policy and Technical Groups. The report will then be finalized in late November. It was recommended that the GCCSI and operational projects share information on regulatory frameworks and lessons learned. Several countries offered to facilitate participation from their technical counterparts or to provide assistance to the task force. The task force should note that it should explore other regimes, as the London Protocol does not cover EOR.

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21. International Energy Agency (IEA) CCUS Activities Update

Tristan Stanley, International Energy Agency (IEA), presented on CCUS activities within the International Energy Agency. The presentation highlighted the release of 20 Years of CCUS: Accelerating Future Deployment, which focuses on the need for accelerated deployment and industrial CCUS in meeting emissions targets. While significant progress has been made over the past two decades, policy support and investment has fluctuated. Meeting the 2 degree target requires a portfolio of multiple technologies; CCUS is projected to deliver 15% of the emissions reductions required but it is still lagging. Progress will require incentives, infrastructure, and support of an innovation chain to advance technologies. Upcoming events and publications were showcased, including Energy Technology Perspectives 2017, World Energy Investment 2017, and World Energy Outlook 2017.

22. Global CCS Institute Update

Jeff Erikson, Global CCS Institute (GCCSI), presented an update on the global status of CCUS. The Institute’s recent publication, Global Status of CCS, released in April, shows that while progress continues to be made, it is not meeting the scale and speed required. Globally, there are 22 large scale CCUS projects in operation, with seven facilities in advanced planning, and 11 in earlier stages. Together, these will capture 40 Mtpa of CO2, which is a fraction of the 4,000 Mtpa of CO2 that will need to be captured and stored by 2040 under the IEA’s 2 degree scenario (2DS). Effective communication and engagement (policymakers, business leaders, financiers, and influencers) are both required to accelerate progress; engagement especially affects innovation, policy, finance, and facilities. Strong policy in particular drives investment; the success of renewable energy technologies is used as an example to demonstrate the need for a strong policy framework. To drive policy change, decision makers and opinion leaders are the main audiences to target, with the public playing a smaller role (both engaged members and the general public). The narrative on CCUS itself needs to show that it is versatile, affordable, profitable, and essential.

23. Clean Energy and Mission Innovation Ministerial Meetings

Ping Zhong, ACCA21, China, provided an update on the Clean Energy and Mission Innovation Ministerial Meetings which will be held in Beijing from June 6-8. The meeting agendas and logistics were reviewed, along with several new initiatives and campaigns that are due to be launched. In addition to numerous side events, public-private roundtables and a dedicated summit will also take place during the meeting week.

24. Mission Innovation: Capture Challenge Update

Stephanie Duran, CSLF Secretariat, provided an update on the Mission Innovation Carbon Capture Challenge, which is co-led by the United States and Saudi Arabia. This challenge has set several goals, including an experts’ workshop to discuss basic research needs for CCUS, establishing strategic partnerships, and exploring ways to engage industry. The experts’ workshop will be held in the fall, with dates tentatively set for September 25-29 in the United States. The workshop will cover an entire week and will include a CCUS project site visit and a reporting and technical committee meeting. A report on the workshop will be published by the end of 2017. Future work will include an update of the Capture Challenge overview document, regular updates to MI Steering Committee and others, and engagement with the private sector.

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25. Clean Energy Ministerial Update Tristan Stanely, IEA, provided an update on the Clean Energy Ministerial, specifically focusing on the CEM Secretariat and its work on building partnerships. IEA now hosts the CEM Secretariat, which was previously held by the U.S. Department of Energy. The upcoming Ministerial meeting aims to focus on transitioning from post-Paris rhetoric to action, drive implementation of clean energy policies to meet NDCs, leverage political engagement of ministers for ambitious policies and actions, and partner with private sector leaders for major commitments and actions. CCUS is implicitly part of the CEM agenda, but there has been little to no activity over past few years. IEA is organizing a Ministerial side-event on CCUS during the upcoming meeting on June 6th in Beijing; this event will be co-hosted by MOST. Invitations have been sent to several IEA and CEM ministers, as well as two CEOs from IEA Executive Director Fatih Birol. The event will include two sessions—“The role and status of CCUS” and “Where to go from here?”—with the goal of issuing a statement by attending ministers on bringing CCUS back into CEM and setting a way forward.

26. Planning for Upcoming CSLF Ministerial Meeting Stephanie Duran, CSLF Secretariat, and Meshayel Omran AlAli, United Arab Emirates, stated that planning was underway for 2017 CSLF Ministerial Meeting, which will be held in Abu Dhabi from December 3-7. The venue has been set for the ministerial day meeting, but a venue has not yet been set for the Policy and Technical Group meetings. More information will be provided in the coming months.

27. Future CSLF Meetings

Australia has stated that it will host the 2018 CSLF Annual Meeting on the margins of the IEAGHGT meeting in October. Additional details will follow. We are still seeking a host for the CSLF Mid-Year Meeting.

28. Ministerial Communiqué Jarad Daniels, Policy Group Chair, United States, led the discussion regarding the draft CSLF Ministerial Communiqué. The goal is to sustain momentum from the previous Ministerial meeting and to keep actions consistent with ongoing policy conversations. The current format of the draft communiqué offers a concise message with key follow-on actions for ministers. Suggested topics to incorporate include greater focus on utilization, collaborative research and development, sharing information, and leading on public engagement. Another suggestion to move toward using “CCUS” instead of “CCS” gained support of several delegates, but discussion will continue throughout the drafting process. It was agreed that the Ministerial Steering Committee and the CSLF Secretariat will continue to push forward toward the CSLF Ministerial Meeting and developing the Communiqué, while communicating with the Policy Group at large throughout the next few months. This agenda item was only open to CSLF Delegates; observers were asked to leave the room.

29. Open Discussion and New Business No new business items were discussed.

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30. Action Items and Next Steps

Stephanie Duran, CSLF Secretariat, provided a summary of the day’s Policy Group Meeting, and noted the significant agreements and action items. The Policy Group reached a consensus on the following items:

• Approved the Al Reyadah, CCUSI, and NRAP projects for CSLF recognition; these projects will be added to the CSLF website

• The Regulatory Task Force was officially stood up to develop and evaluate regulatory case studies, and will report out in November

• Australia noted that it intends to join the Mission Innovation Carbon Capture Challenge

Action items from the meeting are as follows:

Item Lead Action

1 Technical Group Chair, PIRT Chair, Chair of Communications Task Force; Italy and Netherlands

Explore definition of criteria for project recognition; if necessary, language in PIRT TRM and CSLF Charter will be evaluated to determine criteria for future project recognition. The Group will make recommendations at the next Policy Group meeting on criteria for recognition and any changes that may need to be made to governing documents.

2 All delegates Submit comments on TRM to Andrew Barrett (PIRT). Each delegation is asked to submit one comment.

3 CSLF Secretariat Send out completed CURC report; if appropriate, this can be posted on the CSLF website

4 CSLF Delegates Send any comments or suggestions on CCUS financing to Bernard Frois and the CSLF Secretariat

5 CSLF Secretariat Send out CCUS events list/calendar to delegates for input – COMPLETED

6 CSLF Secretariat Send out new country page templates to countries for their updates

7 CSLF Secretariat Send out updated media kit

8 Regulatory Task Force Will develop and evaluate regulatory case studies and issue report in November (in advance of Ministerial)

9 CSLF Secretariat Will reach out to eNGO community on Ministerial communique

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31. Closing Remarks / Adjourn Jarad Daniels, Policy Group Chair, United States, closed the meeting. He also highlighted the approval of three new CSLF-recognized projects. He thanked all of the participants and by thanking the government of the UAE for hosting the event.

POLICY GROUP

Recommended Revisions to CSLF Terms of Reference

Background At the May 2017 CSLF Mid-Year Meeting in Abu Dhabi, the CSLF Policy Group requested that the CSLF Technical Group and the CSLF Communications Task Force review and update procedures for CSLF project recognition procedures. The issue was that project recognition is described in both the CSLF Terms of Reference and the PIRT Terms of Reference, and the language in these documents does not agree with each other.

In the months following the 2017 Mid-Year Meeting, a working group consisting of the Technical Group Chair and Vice Chairs, PIRT Chair, Communications Task Force Chair, and CSLF Secretariat extensively reviewed both Terms of Reference documents and recommended changes which fall into three categories: (a) updating project recognition procedures; (b) consistency with the CSLF Charter; and (c) other miscellaneous corrections and updates.

This paper, prepared by the CSLF Secretariat, is an annotated draft of the proposed revisions to the CSLF Terms of Reference, and incorporates changes recommended by the working group. Deletions are shown as strikethrough text and insertions are shown as underlined text. Annotations describing these proposed changes are shown in [[bracketed italicized text]]. Action Requested The Policy Group is requested to review the annotated document.

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CARBON SEQUESTRATION LEADERSHIP FORUM TERMS OF REFERENCE AND PROCEDURES

These Terms of Reference and Procedures provide the overall framework to implement the Charter of the Carbon Sequestration Leadership Forum (CSLF). They define the organization of the CSLF and provide the rules under which the CSLF will operate. 1. Organizational Responsibilities 1.1. Policy Group. The Policy Group will govern the overall framework and policies of the CSLF in line with Article 3.2 3.3 of the CSLF Charter. The Policy Group is responsible for carrying out the following functions of the CSLF as delineated in Article 2 of the CSLF Charter:

• Identify key legal, regulatory, financial, public perception, institutional-related or other issues associated with the achievement of improved technological capacity.

• Identify potential issues relating to the treatment of intellectual property. • Establish guidelines for the collaborations and reporting of results. • Assess regularly the progress of collaborative projects and activities, and following reports

from the Technical Group make recommendations on the direction of such projects and activities. A collaborative project or activity is one that results from cooperation between the CSLF and its stakeholders and/or sponsors of recognized projects (as per Section 4.1 below).

• Ensure that CSLF activities complement ongoing international cooperation in this area. Consider approaches to address issues associated with the above functions.

In order to implement Article 3.2 3.3 of the CSLF Charter, the Policy Group will:

• Review all projects and activities for consistency with the CSLF Charter. • Consider recommendations of the Technical Group for appropriate action. • Annually review the overall program of the Policy and Technical Groups and each of their

activities. • Periodically review the Terms of Reference and Procedures.

The Chair of the Policy Group will provide information and guidance to the Technical Group on required tasks and initiatives to be undertaken based upon decisions of the Policy Group. The Chair of the Policy Group will also arrange for appropriate exchange of information between both the Policy Group and the Technical Group.

[[ The change from “projects” to “projects and activities” (in this section and below) is recommended to reflect the current practice of the CSLF engaging more than just sponsors of CSLF-recognized projects.

The change from “3.2” to “3.3” (in this section and below) is recommended because the Policy Group is described in Section 3.3 of the Charter, not Section 3.2. ]]

1.2. Technical Group. The Technical Group will report to the Policy Group and make recommendations to the Policy Group on needed actions in line with Article 3.3 of the CSLF Charter.

Proposed revisions

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The Technical Group is responsible for carrying out the following functions of the CSLF as delineated in Article 2 of the CSLF Charter:

• Identify key technical, economic, environmental and other issues related to the achievement of improved technological capacity.

• Identify potential areas of multilateral collaboration on carbon capture, transport and storage technologies.

• Foster collaborative research, development, and demonstration (RD&D) projects and activities reflecting Members’ priorities.

• Assess regularly the progress of collaborative projects and activities, and make recommendations to the Policy Group on the direction of such projects and activities.

• Establish and regularly assess an inventory of the potential areas of needed research. • Facilitate technical collaboration with all sectors of the international research community,

academia, industry, government and non-governmental organizations. • Consider approaches to address issues associated with the above functions.

In order to implement Article 3.2 3.4 of the CSLF Charter, the Technical Group will:

• Recommend collaborative projects and activities to the Policy Group. • Set up and keep procedures to review the progress of collaborative projects and activities. • Follow the instructions and guidance of the Policy Group on required tasks and initiatives

to be undertaken.

[[ The change from “3.2” to “3.4” is recommended because the Technical Group is described in Section 3.4 of the Charter, not Section 3.2. ]]

1.3. Secretariat. The Secretariat will carry out those activities enumerated in Section 3.5 3.6 of the CSLF Charter. The role of the Secretariat is administrative and the Secretariat acts on matters of substance as specifically instructed by the Policy Group. The Secretariat will review all Members material submitted for the CSLF web site and suggest modification where warranted. The Secretariat will also clearly identify the status and ownership of the materials. 2. Additions to Membership 2.1. Application. Pursuant to Article 4 of the CSLF Charter, national governmental entities may apply for membership to the CSLF by writing to the Secretariat. A letter of application should be signed by the responsible Minister from the applicant country. In their application letter, prospective Members should:

1) demonstrate they are a significant producer or user of fossil fuels that have the potential for carbon capture;

2) describe their existing national vision and/or plan regarding carbon capture, utilization and storage (CCUS) technologies;

3) describe an existing national commitment to invest resources on research, development and demonstration activities in CCUS technologies;

4) describe their commitment to engage the private sector in the development and deployment of CCUS technologies; and

5) describe specific projects or activities proposed for being undertaken within the frame of the CSLF.

The Policy Group will address new member applications at the Policy Group Meetings.

[[ The change from “CCS” to “CCUS” (in this section and below) is recommended to be consistent with the CSLF Charter, which uses that terminology. ]] 2.2. Offer. If the Policy Group approves the application, membership will then be offered to the national governmental entity that submitted the application.

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2.3. Acceptance. The applicant national governmental entity may accept the offer of membership by signing the Charter in Counterpart and delivering such signature to the embassy of the Secretariat. A notarized “true copy” of the signed document is acceptable in lieu of the original. The nominated national governmental entity to which an offer has been extended becomes a Member upon receipt by the Secretariat of the signed Charter. 3. CSLF Governance 3.1. Appointment of Members’ Representatives. Members may make appointments and/or replacements to the Policy Group and Technical Group at any time pursuant to Article 3.1 of the CSLF Charter by notifying the Secretariat. The Secretariat will acknowledge such appointment to the Member and keep an up-to-date list of all Policy Group and Technical Group representatives on the CSLF website.

[[ The deletion of “on the CSLF website” is recommended because due to privacy concerns the Secretariat no longer keeps delegates’ personally identifiable information accessible via the Internet. ]]

3.2. Meetings.

a) The Policy Group should meet at least once each year at a venue and date selected by a decision of the Members.

b) Ministerial meetings will normally be held approximately every other year. Ministerial meetings will review the overall progress of CSLF collaboration, findings, and accomplishments on major carbon capture and storage issues and provide overall direction on priorities for future work.

c) The Technical Group will meet as often as necessary and at least once each year at a considered time interval prior to the meeting of the Policy Group.

d) Meetings of the Policy Group or Technical Group may be called by the respective Chairs of those Groups after consultation with the members.

e) The Policy and Technical Groups may designate observers and resource persons to attend their respective meetings. CSLF Members may bring other individuals, as indicated in Article 3.1 of the CSLF Charter, to the Policy and Technical Group meetings with prior notice to the Secretariat. The Chair of the Technical Group and whomever else the Technical Group designates may be observers at the Policy Group meeting.

f) The Secretariat will produce minutes for each of the meetings of the Policy Group and the Technical Group and provide such minutes to all the Members’ representatives to the appropriate Group within thirty (30) days of the meeting. Any materials to be considered by Members of the Policy or Technical Groups will be made available to the Secretariat for distribution thirty (30) days prior to meetings.

3.3. Organization of the Policy and Technical Groups

a) The Policy Group and the Technical Group will each have a Chair and up to three Vice Chairs. The Chairs of the Policy and Technical Groups will be elected every three years. 1) At least 3 months before a CSLF decision is required on the election of a Chair or Vice

Chair a note should be sent from the Secretariat to CSLF Members asking for nominations. The note should contain the following:

“Nominations should be made by the heads of delegations. Nominations should be sent to the Secretariat. The closing date for nominations should be six weeks prior to the CSLF decision date.”

2) Within one week after the closing date for nominations, the Secretariat should post on the CSLF website and email to Policy and Technical Group delegates as appropriate the

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names of Members nominated and identify the Members that nominated them. 3) As specified by Article 3.2 3.3 of the CSLF Charter, the election of Chair and Vice

Chairs will be made by consensus of the Members. 4) When possible, regional balance and emerging economy representation among the

Chairs and Vice Chairs should be taken into consideration by Members.

b) Task Forces of the Policy Group and Technical Group consisting of Members’ representatives and/or other individuals may be organized to perform specific tasks including revision of the CSLF Technology Roadmap as agreed by a decision of the representatives at a meeting of that Group. Meetings of Task Forces of the Policy or Technical Group will be set by those Task Forces.

c) The Chairs of the Policy Group and the Technical Group will have the option of presiding over

the Groups’ meetings. Task Force leaders will be appointed by a consensus of the Policy and Technical Groups on the basis of recommendations by individual Members. Overall direction of the Secretariat is the responsibility of the Chair of the Policy Group. The Chair of the Technical Group may give such direction to the Secretariat as is relevant to the operations of the Technical Group.

[[ The addition of “including revision of the CSLF Technology Roadmap” is recommended to give greater emphasis to the Roadmap as one of the CSLF’s most important deliverables.

The change from “3.2” to “3.3” (in this section and below) is recommended because the statement that “All decisions will be made by consensus of the Members” appears in Section 3.3 of the Charter, not Section 3.2. ]]

3.4. Decision Making. As specified by Article 3.2 3.3 of the CSLF Charter, all decisions will be made by consensus of the Members. 4. CSLF-Recognized Projects 4.1. Types of Collaborative Projects. Collaborative projects, executed and funded by separate entities independent of the CSLF and of any type consistent with Article 1 of the CSLF Charter may be recognized by the CSLF as described below. The CSLF Projects Interaction and Review Team (PIRT) shall determine the types of projects eligible for CSLF recognition. This specifically includes projects that are indicative of the following:

• Information exchange and networking, • Planning and road-mapping, • Facilitation of collaboration, • Research and development, • Demonstrations, or • Other issues as indicated in Article 1 of the CSLF Charter.

[[ The changes in this section (and also in Section 4.2) are recommended to bring the PIRT Terms of Reference and CSLF Terms of Reference into agreement with each other concerning CSLF-recognized projects. In order to simplify responsibilities concerning project recognition, it is recommended that the PIRT be the only CSLF group which determines what kinds of projects are eligible for CSLF recognition. Other recommended changes in this section more precisely specify what constitutes a collaborative project. ]]

4.2. Project Recognition. All projects proposed for recognition by the CSLF shall be evaluated via a CSLF Project Submission Form. The CSLF Project Submission Form shall request from project sponsors the type and quantity of information that will allow the project to be adequately evaluated by the CSLF.

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A proposal for project recognition can be submitted by any CSLF delegate to the Technical Group and must contain a completed CSLF Project Submission Form. In order to formalize and document the relationship with the CSLF, the representatives of the project sponsors and the delegates of Members nominating a project must sign the CSLF Project Submission Form specifying that relationship before the project can be considered.

The CSLF can provide recognition to CCUS projects based on the overall technical merit of the projects. Project recognition shall be a three-step process. The PIRT shall perform an initial evaluation and pass its recommendations on to the Technical Group. The Technical Group shall evaluate all projects proposed for recognition. Projects that meet all evaluation criteria obtain Technical Group approval shall be recommended to the Policy Group. A project becomes recognized by the CSLF following approval by the Policy Group.

[[ The deleted language in the first paragraph of this section has been transferred to the PIRT Terms of Reference.

The changes in the second paragraph are recommended so that the three-step process for recognition of projects can be generally described without getting into specifics (which now appear in the PIRT Terms of Reference). ]]

4.3. Information Availability from Recognized Projects. Non-proprietary information from CSLF-recognized projects, including key project contacts, shall be made available to the CSLF by project sponsors. The Secretariat shall have the responsibility of maintaining this information on the CSLF website.

5. Interaction with Stakeholders It is recognized that stakeholders, those organizations that are affected by and can affect the goals of the CSLF, form an essential component of CSLF activities. Accordingly, the CSLF will engage stakeholders paying due attention to equitable access, effectiveness and efficiency and will be open, visible, flexible and transparent. In addition, CSLF members will continue to build and communicate with their respective stakeholder networks.

Practical Regulations and Permitting Process

for Geological CO2 Storage

Report Prepared for the Policy Group of the

Carbon Sequestration Leadership Forum (CSLF)

By the CSLF Regulation Task Force

November 7, 2017

ACKNOWLEDGEMENTS

This report was prepared by participants in the CSLF Regulation Task Force: Ryozo Tanaka (Research

Institute of Innovative Technology for the Earth, Japan; Chair), Tim Dixon (IEA Greenhouse Gas R&D

Programme), Sallie Greenberg (Illinois State Geological Survey, USA), Ian Havercroft (Global CCS

Institute), and Tristan Stanley (International Energy Agency). The Task Force members would like to

thank all authors of the case studies: Aaron De Fina (CO2CRC), Chris Gittins (TAQA), Anne Halladay

(Shell), Jordan Hamston (CO2CRC), Randy Locke (Illinois State Geological Survey), Britta Paasch

(Statoil Research Centre), Lynsey Tinios (Shell), Owain Tucker (Shell), Jonas Nesland Vevatne (Sleipner

Asset), and Max Watson (CO2CRC).

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EXECUTIVE SUMMARY

This report was aimed at exploring practical regulations for geological CO2 storage from the

viewpoint of smooth planning, development, and operation of carbon capture and storage (CCS)

projects. Experiences of seven CCS projects with the regulatory process for geological CO2 storage in

their own country was compiled as case studies here. This report will be useful for regulatory

authorities who will develop CCS regulations, regulatory authorities who will review existing CCS

regulations and amend them if necessary, and CCS project proponents who will apply for a permit.

CCS is expected to play a great role in long term energy policy to meet ambitious global climate goals.

The large-scale deployment of CCS requires appropriate incentives and regulations to be in place in

each country. This report fills the gaps of initiatives by other organizations to facilitate the

establishment of CCS regulatory frameworks by governments: the initiatives of the International

Energy Agency (IEA) in the publication on model regulatory frameworks and knowledge sharing on

regulations in major jurisdictions through workshops and a series of publications; and the initiative

of the Global CCS Institute (GCCSI) in examining and assessing the completeness of national legal and

regulatory frameworks in major jurisdictions.

The seven case studies herein are shared by real CCS projects which are reasonably diversified in

terms of region, storage type, scale, and project status. The projects cover different regions (Europe,

North America, and Asia Pacific), different storage type (onshore and offshore, saline formation, and

depleted gas field), different scale (from pilot through medium scale to large scale) and different

project status (operational, post-injection or cancelled). An overview of each case study is

summarized in Table-S1.

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Table-S1: Overview of the Case Studies

Region Project Storage Type Scale 1) Status 2)

Outline of Case Study

Europe

Sleipner CCS Project

Saline Formation Offshore Large Operational Sleipner was required to re-apply for a CO2 storage permit due to the replacement of storage regulations. A number of challenges in the re-permitting and new regulations, such as financial security, were resolved.

ROAD and P18-4 CO2

Storage

Depleted Gas Field Offshore Large Cancelled ROAD began its planning before the CO2 storage regulation was finalized. They resolved a number of challenges such as financial security in permitting through close communication with the regulatory authority. Their application was found to be in compliance with the London Protocol requirements in general.

Former Peterhead CCS project

Depleted Gas Field Offshore Large Cancelled Peterhead commenced communications with the regulatory authority at a time of its precedent project. The successful outcomes include a reasonably flexible way of determining the length of the closure period. They found a need to actively reach out to different teams within the regulatory authority and noted the benefits of independent external review on their permit application.

North America

Quest CCS Facility

Saline Formation Onshore Large Operational The Quest operator was involved in the establishment of the regulatory framework and also a comprehensive review of the framework afterward. The monitoring plan for the project is being optimized and streamlined as the project progresses thanks to its high adaptability.

Illinois Basin – Decatur Project

Saline Formation Onshore Medium Site Closure Decatur was planned while the new CO2 storage regulation was evolving. The developer needed to re-apply for a CO2 storage permit. This resulted in prolonged permitting process, changes in its monitoring plan, and cost increase for monitoring.

Asia Pacific

Tomakomai CCS

Demonstration Project

Saline Formation Offshore Medium Operational Tomakomai had to suspend CO2 injection in its offshore site due to natural fluctuation in seawater parameters larger than conservative threshold. Injection was resumed after the revision of its monitoring plan to allow for more comprehensive judgement when irregularity is detected.

CO2CRC Otway

Research Facility

Depleted Gas Field / Saline Formation Onshore Small Operational

Otway pilot has had three phases and has gone through different CCS regulatory environments. CO2 storage regulation came into force during the second phase. Since then, the project has worked under exemption as an R&D project, but is currently explore how R&D injection fits into the regulation.

1) Large: > 1 Mt/yr, Medium: 0.1 - 1 Mt/yr, Small: < 0.1 Mt/yr 2) As of November 2017

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This report analyzes the case studies, in particular, their 40 lessons learned in total to draw findings

for making CO2 storage regulations practical. The findings here are categorized into 1) findings for

making CO2 storage regulations practical; 2) findings for effective CO2 storage permitting process; and

3) findings for making permit application documents and plans pragmatic.

Findings for Making CO2 Storage Regulations Practical 1. CO2 storage regulations should be established under the principle of promotion of safe CCS. In

the establishment of the regulations, the timely involvement of industry is important.

2. Existing CO2 storage regulations can be improved through a review by diversified stakeholders.

3. CO2 storage regulations should be flexible enough for various CCS projects with different

characteristics to move forward.

4. New or amended CO2 storage regulations should be flexible with transitional provisions where

necessary for continuation of existing valid projects if any.

5. The definitions of key terms should be made with consideration of technical constraints and

should have consistency with those in other related laws and regulations.

Findings for Effective CO2 Storage Permitting Process 6. CO2 storage regulations should ideally be in place before a planning of the first CO2 storage

project starts in order to promote the deployment of CCS projects in a country.

7. A permitting process should have adequate time and resources allocated and be appropriate to

the scale and the likely impact from the project.

8. For efficient permit award, close communication is essential between a permit applicant and a

regulatory authority and should be initiated at an early stage. Such communications can be

expedited by diversified members and fixed contact points.

9. A regulatory authority and a permit applicant should identify other regulatory authorities who

should be involved in a permitting process and commence communicate with them early.

10. It would be helpful if a regulatory authority can recognize that key permit application documents

and plans will mature and should be resubmitted when appropriate.

11. A regulatory authority and a permit applicant in a national jurisdiction that is a contacting party

to the 1996 London Protocol should make sure that permit application documents for offshore

CO2 storage are in compliance with the Protocol Requirements.

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Findings for Making Permit Application Documents and Plans Pragmatic 12. An independent external review may be useful to make permit application documents better and

streamlined.

13. Negotiations between a permit applicant and a regulatory authority to address critical issues in

permitting should be initiated as early as possible. These issues may include financial

responsibilities of an operator and monitoring plans.

14. Financial responsibilities of an operator should be reasonable and pragmatic. Issues to be

addressed may include the length of the closure period1; financial contribution from an operator

for a regulatory authority's responsibility during the post-closure period2; and responsibility to

compensate unintended CO2 leakage by purchasing emission credits.

15. Monitoring plans for CO2 storage should be risk-based and adaptive; be pragmatic when

responding to an irregularity or a potential irregularity; and use monitoring parameters that are

well understood and have sufficient baseline data for critical judgements.

The findings should provide useful information in many situations including: regulatory authorities

develop regulations for geological CO2 storage, or review existing regulations for geological CO2

storage and amend them if necessary; and CCS project proponents apply for, or consider applying for

a geological CO2 storage permit.

And in the future, experiences for the next generation of CCS projects should be examined to look

into how the issues to be addressed that have been identified in the findings in this report will have

been resolved in various jurisdictions. Many of the issues, including operator’s finance

responsibilities, may be specific to a first wave of CCS projects which has no or limited precedent

experiences in permitting for geological CO2 storage.

1 A closure period is a period between the cessation of CO2 injection and the demonstration of compliance with criteria for storage site closure.

2 A post-closure period begins with the demonstration of compliance with criteria for storage site closure.

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Contents

ACKNOWLEDGEMENTS ............................................................................................................... i

EXECUTIVE SUMMARY ............................................................................................................... ii

Contents .................................................................................................................................... vi

Figures and Tables .................................................................................................................... vii

1 Introduction ....................................................................................................................... 1

1.1 CSLF Purpose ................................................................................................................ 1

1.2 Regulation Task Force and its Mandate ....................................................................... 1

1.3 CO2 Storage Regulations for CCS Deployment ............................................................. 2

2 Case Studies ....................................................................................................................... 3

2.1 Sleipner CCS Project ..................................................................................................... 5

2.2 ROAD Project and P18-4 CO2 Storage .......................................................................... 9

2.3 Former Peterhead CCS project ................................................................................... 14

2.4 Quest CCS Facility ....................................................................................................... 22

2.5 Illinois Basin - Decatur Project ................................................................................... 26

2.6 Tomakomai CCS Demonstration Project .................................................................... 30

2.7 CO2CRC Otway Research Facility ............................................................................... 35

3 Analysis and Findings ....................................................................................................... 42

3.1 Findings for Making CO2 Storage Regulations Practical ............................................. 42

3.2 Findings for Effective CO2 Storage Permitting Process .............................................. 44

3.3 Findings for Making Permit Application Documents and Plans Pragmatic ................ 47

4 Conclusions ...................................................................................................................... 49

APPENDIX: Check List for Regulatory Authority & Project Proponent .................................... 50

vi

Figures and Tables

Figure 2-1: Sleipner CCS Facility .............................................................................................................. 5

Figure 2-2: Offshore Platform P18-A ....................................................................................................... 9

Figure 2-3: Schematic of the project showing the location of the key elements .................................. 14

Figure 2-4: Photograph of Peterhead power station and the Goldeneye platform .............................. 14

Figure 2-5: Logic behind post closure monitoring ................................................................................. 18

Figure 2-6: Quest CCS Facility at the Scotford Upgrader ....................................................................... 22

Figure 2-7: 2017 Quest MMV Plan overview ........................................................................................ 24

Figure 2-8: Injection Well for the Illinois Basin - Decatur Project ......................................................... 26

Figure 2-9: Tomakomai CCS Facility ....................................................................................................... 30

Figure 2-10: pCO2 and DO Acquired in Offshore Tomakomai ................................................................ 31

Figure 2-11: CO2CRC Otway Research Facility ...................................................................................... 35

Figure 2-12: Effect of the Proposed Changes to the VGGGSA on the Otway’s Storage Activities ......... 39

Table-S1: Overview of the Case Studies ................................................................................................. iii

Table 2-1: Overview of the Case Studies ................................................................................................. 4

Table 2-2: Regulations Applied to the Otway’s Stage 1 Activities ......................................................... 37

Table 2-3: Regulations Applied to the Otway’s Stage 2 Activities ......................................................... 38

vii

1 Introduction

1.1 CSLF Purpose

The Carbon Sequestration Leadership Forum (CSLF) is a Ministerial-level international climate change

initiative that is focused on the development of improved cost-effective technologies for carbon

capture, utilization and storage (CCUS). It also promotes awareness and champions legal, regulatory,

financial, and institutional environments conducive to such technologies. The mission of the CSLF is

to facilitate the development and deployment of CCUS technologies via collaborative efforts that

address key technical, economic, and environmental obstacles.

CSLF comprises 26 members, including 25 countries and the European Commission. The CSLF

member countries represent over 3.5 billion people or approximately 60% of the world's population

on six continents and comprise 80% of the world’s total anthropogenic carbon dioxide (CO2)

emissions.

The CSLF comprises a Policy Group and a Technical Group. The Policy Group governs the overall

framework and policies of the CSLF, and focuses mainly on policy, legal, regulatory, financial,

economic, and capacity building issues. The Technical Group reports to the Policy Group and focuses

on technical issues related to CCUS and CCUS projects in member countries. The two groups carry

out activities usually in the form of a task force.

1.2 Regulation Task Force and its Mandate

At the Policy Group meeting held in Abu Dhabi, United Arab Emirates in May 2017, the CSLF Policy

Group formally agreed to launch a new task force chaired by Japan to explore practical carbon

capture and storage (CCS) regulations from the viewpoint of smooth planning, development, and

operation of CCS projects. The Regulation Task Force mandate was to produce a report by compiling

case studies of real CCS projects regarding regulations for geological CO2 storage and identifying

findings or recommendations.

1

1.3 CO2 Storage Regulations for CCS Deployment

To meet ambitious global climate goals, CCS is expected to play a great role in long term energy

policy. The large-scale deployment of CCS requires appropriate incentives and regulations to be in

place in each country. A number of governments around the world have already implemented CCS

regulations by amending existing resource extraction or environmental impact frameworks or

establishing dedicated regulatory frameworks. More and more governments are recognizing the

need for appropriate legal and regulatory frameworks if CCS is in their plans.

To facilitate the establishment of CCS regulatory frameworks by governments, the International

Energy Agency (IEA) formed the International CCS Regulatory Network in 2008 to bring together

international experts in this area to support global knowledge sharing by organizing meetings on an

annual basis. Eighth such meeting have been held, the most recent in 2016. The IEA also published

the Carbon Capture and Storage Model Regulatory Framework as a guidance document for the

development of CCS regulations in 2010. In addition, they published four editions of the Carbon

Capture and Storage Legal and Regulatory Review from 2010 to 2014. The publications updated the

development of regulatory frameworks in major jurisdictions on a regular basis. The Global CCS

Institute (GCCSI) launched the CCS Legal and Regulatory Indicator in 2015 and will release a second

edition in 2017. The indicators are aimed at examining and assessing the completeness of national

legal and regulatory frameworks in major jurisdictions.

Now that dozens of CCS projects, including anthropogenic CO2-EOR projects, have gone through

regulatory processes in a number of countries, the CSLF Regulation Task Force was formed to

produce a report that compiles project experiences with the regulatory process in their own country.

The members agreed to put the focus on regulations for geological CO2 storage since CO2 capture

and CO2 transportation are generally dealt with by conventional regulations for industry without any

major problems. It was not intended to exclude regulations for CO2-EOR in the scope if they are for

permanent geological CO2 storage, but the projects that agreed to share their experiences as case

studies for this report do not include any CO2-EOR projects. The report compiled seven case studies,

which are reasonably diversified in terms of region, storage type, scale, and project status. The case

studies, in particular, their lessons learned are analyzed, and findings are drawn for making

regulations practical, making a permitting process smooth, and making permit application

documents and plans pragmatic.

The information herein will contribute to smooth planning, development and operation of CCS

projects. The findings in this report will be useful for regulatory authorities who will develop

regulations for, regulatory authorities who will review existing regulations geological CO2 storage and

amend them if necessary, and CCS project proponents who will apply for a permit for geological CO2

storage.

2

2 Case Studies

This report compiles seven case studies of project experiences with the regulatory process, listed in

the Table 2-1. The projects cover different regions (Europe, North America, and Asia Pacific),

different storage type (onshore and offshore, saline formation, and depleted gas field), different

scale (from pilot through medium scale to large scale) and different project status (operational,

post-injection or cancelled). An outline of each study is also included in the table. Since the seven

projects are a pioneer CCS project in their country, almost all of the projects commenced its planning

before the CO2 storage regulations were finalized and enforced or the current regulations replaced

the previous regulations which had issued the original permit.

3

Table 2-1: Overview of the Case Studies

Region Project Storage Type Scale 1) Status 2)

Outline of Case Study

Europe

Sleipner CCS Project

Saline Formation Offshore Large Operational Sleipner was required to re-apply for a CO2 storage permit due to the replacement of storage regulations. A number of challenges in the re-permitting and new regulations, such as financial security, were resolved.

ROAD and P18-4 CO2

Storage

Depleted Gas Field Offshore Large Cancelled ROAD began its planning before the CO2 storage regulation was finalized. They resolved a number of challenges such as financial security in permitting through close communication with the regulatory authority. Their application was found to be in compliance with the London Protocol requirements in general.

Former Peterhead CCS project

Depleted Gas Field Offshore Large Cancelled Peterhead commenced communications with the regulatory authority at a time of its precedent project. The successful outcomes include a reasonably flexible way of determining the length of the closure period. They found a need to actively reach out to different teams within the regulatory authority and noted the benefits of independent external review on their permit application.

North America

Quest CCS Facility

Saline Formation Onshore Large Operational The Quest operator was involved in the establishment of the regulatory framework and also a comprehensive review of the framework afterward. The monitoring plan for the project is being optimized and streamlined as the project progresses thanks to its high adaptability.

Illinois Basin – Decatur Project

Saline Formation Onshore Medium Site Closure Decatur was planned while the new CO2 storage regulation was evolving. The developer needed to re-apply for a CO2 storage permit. This resulted in prolonged permitting process, changes in its monitoring plan, and cost increase for monitoring.

Asia Pacific

Tomakomai CCS

Demonstration Project

Saline Formation Offshore Medium Operational Tomakomai had to suspend CO2 injection in its offshore site due to natural fluctuation in seawater parameters larger than conservative threshold. Injection was resumed after the revision of its monitoring plan to allow for more comprehensive judgement when irregularity is detected.

CO2CRC Otway

Research Facility

Depleted Gas Field / Saline Formation Onshore Small Operational

Otway pilot has had three phases and has gone through different CCS regulatory environments. CO2 storage regulation came into force during the second phase. Since then, the project has worked under exemption as an R&D project, but is currently explore how R&D injection fits into the regulation.

1) Large: > 1 Mt/yr, Medium: 0.1 - 1 Mt/yr, Small: < 0.1 Mt/yr

2) As of November 2017

4

2.1 Sleipner CCS Project

Compiled from the Norwegian legal documents by Britta Paasch (Statoil Research Centre) & Jonas

Nesland Vevatne (Sleipner Asset)

Overview of the Project

The Sleipner CCS project started in 1996 and played a pivotal role in developing and demonstrating

numerous technologies related to CCS, in addition to complying to changing legal requirements

during the last 21 years. In 2013, the nearby Gudrun field came online and the gas from this field was

also transported to the Sleipner facility for CO2 removal and storage.

The Sleipner CCS project is an offshore-based, amine-capture facility processing natural gas from the

Sleipner field. It is located 250 km offshore southern Norway. The separated CO2 is injected into the

800-1000 m deep Utsira Formation which is a saline aquifer. So far over 16 Mt CO2 have been stored

at this site. The project continues to give valuable insights into the value of remote geophysical

monitoring techniques and their detection capabilities allowing the tracking of the CO2 plume.

Geophysical monitoring data and interpretation contributed to and improved the quantification of

CO2 processes in saline, siliciclastic formations. In addition, the stable performance of the Sleipner

CCS project over the last 21 years highlights the value of careful design and engineering.

During the lifetime of the Sleipner CCS project new Norwegian and EU regulations for storage of CO2

in geological formation were implemented. Statoil applied for re-permitting of CO2 storage under the

new regulations, which was then approved in 2016 by the Norwegian Department of Environment.

Figure 2-1: Sleipner CCS Facility

(photo: Eiken, Statoil)

5

Changes in the Norwegian regulations regarding storage of CO2 in geological formations

In the period between 1996 and 2016 Sleipner CO2 injection was governed by the Norwegian

Petroleum Law. In 2015 Statoil re-applied for permission to store CO2 under the new Norwegian CO2

storage directive and was subsequently permitted to continue storing CO2, replacing the previous

permit, where storage of CO2 was permitted as an integrated part of the pollution law related to

drilling and production.

In 2014, the EU Directive regarding geological storage of CO2 was included, with certain modifications,

into the Norwegian Petroleum Directive and the Pollution Directive. For CO2 storage related to

petroleum extraction in Norway, it is the petroleum law and pollution regulations that apply.

Background for the application

The gas from Sleipner Vest and Gudrun fields contain 9% and 12% CO2, respectively. CO2 from both

fields is extracted at the Sleipner T platform. The CO2 needs to be reduced to <2,5% to meet export

gas specifications. This is achieved by a combination of CCS and blending with low-CO2 gas from

other fields. According to the pollution law, injection of CO2 into a geological formation is classed as

pollution and a special permit is required. The aim of the pollution law is to obtain environmentally

safe geological storage of CO2 as a means of mitigating climate change.

Statoil applied for a permit to store an additional 4 Mt CO2 from the Sleipner and Gudrun field via the

Sleipner T platform, including possible new projects. Until now about 16 Mt CO2 have been stored at

the Sleipner storage site. The injection rate has been approximately 0.9 Mt/a. In the future, this rate

is expected to decline due to declining production rates of the fields. The Sleipner field is expected to

be in production until 2032 and the total capacity of the storage site is estimated to be 25 Mt.

Application Content

The content of the application had to include a description of the storage formation characteristics, a

risk assessment, a monitoring plan and a documentation of current financial security for production

and activities on the Sleipner field. Statoil’s internal requirements for safe storage of CO2 is in good

agreement with official requirements, and much of the content could be based on previous work.

Characterization The characterization of the storage site mainly comprises data collection prior to injection used for

establishing reservoir models for prediction of CO2 plume behaviour. Statoil has explained to the

authorities the existing dataset related to the permit requirements. The regulations require a

dynamic model of the injection site, which should be updated through time. This method has not

been used at Sleipner, due to challenges specific to modelling the Utsira formation in a predictive

manner, and because existing 4-D seismic data is better suited to understanding and predicting the

6

movement of the CO2 plume. Thanks to flexibility in the regulations, the Norwegian Department of

Environment could allow this deviation.

Risk Any activity related to storage of CO2 can only be permitted if no significant risk is associated with

such activity. Statoil was requested to identify risk elements for both the injection and post injection

phase where the post-injection phase was defined as 50 years. The likelihood for leakage to the

seabed through faults, weaknesses in the caprock or through plugged exploration wells was found to

be very low, with probabilities in the order of 0,0001 to 0,001 for the ongoing and post-injection

periods, respectively.

Monitoring plan The pollution regulation requires the operator to monitor the injection site. This includes the storage

site including any area which CO2 might migrate to. Potential CO2 emissions include diffuse emissions

from the amine process and injection facilities on the platform and emission from to the sea from

the storage site. The Sleipner monitoring plan includes monitoring of well-head pressure and

temperature, as well as 4-D seismic with a frequency related to the (declining) injection rate. In

addition, gravimetry and seabed inspections have been conducted. Other monitoring technologies

such as seabed uplift, passive seismic and electromagnetics have also been considered.

The present-day monitoring plan was confirmed to be sufficient to give a good understanding on

how the CO2 plume moves in the subsurface.

Financial solidity, reliability and technical competence The pollution regulation requires the operator to be financially sustainable throughout the lifetime of

the project, in addition to possessing necessary technical competence. Statoil has operated the

Sleipner field since 1996 under the Norwegian Petroleum law, which also required both financial and

technical capacity. It has been concluded that Statoil as the operator fulfils the necessary

requirements with respect the solidity, reliability and technical competence.

7

Post-injection phase

The field decommissioning plan is covered by the Petroleum Law. The Department of Environment

finds it appropriate that the post-injection plan required by the Pollution Regulation is part of the

operator’s decommissioning plan as required by the Norwegian Petroleum Law. Closure of the CO2

storage site will therefore be included in the gas field decommissioning plan.

Experience

One important challenge which was identified early, relates to financial security and the long

timeframes involved. A requirement to put aside money for an unlikely leakage event would have a

significant cost. Also, no company can with 100% certainty guarantee to be present at such time

scales. Due to the importance of establishing CCS as a means to reduce greenhouse gas emission,

this post-closure financial risk was accepted by the state. The state takes the risk in the post-closure

period in case the operator and partners are unable to fulfill the required obligations.

Overall, the transition from the former Petroleum Law to the new regulations governing the

geological storage of CO2 in a geological formation at Sleipner went smoothly. Statoil applied for the

permission in June 2015, with some additional information provided during the next months in

response to questions from the regulator. The permission was granted in June 2016.

Lessons Learned

• There is the potential that re-permission of geological CO2 storage is required due to replacement

or essential amendment of CO2 storage regulations, under which the initial permission is obtained.

Since already-operational projects may have restrictions to comply with all new regulatory

requirements, the requirements should be set out to be flexible to allow the continuation of

existing CO2 storage as far as its validity is demonstrated reasonably.

• It may be reasonable that not the CO2 storage operator but the government takes post-closure

financial risks. This is because (1) reserving money for an unlikely leakage event during a

post-injection period may be significantly costly, (2) no company can guarantee to exist on a long

time scale such as 50 years and (3) it is essential not to discourage to operate CCS since GHG

emission reduction is imperative for the globe.

References

Tillatelse til lagring av CO2 ved Sleipner-feltet, Miljødirektoratet, 2016

8

2.2 ROAD Project and P18-4 CO2 Storage

Compiled by Ryozo Tanaka (Research Institute of Innovative Technology for the Earth (RITE)) and Chris

Gittins (TAQA), mainly based on a report entitled “Case study of the ROAD storage permit”.

Overview of the Project

ROAD was a large-scale integrated CCS

demonstration project planned in the Netherlands,

led by Uniper (previously E.ON) and Engie (previously

GDF SUEZ). ROAD was to capture a portion of the

CO2 from the flue gases of a new and now

operational 1,100 MWe coal-fired power plant

(Maasvlakte Power Plant 3). The captured CO2 would

be, according to the initial plan, transported by

pipeline via an offshore platform P18-A to a depleted

gas field P18-4 for storage, located 20 kilometers off

the coast at a depth of 3,500 meters under the

seabed of the North Sea. The project involved

injecting 1.1 million tonnes of CO2 per year for 5

years. ROAD storage partner TAQA obtained a

storage permit for P18-4 in 2013, which is the first

permit issued in the framework of the EU Directive

on the geological storage of CO2 (the CCS Directive).

However, after failing to fully finance the project, Uniper and Engie withdrew from the project in

2017. The storage permit was extended and currently requires first CO2 injection before 2021.

What happened during the project in the context of regulations for geological storage?

The Dutch CCS regulation came into force in August 2011 after TAQA submitted a storage permit

application in June 2010. The Dutch Ministry of Economic Affairs requested TAQA to resubmit the

permit application to conform to the new Dutch CCS regulation. The CCS regulation was embedded

primarily in the Dutch Mining Act by transposing the CCS Directive without additional provisions or

interpretation of the key elements in the Directive. This means that, in line with the Directive, the

Dutch CCS regulation provides general rules for the process of the storage permit application and

allows a systematic assessment of each CO2 storage permit application.

Figure 2-2: Offshore Platform P18-A

9

In order to draw up the permit application, ROAD and TAQA formed a team with several members

with diversified expertise, including technical, engineering, legal, regulations, communications, and

commercial negotiations. This team coordinated communications with stakeholders – for example, a

subgroup of the team communicated with the competent authority, which also appointed a specific

person for discussions on permitting. This approach worked well, in particular, in the circumstances

where the regulations offered room for interpretation and stakeholders wanted to clarify not only

procedures but also technical details of the project.

In the permitting process, ROAD faced several challenges to be addressed, including the following

major ones:

Timing of submission of required plans The CCS Directive demands that all the required plans (e.g. monitoring, closure, corrective measures,

and financial security) are fully ready when a project submits its application. In reality, fully

developing all the studies, collecting all necessary information, and issuing reports will be only

completed after a final investment decision (FID) is taken, and in order to take an FID, a valid storage

permit is necessary. TAQA and ROAD took an approach of lowering the level of details of all of the

required plans for the application and agreed to update these plans a year before commencement of

CO2 injection, which was accepted by the competent authority.

Financial security The CCS Directive requires a permit applicant to prove that it will be able to finance all regulatory

requirements through the project lifetime, which is called financial security. The Directive, however,

doesn’t specify the obligations to be included for financial security. ROAD and TAQA discussed and

agreed with the competent authority which activities should be taken into account if the operator

goes bankrupt, and what financial security would be essential for the competent authority to

continue or abandon the project: routine monitoring, contingency monitoring, well and platform

abandonment, financial contribution and EU emission allowances (EUAs) to be purchased if CO2 is

leaked.

In the estimation of amount of financial security, they faced challenges in particular with regard to

future prices of EUAs, which they have to purchase in the year when CO2 is theoretically leaked. The

uncertainty in EUAs prices has the potential to cause another problem because the amount of

financial security must be adjusted yearly: future fluctuation of EUA prices will have effect on the

amount over time. Several instruments for financial security were discussed including the balance

sheet, however the competent authority preferred a bank guarantee. In ROAD’s opinion, as long as

the balance sheet is healthy, a bank guarantee wouldn’t provide any benefit but would increase the

costs of the project. The eventual permit lists the alternatives discussed and requires that an

acceptable form of security is received by the competent authority before injection begins.

10

Financial contribution The CCS Directive requires a permit applicant to make a financial contribution available to the

competent authority before the transfer of responsibilities in order to cover at least the anticipated

costs of post-transfer monitoring for a period of 30 years. This requirement in the Directive can be

interpreted that the competent authority can demand an unlimited financial contribution. If the

competent authority would demand an unreasonably high financial contribution, there would

actually be no handover of responsibilities from the operator to them. ROAD and TAQA agreed with

the competent authority that the financial contribution should be equivalent to costs of routine

monitoring for 30 years after the handover and that any other possible costs, including contingency

costs in case of leakage, would not be required to be paid after the handover.

Period until transfer of responsibilities The CCS Directive states that when a minimum period has elapsed after a storage site had been

closed, the responsibility for all legal obligations can be transferred to the competent authority,

subject to several other conditions. The competent authority should consider the minimum period as

20 years before such transfer but can reduce on a project-by-project basis. During the period, the

operator has to pay for monitoring, financial security and insurances for liabilities but earns no

income. From the perspectives of the operator, therefore, the duration of the period should be as

short as possible. But the minimum period designated in the Directive has no scientific background

and, theoretically speaking, there is a possibility that the competent authority can claim that all

available evidence does not indicate the stored CO2 will be completely and permanently contained,

which will result in the postponement of handover indefinitely and costs higher than anticipated. So

far, there has been no additional regulation or an agreement to remove this uncertainty, in spite of

several reviews and consultations on the CCS Directive.

Definition of CO2 leakage CO2 leakage in the CCS Directive is defined as any release of CO2 not from the storage site but from

the storage complex, which comprises the storage site and surrounding geological domain, including

secondary containment formations. CO2 movement within the storage complex is defined as CO2

migration and not regarded as CO2 leakage. CO2 leakage requires corrective measures to be taken but

CO2 migration does not. However, it is clear that if CO2 migrates out of the reservoir (out of the

storage site) into the complex, the operator would need to scale up a level of its monitoring to

demonstrate that there could or would be no leakage out of the complex. Furthermore, there is

inconsistency in the definition of CO2 leakage between the CCS Directive and the EU ETS Directive.

The ETS Directive defines that the amount of EUAs to be purchased in case of CO2 leakage is

equivalent to the amount of CO2 released into the air, which would be in reality difficult to measure.

11

Compliance with the London Protocol

The permit application was later on assessed by a third party from the viewpoint of the compliance

with the guidelines and criteria of the 1996 London Protocol (officially, the 1996 Protocol to the

Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter, 1972),

which is an international treaty that allows sub-seabed geological CO2 storage under strict

restrictions. Since the Netherlands is a contracting party of the treaty, the P18-4 storage application

should fulfill the requirements. The assessment found that the application documents are broadly

sufficient to allow the evaluation and indicated that no information was sufficiently absent that

would indicate clear non-compliance with the guidelines. This compliance assessment indicated

overall technical compliance with the CO2 Specific Guidelines. This assessment demonstrated that

the London Protocol permit conditions can be achieved by projects and by regulators and that

transparency of such permitting is possible.

Lessons learned

• It may be ideal that national CCS regulations provide not detailed but general rules for the process

of the storage permit application, which allows a systematic assessment for each CCS project

applied based on its specific characteristics.

• Delayed establishment of national CCS regulations would give unnecessary uncertainty to early

CCS projects.

• Close communication is essential between a project promoter and a regulator for efficient permit

award. Forming a team for permit drafting with diversified expertise would be a key element in

efficient communication between all parties. Fixed contact points within the promoter team and

the competent authority would be another key facilitation measure.

• It helps if the competent authority can recognize that the key documents and plans to be

submitted for the permit application will mature and should be resubmitted from time to time up

to first injection and then at regular intervals thereafter throughout the project.

• If financial security is required to cover costs for the purchase of emission credits if stored CO2

theoretically leaks, the CCS project would need to deal with risks of increase in the prices of the

credits and hence the project may be unfinancable. This single requirement will obstruct all future

projects and pragmatic solutions will need to be agreed between permit applicants and

competent authorities.

• The scope of financial contribution from the operator to the competent authority to carry out

obligations after responsibility transfer must be discussed pragmatically. Reasonable and practical

breadth of the scope is necessary for the project to proceed, but impractical or unreasonable

demands should not hamper the investment decision.

12

• Uncertainty in the length of the period from the site closure to transfer of responsibility to the

competent authority poses risks of cost increase for the project. If the competent authority can

decide to delay a timing of the transfer, the risks continue until the completion of the transfer.

This also affects the ability make a financial investment in the project.

• The definitions of terms should be harmonised, taking technical constraints and also public

perception into consideration. Using an inappropriate or misleading term can impact the

credibility or understanding of a project immeasurably. There may also need to be efforts made to

ensure consistency between CCS regulations and other regional and national laws and

regulations.

• If the national jurisdiction is a contacting party to the 1996 London Protocol, which is an

international treaty that allows sub-seabed geological CO2 storage, the competent authority and

the permit applicant should make sure to comply with the guidelines and criteria of the Protocol.

Ratification of the London Protocol would help this new industry develop.

References

ROAD, 2013, Case study of the ROAD storage permit,

http://decarboni.se/sites/default/files/publications/111356/case-study-road-storage-permit.pdf

Tom Jonker, 2013, ROAD CCS permitting process: Special report on getting a CCS project permitted,

http://hub.globalccsinstitute.com/sites/default/files/publications/94946/permitting-process-special-

report-getting-ccs-project-permitted.pdf

IEAGHG, 2016, Review of Project Permits under the London Protocol – An Assessment of the

Proposed P18-4 CO2 Site, 2016/TR4,

http://www.ieaghg.org/docs/General_Docs/Reports/2016-TR4.pdf

13

2.3 Former Peterhead CCS project

Written by Owain Tucker and Lynsey Tinios, Shell. More information can be found in the GHGT13

paper: Experience in developing the Goldeneye Storage Permit Application.

Overview of the Project

The Peterhead CCS project was slated

to be the first full chain gas CCS project

in the world. It planned to capture 1

Mtpa of CO2 from the Peterhead CCGT

power station on the north-east coast

of Scotland and store it offshore,

reusing existing infrastructure from the

depleted Goldeneye gas field.

The project was initiated in response

to the UK Government’s solicitation for

carbon capture and storage projects.

Shell UK developed plans to convert the existing Goldeneye gas field into a CO2 store. The work to

assess the suitability started under the UK Government CCS Demonstration competition launched in

2007, when the plan was to store around 20 million tonnes of CO2 sourced from the Longannet

power station in Fife, Scotland.

This project was later halted by the UK Government. Work resumed as part of the subsequent CCS

Commercialisation Programme launched in by the UK Government in 2012. The second attempt to

develop a CCS project involved transporting CO2 from the Peterhead Power Station in North East

Scotland directly offshore where it would tie into the existing 102 km Goldeneye to St Fergus gas

export pipeline to transport the dense phase CO2 to the normally unmanned Goldeneye platform

above the field (see Figure 2-4). This programme was cancelled by the UK Government in November

2015.

Figure 2-4: Photograph of Peterhead power station and the Goldeneye platform

Figure 2-3: Schematic of the project showing the location of the key elements

14

The Goldeneye platform is located ~100 km northeast of the St Fergus gas terminal (which is near

Peterhead, Aberdeenshire, Scotland see Figure 2-3) in water of ~120 m depth. From here, the CO2

was to be injected into the depleted Goldeneye gas field for geological storage, reusing the existing

hydrocarbon production wells, at a maximum rate of just over 1 million tonnes per annum.

The project was very advanced when funding was withdrawn by the UK government. When

cancelled, it had submitted the Storage Permit Application to the UK regulatory authorities who had

sent it on to the European Commission for their review.

What happened during the project in the context of regulations for geological storage?

Member states of the European Union are required to transpose the directive on the geological

storage of CO2 (often called the "CCS Directive"). In the UK, the directive is implemented in The

Energy Act of 2008, particularly in Chapter 3: Storage of Carbon Dioxide. In section 18, this act sets

out the framework that allows the awarding of licenses for the storage of CO2 by a licensing authority.

In addition to the license, a lease from The Crown Estate, the “land owner”, is needed for storage

activities for all offshore areas. The details of the licensing regime are outlined in the Carbon Dioxide

(Licensing etc.) Regulations 2010. The storage license does not give permission to inject, this

permission is conferred by a storage permit which must include all the conditions outlined in the CCS

Directive. In many paragraphs, the UK regulations refer back to the CCS Directive directly.

A number of other documents also inform the content of the storage permit application. These are

the Guidance Documents3 that were issued by the EU Commission along with the CCS Directive, and

also specific application guidance issued by the UK Oil and Gas Authority – the UK licensing authority

for CCS.

The transposition had already taken place before start of the Longannet CCS project, however, some

of the supporting regulations were still being drafted.

3 Implementation of Directive 2009/31/EC on the Geological Storage of Carbon Dioxide Guidance Documents 1-4

15

Structure of the storage permit application

The Goldeneye storage permit application was designed to address all the requirements of both the

CCS Directive and the UK regulation.

Because the storage permit application was going to be reviewed by multiple parties, including

consultants employed by the EU Commission, the team made the decision to create a self-standing

permit application and to extract material from the underlying technical reports. These technical

reports had been written over a period of five years by various authors and totalled many thousands

of pages. During this time, the Goldeneye gas field had stopped production, the reservoir pressures

had evolved, additional analytical laboratory work had been performed, and the development

concept had altered from 2Mtpa for ten years to 1Mtpa for fifteen years. Collating all the relevant

information into one consistent whole was designed to make the task of any reviewers easier.

One of the tasks of the permitting authorities is to ensure that all requirements laid out in the CCS

Directive had been addressed. To make this task easier, the team created a concordance table to

cross reference between the UK regulations, the EU Directive and the permit application to show

exactly where and in which volume each statutory requirement had been addressed.

The permit application was divided into seven volumes, plus the Offshore Environmental Statement.

Part 0 Introductory Material Part I Characterisation of the Geological Storage Site and Complex Part II Containment Risk Assessment Part III Measurement, Monitoring and Verification Plan Part IV Corrective Measures Plan Part V Closure and Post-closure Plan Part VI Details of Financial Security

The image to the right is the Goldeneye duck after which the gas field was named.

The aim in writing the Goldeneye storage permit application was to lay out all the evidence in

support of the containment integrity and the suitability of the store, and then let everything follow

from this. At the same time it was necessary to satisfy the requirements of the CCS Directive. This led

to the following structure:

I. Detail all the evidence from site characterization and design [~400 pp] II. Bring the evidence together in a containment risk assessment [~200 pp] III. Design the MMV plan based on the containment risk assessment [~90pp] IV. Outline the corrective measures that complement the monitoring plans to create

additional safeguards for containment [~90pp] V. Present the closure and post-closure plans that draw their evidence from the

conformance results derived from the monitoring [~25pp] VI. Outline the financial security that is based on the site selection and characterization, the

design decisions, and the risk assessment results [~10pp]

16

In this manner, although the monitoring and corrective measures provide additional safeguards and

do impact the containment risk assessment, it should be possible to read the application from end to

end and get a logical flow.

Within the extensive characterization volume, the same stepwise approach was attempted, with the

following chapters:

• Definition of Target (Site and Complex) • Regional Geology and Structure • Rock and Fluid Properties, which included geochemistry and geomechanics • Static Models • Reservoir Engineering and Dynamic Models • Estimating Storage Capacity • Effects of Hydraulically Connected Volumes • Wellbore Containment Assessment • Secondary Containment • Transportation and Injection Facilities

All other volumes referred back to the characterization volume.

Process to draft the permit application

The project took the approach of working very closely with the UK regulator. This being a first of a

kind application, it was important to ensure that both the project team understood the needs of the

regulator, and the regulator had the opportunity to explore the technical details of the project and

gain a thorough understanding of the risks. The process of engagement started with the Longannet

project and then continued in earnest with the Peterhead project – both planned storage in

Goldeneye.

A whole day engagement session was run at the beginning of the process where technical

presentations were delivered by the project team. A schedule of meetings and workshops was then

established where the project developer and the regulator teams would meet. The permit

application was divided into parts and in each meeting the plans for the next part were outlined and

discussed prior to writing the formal text. The text was then developed and circulated to the

regulator for comment at the next meeting. All feedback was then incorporated.

By the end of the process, there were no surprises in the permit application, and the regulator had a

detailed understanding and insight into the risk profile of the proposed project.

The project team also commissioned the British Geological Survey (BGS), a government funded and

independent institution of excellent standing in the UK, and an institute with significant expertise

over many years in the area of CO2 storage, to perform an independent external review.

17

Post closure plan and handover criteria

A key concern amongst potential storage operators is the exposure to commitments of unknown

duration and size. It is all but impossible to cost these, and all but impossible to promise that a

company will still be operating for twenty or more years after the end of storage. The CCS Directive

allows flexibility in the determination of the handover period, but it up to the implementing

competent authority to judge if and how to allow for this.

In article 18 on transfer of responsibility, the CCS Directive states that where a storage site has been

closed pursuant to certain criteria then responsibility shall be transferred to the competent authority,

if the following conditions are met:

(a) all available evidence indicates that the stored CO2 will be completely and permanently contained;

(b) a minimum period, to be determined by the competent authority has elapsed.

This minimum period shall be no shorter than 20 years, unless the competent authority is convinced

that the criterion referred to in point (a) is complied with before the end of that period;

The aim of conformance monitoring throughout the project and in the period between the end of

injection and handover is to satisfy point (a) above, i.e. show that all available evidence indicates that

the stored CO2 will be completely and permanently contained. Once this has been shown, the site

can be transferred to the Competent Authority. It is important to have a set of performance criteria

against which to measure the monitoring results. In the Goldeneye structural store in a depleted gas

field, this translated into the following performance criteria:

• CO2 is behaving as predicted and is unlikely to deviate from prediction

o 3D dynamic simulation forecasts of the movement of continuous phase CO2 indicate that

the continuous phase CO2 is approaching a gravity stable equilibrium within the site.

• No leaks or unexpected migration paths are observed: Two separate seismic surveys – with an

expected separation of five years, show that continuous phase CO2 is not migrating laterally

or vertically from the licensed storage site.

o In the Goldeneye specific case, a post closure survey is a combination of a time-lapse 3D

seismic survey for subsurface profiling and site surveys of well locations to look for

surface indications of CO2 leakage.

Figure 2-5: Logic behind post closure monitoring

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While the CCS Directive in point (b) above indicates that the minimum period could be 20 years, it

also gives the latitude to the competent authority to determine the duration based on the risk. In the

Goldeneye case this translated in to a performance based plan, not a time based plan. This is

illustrated in Figure 2-5. The logic is step wise and the approach measured. All monitoring is aimed at

identifying losses of containment and at giving data to improve the conformance modelling. At the

end of injection, a seismic survey was planned to show, in combination with previous surveys, that

no migration was taking place behind the casing. If migration were taking place behind casing, the

abandonment would involve milling the casing and setting two new long cement plugs; if not then

the abandonment would be less intrusive and would involve setting a two long cement plugs inside

the casing. A second survey would then be taken with a separation of at least five years to give time

for any migration to create a CO2 accumulation that would be detectable below 8000ft of solid rock.

If interpretation of this second survey in combination with the results of all prior monitoring showed

that the site was now secure, then handover could be progressed.

EU Commission review and opinion

Formal feedback on the permit application was received from the EU Commission: on the 21st of

January 2016, after the announcement of the end of the commercialization process funding by the

UK Government, the EU Commission published its opinion on the Goldeneye storage permit4.

In accordance with Article 10 of the CCS Directive and based on its review of the draft permit, the

Commission concludes that the draft storage permit fulfils the requirements of the CCS Directive save

as outlined below. Moreover, the prospective operator appears technically and financially competent

and capable of carrying out the planned CO2 storage operation at the proposed storage site.

The Commission considers that, to prevent any negative impacts on the environment, an

assessment of the effects of substances other than CO2 that may be present in leaking CO2 streams

must be included in the Environment Statement before consent to the project is granted. Moreover,

the Commission considers that financial security must be based on a postclosure monitoring period of

20 years in accordance with Article 18(1)(b) and Article (19)(1) of the CCS Directive.

Done at Brussels, 20.1.2016 For the Commission Miguel ARIAS CAÑETE Member of the Commission

4 E. Commission, COMMISSION OPINION of 20.1.2016 on a draft permit for the permanent storage of carbon dioxide in the depleted Goldeneye gas condensate field located in blocks 14/28b, 14/29a, 14/29e, 20/3b, 20/4b and 20/4c on the United Kingdom Continental Shelf, in accor.

19

Lessons learned

• Developing a first of kind permit application: We recommend the collaborative process as

used by the project team and the UK regulator for any region trying to develop a storage permit

for the first time. There are key differences between CO2 storage and hydrocarbon production and

these have to be recognised by both parties and designed into the permit application.

• Independent external review: The project team found the external review very constructive,

and despite initial concerns about cost increase, the review identified redundancy in the MMV

plan and simplification in areas such as handover criteria. It led to a better, more streamlined

storage permit application.

The review also led to external confirmation that the store was suitable: “Our conclusion is that

the proposed Goldeneye storage site is suitable for the purpose of storing up to 20 million tonnes

of CO2 injected according to the specified plan. BGS have signed a statement to this effect.”

• Interfaces between regulatory teams: Interfaces between regulatory teams were sometimes

less streamlined than originally expected. The project team found that different regulatory teams

were responsible for the seabed monitoring and risk assessment and the deep monitoring and

risk assessment. Because the CO2 is injected at over 8000ft below layers of impervious rock,

because of the extremely thorough risk assessment, and because the wellbores which cut across

the containment layers are intensively monitored, then the risk to benthic populations is

negligible, and any CO2 migration would be expected to be detected at depth before it reaches

the surface. This means that marine environmental monitoring does not perform a detection role,

rather it is used to establish the undisturbed situation should any significant irregularity take

place.

While the storage regulatory team appreciated this fact, the project team did not interact with

the environmental monitoring team till late in the process and had to go over much of the ground

that had been covered with the storage team over the previous year.

A similar experience was had when the team moved onto determining the financial security

provision. This also required the engagement of a new team within the regulatory division who

had to be on-boarded.

The learning here is not to underestimate the novelty of CO2 storage and to ensure that all

regulatory stakeholders are effectively engaged early on, even if this is not normally the case for

standard hydrocarbon developments.

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• The form of the actual Storage Permit: The actual wording of the Storage Permit was only

determined after the development of the Storage Permit Application. This led to some

reformatting of the permit application and even some additional dynamic simulation runs to

determine pressure bounds as it was found to be useful to apply maxima to the injection

pressures. The team had not focused on point this because the injection volumes were only half

the store capacity therefore there was no possibility of exceeding any geomechanical pressure

limit therefore the pressure limits had not been critical in the design of the injection facilities.

This was a first of a kind issue, but it could be good learning for other first of a kind projects.

References

E. Commission, COMMISSION OPINION of 20.1.2016 on a draft permit for the permanent storage of

carbon dioxide in the depleted Goldeneye gas condensate field located in blocks 14/28b, 14/29a,

14/29e, 20/3b, 20/4b and 20/4c on the United Kingdom Continental Shelf, in accor.

Directive 2009/31/EC, Directive 2009/31/EC of the European Parliament and of the Council of 23

April 2009 on the geological storage of carbon dioxide, European Parliament, 2009.

UK Government, The Storage of Carbon Dioxide (Licensing etc.) Regulations, 2010.

21

2.4 Quest CCS Facility

Written by Anne Halladay, Subsurface Advisor for Quest

Overview of the Project

The Quest CCS facility is a commercial-scale CCS project attached to an industrial facility northwest of

Edmonton, Alberta, Canada. The purpose of Quest is to deploy technology to capture CO2 produced

at the Scotford Upgrader and to compress, transport, and inject the CO2 for permanent storage in a

deep saline formation. More than 1.2 Mt/a of CO2 is currently being captured, representing greater

than 35% of the CO2 produced from the Scotford Upgrader. Shell Canada Energy operates Quest as

agent for and on behalf of the AOSP Joint Venture and its participants (Canadian Natural Resources

Limited, Chevron Canada Limited and Shell Canada Limited).

Quest began operations in August 2015 and achieved commercial operation status in September

2015. The CO2 is captured using Shell’s-patented amine capture technology from three hydrogen

manufacturing units (HMUs) (Figure 2-6). The CO2 is then compressed by an electrical drive

compressor and transported in dense phase through a 12-inch diameter pipeline to a storage site.

The CO2 is injected through two vertical injection wells into a saline aquifer overlying the basement–

the Basal Cambrian Sandstone (BCS). After two years of injection, in August 2017, more than two

million tonnes of CO2 have been safely stored in the BCS.

Figure 2-6: Quest CCS Facility at the Scotford Upgrader

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What happened during the project in the context of regulations for geological storage?

It is well recognized that Alberta is showing leadership in implementing climate policies, including

carbon pricing mechanisms and CCS-enabling regulations. Carbon capture and storage in Alberta,

Canada is regulated by the Government of Alberta’s (GOA) Alberta Energy Ministry, including the

Alberta Energy Regulator (AER). In addition to the existing oil and gas regulations and directives

applicable to CCS projects, the GOA enacted the Carbon Capture and Storage Funding Act, Carbon

Capture and Storage Statues Amendment Act 2010 and established the Carbon Sequestration Tenure

Regulation0. The CCS Statutes Amendment Act defines the assumption by the government of the

long-term liability for sites in post-closure and requires operators to contribute to the Post-Closure

Stewardship Fund. The Tenure Regulation defines the process (outlined in the CCS Statues

Amendment Act) to evaluate and acquire pore space leases for carbon sequestration, including

monitoring, measurement and verification plans (MMV), and contributions to the Post-Closure

Stewardship Fund.

To help create the regulatory environment for CCS, Shell worked with the regulator closely. After the

establishment of the regulatory framework, the GOA launched a process called the Regulatory

Framework Assessment (RFA) to make sure that the right regulations are in place before full-scale

CCS projects become operational. To ensure that the regulatory review was complete and balanced,

many Canadian and international experts from industry, universities, research organizations,

environmental groups and provincial and national governments participated. The process resulted in

71 recommendations to close regulatory gaps or enhance current requirements. Shell was involved

in the RFA as well.

With the established framework outlined above, the Quest storage facility operates under an AER

Approval that specifies the operating and reporting conditions for CO2 injection and storage. A key

requirement of the AER Approval and the Carbon Sequestration Lease Approval is the submission of

an MMV Plan. The Quest MMV plan outlines activities related to monitoring the injection stream

composition, and activities related to addressing the containment and conformance of the CO2 in the

storage reservoir, the BCS. As a first-of-its-kind MMV Plan, it is designed based on the following

principles: Regulatory-Compliance; Risk-Based; Site-Specific; and Adaptive. The assessment of

storage risks includes both containment and conformance risks, and relies on an evidence-based

evaluation of threats and consequences, and the effectiveness of safeguards in place. The MMV Plan

contains the monitoring tasks, safeguards, control measures, performance targets, and operating

procedures designed to manage and minimize the storage risks.

23

The MMV Plan is adapted in response to new information gained from well data, site-specific

technical feasibility assessments, and monitoring during the injection and closure periods. The 2017

MMV plan contains updates based on learnings from the initial phase of injection which provide a

basis to optimize and streamline MMV activities, as per the design principles of the MMV plan

(Figure 2-7). The learnings from the first year of injection operations demonstrate that the original

monitoring plan has been working according to the MMV aims of containment and conformance,

and provide a basis to optimize and streamline MMV activities as per the design principles.

Figure 2-7: 2017 Quest MMV Plan overview

Some of the changes include:

• A cessation of the assessment of DAS (distributed acoustic sensing) for novel potential

applications related to well integrity monitoring, as the well integrity monitoring program has

demonstrated performance.

• Following a report on the efficacy of InSAR (a satellite remote sensing method designed to

monitor surface heave), InSAR is now considered to be a secondary technology within the MMV

plan that will only be used in a contingency role (if another technology indicates a potential

issue).

24

• DTS (distributed temperature sensing) data have been collected in the injection wells since the

baseline monitoring period, with the aim of aiding well integrity assessments in a continuous,

quantitative application. At present, DTS can only be used for a qualitative assessment primarily

by observing rates of change in temperature over time and the integration of temporal data on

CO2 flow into the injection wells.

• The timeline for the deployment of time-lapse seismic surveys was modified to reflect observed

and predicted CO2 plume growth rather than preset dates.

The MMV operations have had no trigger events indicating any storage complex containment or

conformance issues. This is in a large part due to the site selection process, where a significant

portion of the risks associated with CCS activities were mitigated by the choice of the storage

complex itself.

Lessons learned

• To promote the development of commercial-scale CCS and the safe and effective use of CCS

technologies, the creation of a good regulatory environment for CCS is essential. This may include

a carbon credit system to provide incentives for sequestration, defining the pore space tenure,

the clarification of long-term liability, closure planning, and determining the requirements for

Monitoring, Measurement and Verification (MMV), and building a quantification protocol to

generate carbon credits..0

• The involvement of industry is critically important to create effective regulatory framework. A

comprehensive review of the established framework by diversified stakeholders may be also

effective to close regulatory gaps or enhance current requirements.

• The MMV plan should be adaptable in response to new information gained from well data,

site-specific technical feasibility assessments, and monitoring during the injection and closure

periods. The process enables the MMV plan to be optimized and streamlined.

References

Government of Alberta, Alberta Energy, Carbon Capture and Storage Legislation and Policy,

http://www.energy.alberta.ca/CCS/3844.asp

Government of Alberta, Alberta Energy, Alberta CCS Knowledge Sharing Program, Quest Project,

http://www.energy.alberta.ca/CCS/3848.asp

Bourne, S & Crouch, S & Smith, M. (2014). A risk-based framework for measurement, monitoring and

verification of the Quest CCS Project, Alberta, Canada. International Journal of Greenhouse Gas

Control. 26. 109–126.

25

2.5 Illinois Basin - Decatur Project

Authored by: Sallie Greenberg and Randy Locke at the Illinois State Geological Survey

Overview of the Project

The Illinois Basin – Decatur Project

(IBDP), located in Decatur, Illinois

USA, is a one million tonne

bio-energy carbon capture and

storage (BECCS) deep saline

geologic CO2 storage project. It is

led by the Midwest Geologic

Sequestration Consortium (MGSC)

and funded by the United States

Department of Energy (US DOE) –

National Energy Technology

Laboratory through the Regional

Carbon Sequestration Partnership

Program. IBDP is a fully integrated

large-scale demonstration project in an onshore sedimentary basin, the Illinois Basin. The source CO2

was derived from biofuel production at the Archer Daniels Midland (ADM) hosted test site.

IBDP field activities began in 2007 with a 4-year pre-injection characterization and design period,

followed by 3 years of injection (2011-2014) and will conduct more than 5 years of post-injection

monitoring (ending in 2020). In November 2014, the injection phase was safely and successfully

completed with 999,215 tonnes of CO2 injected at rate of 1,000 tonnes/day into the lower Mt. Simon

Sandstone at a depth of 2.1 km. The project infrastructure includes three deep wells (injection (CCS1),

monitoring (VW1), geophysical (GM1)), 17 shallow groundwater monitoring wells, passive

microseismic monitoring, an extensive monitoring, verification, and accounting (MVA) system, a

compression/ dehydration facility, and a 2-km pipeline.

IBDP is currently in the post-injection monitoring phase, and in this phase, is linked to the Illinois

Industrial Sources CCS (IL ICCS) Project through scientific and permitting-related activities. These two

projects hold the first-ever United States Environmental Protection Agency (US EPA) Underground

Injection Control (UIC) permits for Class VI injection, specifically developed for the subsurface storage

of CO2.

Figure 2-8: Injection Well for the Illinois Basin - Decatur Project

26

Permitting and regulatory context for storage of CO2 at the IBDP

At the beginning of the IBDP, the carbon storage regulatory framework in the United States was not

yet established and regulatory requirements were guided by the existing UIC framework. To address

uncertainty in this evolving regulatory environment, IBDP designed a comprehensive, risk-based,

monitoring strategy that was anticipated to be over and above new regulatory requirements.

Throughout the project (2007-present), two lengthy permitting processes have been undertaken that

proved to be a primary rate-limiting factor for the project. The permitting process increased the

length of time before CO2 injection began, resulted in additional monitoring and modeling

requirements, and required additional funding resources and project time for the required

post-injection site care and monitoring.

In January 2008, the IBDP submitted a UIC Class I injection permit application to the Illinois

Environmental Protection Agency (Illinois EPA). In January 2009, the IBDP site operator, ADM,

received a draft Class I - Non-hazardous UIC permit issued by the Illinois EPA. The draft permit only

provided authorization to drill the injection well (CCS1). Between 2009 and 2011, additional site

characterization was performed, site infrastructure constructed and baseline monitoring networks

established. IBDP was required to apply for a Class VI well permit from the US EPA authority under

the new regulatory framework as a condition of the Class I permit.

Coincident with the IBDP Class I permitting process, the US EPA promulgated final regulations in

December 2010 for a new class of injection well (Class VI) specific to the injection of CO2 into the

subsurface. The rules were effective in September 2011 and were published in the Code of Federal

Regulations (CFR) in 40 CFR 146 Subpart H. In October 2011, the final UIC Class I permit was issued

to the site operator (ADM) and authorization to inject one million tonnes of CO2 was received. The

conversion of the IBDP Class I permit was not automatic and the IBDP was required to go through

the full Class VI application process. For IBDP, the final Class VI permit was issued in 2014 as the

injection was nearing completion and went into effect in February 2015.

From the date of submission to the Illinois EPA, the Class I permitting process took approximately

one year for a draft permit to be issued and more than 3.5 years for a final permit to be issued.

While some benefit to the extended permitting time was realized due to additional time for project

planning and baseline data gathering, the lengthy permitting process added very significant delays to

the start of CO2 injection. Similarly, the IBDP Class VI permitting process took over four years from

submission to final effective permit. During the process, the US EPA required IBDP wells and

infrastructure to be used in the monitoring of the adjacent Illinois Industrial CCS (IL ICCS) project.

The IBDP deep wells (CCS1 and VW1) then became part of the monitoring program for IL ICCS, which

started injection in April 2017. Thus, the IBDP post-injection regulatory monitoring requirement

went from 3 years (planned) to more than 5 years, requiring additional field support, analyses, and

funding.

27

Under the Class VI permit, a significant number of changes occurred to the IBDP monitoring

program. For example, groundwater monitoring under the Class I permit focused on 11 parameters

selected for their sensitivity to detect fluid quality changes resulting from interactions with CO2 or

brine: pH, temperature, specific conductance, dissolved oxygen, dissolved CO2 as total inorganic

carbon, alkalinity, bromide, chloride, calcium, sodium, and groundwater elevation at four sampling

locations in Pennsylvanian-age bedrock (lower most USDW under the Class I permit). The Class VI

permit added groundwater sampling locations from three deeper depths (St. Peter Sandstone,

Ironton-Galesville Formation and Mt. Simon Sandstone) and retained the four sampling locations in

Pennsylvanian-age bedrock. The permit also increased the number of water quality parameters to be

monitored from 11 to 30 that included additional major and minor elements and isotopes. The

conditions of the IBDP Class VI final permit required additional fluid sampling from deeper

formations resulting in greater logistical efforts for sampling at depths from 900 to 2,100 m than

were needed previously for shallow (43 m) fluid sampling for the IBDP Class I permit. Those

modifications resulted in additional personnel time and equipment costs to the IBDP.

An approximate 4-fold increase in compliance-related analytical costs were realized by the IBDP

when site monitoring (4 shallow and VW1) was aligned with the final Class VI permit. An

approximate 5-fold increase occurred when also considering wells associated with the IL-ICCS

project (VW2 and GM2). Costs were associated with the increase in permit compliance sampling

locations (number of samples) and increase in water quality parameters to be measured.

The most significant remaining sources of regulatory uncertainty for the IBDP are related to

monitoring program requirements during the post-injection site care (PISC) period. They include the

length of PISC period monitoring and the process by which a non-endangerment determination will

be sought from the US EPA and how the project should proceed to closure. At present, IBDP has a

PISC monitoring requirement through April 2020 and the IL ICCS project has a 10-year PISC

requirement (adjusted from the default 50-year requirement). The adjusted PISC timeframe is linked

to the completion of IL ICCS injection and would not likely begin before 2022.

Lessons Learned

• Regulatory uncertainty can impact projects by requiring significant time and resources.

• Regulatory permitting can be a major rate limiting step in conducting a project.

• Future projects in the United States will likely continue to experience significant regulatory

uncertainty.

• Operators and regulators can benefit by reducing the length of time for Class VI permitting.

• CCS monitoring programs should be risk-based and adaptive.

28

References

Finley RJ. An overview of the Illinois Basin-Decatur Project. Greenhouse Gases Sci and Technol 2014;

4, 5: 571–579.

Greenberg SE, Bauer R, Will R, Locke R II, Carney M, Leetaru H, Medler, J. Geologic carbon storage at

a one million tonne demonstration project: Lessons learned from the Illinois Basin – Decatur Project.

Energy Proc 2017; 114: 5529-5539.

Hnottavange-Telleen K. Risk management at the Illinois Basin – Decatur Project: A FEPs-based

approach. Greenhouse Gases Sci Technol 2014; 4, 5: 604–616.

Locke RA II, Greenberg SE, Jagucki P, Krapac IG, Shao H. Regulatory uncertainty and its effects on

monitoring activities of a major demonstration project: The Illinois Basin – Decatur Project case.

Energy Proc 2017; 114: 5570-5579.

United States Code of Federal Regulations. Title 42, Chapter 6A, Subchapter XII.

https://www.gpo.gov/fdsys/pkg/USCODE-2010-title42/pdf/USCODE-2010-title42-chap6A-subchapXII

.pdf. Accessed August 2016.

United States Code of Federal Regulations. Part 146, Subpart H.

https://www.gpo.gov/fdsys/pkg/FR-2010-12-10/pdf/2010-29954.pdf#page=63. Accessed August

2016.

United States Environmental Protection Agency. Class VI well guidance website.

https://www.epa.gov/uic/final-class-vi-guidance-documents. Accessed August 2016.

Whittaker S, Kneppers A. Lessons in the development of large-scale CO2 storage projects. Energy Proc

2013; 37: 3646–3654.

29

2.6 Tomakomai CCS Demonstration Project

Written by Ryozo Tanaka, Research Institute of Innovative Technology for the Earth (RITE)

Overview of the Project

The Tomakomai CCS Demonstration Project, located on Hokkaido in the northern part of Japan, is

aimed at demonstrating the technical viability of the complete CCS value from capture to storage in

an offshore saline reservoir at full scale. The project is funded and owned by the Ministry of Economy,

Trade and Industry (METI) and Japan CCS Company (JCCS) is the project developer and operator. The

CO2 source is a hydrogen production unit for an

oil refinery, where CO2 is captured with an

amine base technology at a rate of 100,000

tonnes per year or more. The captured CO2 is

injected through two directional wells from

onshore wellheads which are adjacent to the

capture unit into offshore saline reservoirs

under the seabed. The two reservoirs have

different geological characteristics and are

located at different depths. The Tomakomai

project obtained a storage permit in late March

2016 and initiated the three-year CO2 injection

in early April 2016.

What happened during the project in the context of regulations for geological storage?

Sub-seabed geological CO2 storage in Japan is regulated by the Act on the Prevention of Marine

Pollution and Maritime Disasters (the Act). The ministry responsible for the Act, the Ministry of the

Environment (MOE), states that they designed the Act to regulate CCS for the protection of the

marine environment not as a mechanism to promote CCS. The Act requires those who want to store

CO2 in a geological formation under the seabed to assess the potential impacts of CO2 storage on the

marine environment. This assessment must be done in advance and then used to obtain a CO2

storage permit from the environment minister. Permit applications are required to include a plan for

monitoring the status of marine pollution, which should consist of three monitoring phases: 1) the

routine phase, 2) the precautionary phase and, 3) the contingency phase. If a project were to enter

the precautionary phase, CO2 injection should be suspended.

Figure 2-9: Tomakomai CCS Facility

(Courtesy of JCCS)

30

The Tomakomai project is the first project to apply for a sub-seabed CO2 storage permit and

therefore MOE started preparation for handling this permit application well in advance. MOE

deemed that the seawater sampling was as essential as seismic surveys and the measurement of

downhole temperature and pressure in order to detect CO2 leakage even though there had been

limited demonstrated experience and expertise in the detection of CO2 leakage through seawater

sampling. For that reason, they obtained various baseline data with a focus on chemical parameters

in seawater offshore Tomakomai by themselves for several years and then examined appropriate

requirements for monitoring to be performed by the operator.

Independently from, but in consultation with MOE, METI and JCCS collected the required seawater

baseline data in a limited fashion. Samples were collected once in each of the four seasons starting in

the Summer of 2013. This length of the baseline survey period was determined to fulfill a guidance

presented by MOE, which was defined as one year or more. In December 2015, after evaluating

various potential seawater parameters and their thresholds for transition of the monitoring phases,

MOE instructed METI and JCCS to adopt a conservative threshold line. The threshold was established

as the upper bound of 95% prediction interval of CO2 partial pressure (pCO2) calculated by the

correlation with dissolved Oxygen saturation (DO). The number of baseline data sets available for

creating the MOE-required thresholds was limited to the 4 seasonal samples taken per year. 32

samples in total were used to create the threshold, which in retrospect might not be enough to

reliably define the threshold. The approved threshold line is shown as the red line and the baseline

data used are shown in the open circles in Figure 2-10.

Figure 2-10: pCO2 and DO Acquired in Offshore Tomakomai

(Source: Kawabata, 2017)

31

JCCS obtained a storage permit with the MOE-required thresholds in late March 2016 and initiated

CO2 injection in April 2016. During a scheduled injection interruption in early June, the operator

performed the first routine marine monitoring, which resulted in several data points that exceeded

the threshold line (shown with the red circles in Figure 2-10). Following the protocol in the

monitoring plan, a follow-up survey was conducted to evaluate more seawater samples in late June,

but the results again included data points above the threshold (shown by the blue circles in Figure

2-10). Both surveys produced data points with irregular data that were spatially and temporally

discontinuous. As a result, JCCS concluded that the irregularities were due to natural seawater

fluctuations and that the MOE threshold, which was based on a limited number of baseline data

collected for the limited period, was insufficient to accommodate such fluctuations. There is also

growing uncertainty on whether it is possible to collect enough baseline data to quantify natural

variation in a way that will be meaningful for leakage attribution. Alternative approaches should be

developed, and some are in development

The June marine monitoring results had impact on Tomakomai because the monitoring phase was

transferred to the precautionary phase in accordance with the monitoring protocol. This resulted in

the postponement of injection restart scheduled in early August. The precautionary monitoring in

late July delivered a number of data beyond the limit again (shown by the green circles in Figure

2-10). Later the precautionary phase was escalated to the contingency phase. The contingency

survey was conducted in late August and resulted in no data exceeding the threshold.

After assessment of the outcomes from these surveys, MOE announced their view on the monitoring

plan for Tomakomai in mid-October 2016. Their announcement and its consequences implied that

they deemed exceeding the threshold was not caused by CO2 leakage. In the published documents,

they determined that the monitoring plan, as written, might result in the long-term suspension of

CO2 injection even in a case where there is no CO2 leak. MOE also stated this process would be good

from the viewpoint of the marine environmental protection but expressed concerns that this could

deteriorate public trust and public acceptance for the project. Finally, the regulator concluded that

the monitoring protocol in a case where seawater sampling data exceeded the threshold should be

revised in such a way that multiple methods such as pH sensor towing and side-scan sonar for

detecting CO2 leakage are used so that informed decisions about whether or not to transit to the

precautionary phase can be made. This comprehensive approach to determining whether CO2

injection should be suspended will allow for the results of additional water sampling to be evaluated

in the context with the results of other surveys designed to detect CO2 leakage directly. However,

there is insufficient expertise in CO2 leakage detection by pH sensor towing or side-scan sonar. The

optimal operation method has yet to be established and has been explored by, for example, the

Research Institute of Innovative Technology for the Earth (RITE) funded by METI.

Based on this ruling, METI and JCCS revised the Tomakomai monitoring plan to include the additional

surveys instructed by MOE without revising the disputed threshold line and obtained a permit for the

32

revision from the environment minister. They resumed CO2 injection in early February 2017 after a

six-month regulatory suspension.

Lessons learned

• CCS regulations should be established for the purpose of promotion of safe CCS. Regulations

without such a purpose may increase the cost of CCS projects by creating unnecessary

interruptions in operations or by adding additional monitoring and/or research to satisfy a

conservative regulatory approach.

• An unnecessary suspension of project operation caused by an immature plan or protocol can

deteriorate public trust on a CCS project and as a result can hinder the project and future

projects.

• Plans and protocols need to be reasonable and practical in how they respond to irregularities or

potential irregularities. Close communications and co-operation between the operator and the

regulator are necessary to ensure that plans and protocols fit project and monitoring objectives to

protect the environment.

• Once a potential problem is identified in, for example, conditions or regulatory requirements

specified in permit documents, the problem should be rectified as quickly as possible through

close communication between the operator and the regulator. However, it should be noted that it

can be difficult to change conditions or regulatory requirements radically once they have been

approved. This suggests the importance of communication with the regulators before a permit is

issued.

• Monitoring parameters that are being used for critical pathways in permit compliance (e.g.

additional costly surveys, suspension of CO2 injection) should be selected from established

technologies and monitor environments whose variations are well understood. Those parameters

should have a sufficient number of baseline data to account for natural fluctuations if any. When

parameters do not meet these conditions, the determination to change permit status should

incorporate multiple parameters and data sources.

• For offshore CO2 storage, chemical parameters in seawater can be an indicator for CO2 leakage,

but there is lack of expertise in using these parameters as a single identifier for CO2 leaks.

• There is growing uncertainty on whether it is possible to collect enough baseline data to quantify

natural variation in a way that will be meaningful for leakage attribution. Alternative approaches

should be developed, and some are in development.

33

References

JCCS, 2016, Tomakomai CCS Demonstration Project, CSLF PIRT Meeting in Tokyo,

https://www.cslforum.org/cslf/sites/default/files/documents/tokyo2016/YTanaka-TomakomaiProject

-PIRT-Tokyo1016.pdf

MOE, 2017, Lesson learned in the permitting process of the first CCS project under the seabed in

Japan, the fortieth meeting of the Scientific Group under the London Convention and the eleventh

meeting of the Scientific Group under the London Protocol in London

JCCS, 2016, 苫小牧地区における CCS 大規模実証プロジェクト 二酸化炭素圧入再開時期の検

討状況について (the current status of consideration regarding a timing of CO2 injection restart in

the large-scale CCS demonstration project in Tomakomai) (in Japanese)

http://www.japanccs.com/wp/wp-content/uploads/2016/08/二酸化炭素圧入再開時期の検討状

況について 1.pdf

Kawabata T., 2017, CSLF Regulation Task Force, CSLF Policy Group Meeting in Abu Dhabi,

https://www.cslforum.org/cslf/sites/default/files/documents/AbuDhabi2017/Kawabata-ProposedRe

gulatoryTaskForce-PG-AbuDhabi0517.pdf

MOE, 2016, 海底下 CCS 事業に係る監視計画のあり方について (a viable monitoring plan for the

CCS project with sub-seabed CO2 storage) (in Japanese)

http://www.env.go.jp/water/kaiyo/ccs2/kanshinoarikata.pdf

34

2.7 CO2CRC Otway Research Facility

Written by Jordan Hamston, Aaron De Fina and Max Watson (CO2CRC)

Project Introduction

The CO2CRC Otway Research Facility in the State of Victoria’s south-western region is Australia’s first

end-to-end demonstration of carbon capture and storage (CCS). The project provides technical

information on CCS processes, technologies and monitoring and verification regimes that will help

inform public policy and industry decision-makers while also providing assurance to the community.

1The facility has one of world’s most comprehensive characterisation, CO2 injection, monitoring and

verification programs with more than $100 million invested in research over a decade that has both

met and helped guide future CCS legislation within Australia.

The project currently utilises two petroleum production licences (PPL-11 and PPL-13) acquired

through commercial negotiation specifically for this demonstration (with overarching Research

Demonstration and Development licenses issued under the Environment Protection Act 1970).

These petroleum authorities contain a non-commercial CO2 field (Buttress), which is the source of

CO2 (and some associated hydrocarbons) for the facility’s operations, and a 2 km deep depleted gas

field (Naylor) located around 2 km south of Buttress, which was the first storage formation used by

the Project.

Over the life of the facility, the Otway Research Facility has progressed through 3 unique research

programmes each bringing with them a new set of challenges, due to the activities taking place and

the specific regulatory environment at the time of execution.

Figure 2-11: CO2CRC Otway Research Facility

35

Otway Stage 1 (2004-2009) Establishment of a Pilot Project, to extract ~65,000 t of naturally occurring CO2 from the Buttress-1

well, compress at the Buttress facility, and then transport the gas into a deeper depleted natural gas

field (Naylor) via the CRC-1 well. This stage occurred during an era of no formal Carbon Storage

Legislation.

Otway Stage 2 (2009-2019) Enhancement of the understanding of saline formation storage, and improved methodologies for

characterisation, monitoring, and long-term predictions of plume migration and stabilisation. This

project injected approximately 15,000 t of CO2 into a saline formation, leveraging an extensive

seismic monitoring regime. This expanded on our previous regulatory needs while occurring in a time

of the creation and implementation of new carbon storage legislation. This involved managing the

Otway sites through the transitioning of multi-jurisdictional legislative approvals to the new carbon

storage legislation passed by the Victorian State Government.

Otway Stage 3 (2016-2023) Designed to holistically assess the effectiveness of characterisation, injection and storage

management techniques and methodologies currently under development. This project has the aims

of both significantly reducing the cost of geological CO2 storage and monitoring, while meeting and

guiding future regulatory imperatives. Stage 3 is purposefully designed to produce knowledge and

technology that will be needed for the work of regulation of CCS projects in the future.

Regulation over project life

Projects at the Otway Research Facility are designed for purely research and demonstration purposes

and as such are not designed for commercial scale CO2 storage. However, the lessons learnt from

establishing a CO2 storage project within a region with an absence of any legislation, operating a

storage project within a changing regulatory environment and then designing future research

solutions for evolving regulatory environments, could be invaluable to upcoming projects within

Australia and abroad.

Note that in the State of Victoria, the regulation for the production of CO2 gas with some associated

hydrocarbon is through the Petroleum Act 1998. The Otway Research Facility will therefore always

be required to hold the appropriate petroleum licences for the operation of the Buttress facility.

Please also note that although not explicitly noted, we also comply with all relevant Victorian

legislation surrounding any site operations i.e. Worksafe, Country Fire Authority etc.

Stage 1 – Pilot Project in absence of legislation As CO2CRC were undertaking an Australia’s first geological storage research and demonstration

project, it was inevitably going to face a unique legislative environment that would require extensive

36

negotiations and flexibility from all parties involved to reach an acceptable outcome. The aims of this

project were to show that the technology was viable and readily available in Australia as well as

providing an example/driver for CCS legislatively within Victoria.

The closest industry regarding operational activities, to reference for legislative requirements was

the Petroleum Industry. The onshore Petroleum industry in Victoria is tightly regulated under the

Petroleum Act 1998, which is controlled by the Earth Resources Regulation (ERR) Branch (then within

the Department of Primary Industries). Given the nature of the Otway Research Facility, specifically

discharging material into the environment, it was also regulated by the Environmental Protection Act

1970, which is the responsibility of the Environmental Protection Agency (EPA).

After acquiring the two PPLs, the application to the EPA for approval for Stage 1 was submitted in

November 2006 and subsequently approved within a complex permitting regime in July 2007.

Storage of injected CO2 at the Otway Research Facility is being regulated by the Research

Demonstration and Development (RDD) provision of the Victorian Environment Protection Act 1970.

The drilling of CRC-1, conversion of Naylor-1 to a monitoring well, and subsequent extraction and

transportation of CO2 from Buttress 1 to CRC-1 was covered under approvals from the Petroleum Act

1998.

Ultimately, following exceptional collaboration between all regulating bodies, the approval process

for the project was defined using a combination of legislations. The Departments involved were the

Victorian Department of Primary Industries, The Department of Sustainability and Environment, The

Department of Environment and Heritage, The Environmental Protection Agency (EPA), Southern

Rural Water (SRW), The Moyne Shire and Local Government, The Department of Infrastructure,

Aboriginal Affairs Victoria and the Central Fire Authority.

It took over two years to obtain all the regulatory approvals for the project, which included a local

change to the planning regulations to allow for planning permission to be granted. Long-term liability

issues associated with the stored CO2 were the subject of a long debate, with the Victorian

Government not prepared to indemnify the proponents against common law liabilities. Ultimately, it

was accepted that if CO2CRC met all the EPA KPIs, they would have fulfilled their responsibilities and

could hand the tenements back to the government (Sharma et al. 2008).

Table 2-2: Regulations Applied to the Otway’s Stage 1 Activities

Stage 1 Activities Stage 1 Approvals Related Regulatory Bodies

CO2 Production and transport

(including all wells) Petroleum Act 1998 ERR

CO2 Injection and Storage Environment Protection Act 1970 EPA

Monitoring and Verification Environment Protection Act 1970

Petroleum Act 1998

EPA

ERR

37

Stage 2 – Expansion during a changing regulatory regime The application for EPA approval for Stage 2 was submitted in May 2009 and the EPA approval was

granted (for a period of 6 years) in October 2009.

The Otway Research Facility initially commenced in the absence of legislation specific to carbon

storage. However, by the time that Stage 2 was being planned and developed, the Victorian

Greenhouse Gas Geological Sequestration Act 2008 (VGGGSA) had been finalised and was about to

come into operation. The VGGGSA requirements are primarily based on the State’s well-established

and effective petroleum legislation

In October 2008, the Victorian Parliament passed the VGGGSA, and it came into operation on 1st

December 2009. This Act established an exclusive jurisdiction specifically prohibiting any storage

activities except those specially permitted under the Act.

The thinking behind key features in the Victorian legislation originated from the Otway Research

Facility which included;

• Maintaining the involvement of the EPA and Water Authority by formally identifying them as

referral authority (with involvement) in the appropriate processes;

• The importance of acting in public interest and public consultation,

• Defined requirements for special access authorities, and greenhouse gas infrastructure lines; and

• The criteria for surrender of injection authorities.

Unfortunately, the VGGGSA did not sufficiently provide for the non-commercial research and

development activities at the Otway Research Facility and some gaps were identified, where it could

be seen that the ongoing activities may be in breach of this newly introduced Act. After much

consultation, specific regulations were passed exempting the Project from the VGGGSA so long as it

maintained the approvals obtained under the previous regulatory regime.

Discussions over the Stage 2 approvals were held with the regulators after initial review by CO2CRC,

and these approvals were obtained by extending the existing RD&D approvals from the EPA, and

obtaining new approvals from Southern Rural Water (SRW) the local authority for the Water Act

1989. The new well CRC-2 was drilled under the Water Act 1989, as it did not meet the definitions of

a petroleum activity as per the Petroleum Act 1998.

Table 2-3: Regulations Applied to the Otway’s Stage 2 Activities

Additional Stage 2 Activities Additional Stage 2 Approvals Regulatory Bodies

Injection Bores Water Act 1989 SRW

CO2 Injection and Storage Environment Protection Act 1970

Water Act 1989

EPA

SRW

38

Stage 3 – Opportunities for refinement As part of the planned Stage 3 operations, CO2CRC and the Regulators recognised that operating

under an exemption to the VGGGSA is not the most appropriate way to have the storage research

facility regulated in an ongoing operational basis. CO2CRC are currently working closely with the

Victorian Government to seek a formal solution.

Currently the legislation has not changed so that the Stage 3 project is remaining under the same

regime as Stage 2, with new bores to be drilled under the Water Act 1989, and the storage

operations approved via the Environment Protection Act 1970, Research, Demonstration and

Development processes.

If the legislation changes, the storage activities, including the drilling of the new monitoring wells,

will all be regulated by the Victorian Greenhouse Gas Geological Sequestration Act 2008 (example

shown below), with the EPA and SRW being formally requested by ERR to comment upon the

proposed activities via the identified referral process within the Victorian Greenhouse Gas

Geological Sequestration Act 2008. The production of the CO2 at Buttress will remain a petroleum

activity with associated approvals via the Petroleum Act 1998.

Figure 2-12: Effect of the Proposed Changes to the VGGGSA on the Otway’s Storage Activities

Lessons Learnt

The activities in the Otway Research Facility revealed that it would be best to use a less prescriptive

and more outcomes based overarching approach to developing regulations (in line with accepted

regulatory best practice for other industries). This allows for the operator to have flexibility to utilise

best practice techniques without compromising the outcomes, whilst giving the regulatory authority

the appropriate assessment and enforcement mechanisms to manage the operations. It also showed

the importance of ensuring the need to conduct research is recognised in the legislation. From a

39

governmental regulatory perspective, the lessons from this project were summarised by Cook et al.

2014 below:

• Adequate time and resources should be allocated for the project approval processes, particularly

for pilot project where the potential regulatory framework for the project is unclear

• Project operator and regulators need to collaborate at the concept phase of the project to clarify

the process for approve the project

• The project approvals process needs to be appropriate to the scale and the likely impact from the

project

• Although a CCS project may be approved by environmental regulators, the petroleum regulators

have a valuable contribution to make in carbon storage, based on their experience with the

petroleum sector

• The petroleum industry regulation model has a lot to offer for the regulation of the carbon

storage industry and the expertise required for resulting the petroleum industry is transferable to

the carbon storage sector

• Water authority’s inputs/approvals are an integral part of regulating carbon storage projects,

particularly where there are beneficial aquifers in the vicinity of the project

• Adequate time and resources need to be allocated for any potential land access issue even if a

project is small-scale, non-commercial research project

• In developing new legislation alongside projects in operation, the transitional provisions need to

provide for projects already in existence

• Although, liability is a challenging topic to resolve, discussion must take place early in the project

planning, to clarify the distributions of liability over time especially for the long term and at

project closure.

• Stakeholder engagement is a critical part of any pilot project and needs to be planning and

managed carefully including a proactive approach to managing media matters

The activities within the Otway Research Facility presented a number of challenges from a

government perspective but both the government team and CO2CRC teams involved were able to

work through each of these challenges and together they delivered an iconic project for Victoria.

40

References

Cook, P.J (Ed.) (2014) Geologically Storing Carbon: Learning from the Otway Project Experience.

CSIRO Publishing, Melbourne

Sharma, S, Cook, P.J., Berly, T, Lees, M (2008), The CO2CRC Otway Project: Overcoming Challenges

from Planning to Execution of Australia’s first CCS project, Energy Procedia 1 (2009) 1965-1972

Ranasinghe, N, (2013), Regulating a Pilot Project in the Absence of Legislation Specific to Carbon

Storage, Energy Procedia 37 (2013) 6202-6215

41

3 Analysis and Findings

This chapter analyzes the case studies, in particular, their 40 lessons learned in total to draw findings

for making CO2 storage regulations practical. The findings here are categorized into 1) findings for

making CO2 storage regulations practical; 2) findings for effective CO2 storage permitting process; and

3) findings for making permit application documents and plans pragmatic. Those findings will be

useful for regulatory authorities to develop regulations for geological CO2 storage, or to review

existing regulations for geological CO2 storage and amend them if necessary, and for CCS project

proponents to apply for a CO2 storage permit.

3.1 Findings for Making CO2 Storage Regulations Practical

It is apparent that, to facilitate the deployment of CCS projects, CO2 storage regulations should be

practical and reasonable scientifically, technically and financially. Impractical regulations discourage

CCS projects to take place, for example, by increasing costs significantly.

Principle of and Industry Role in the Establishment of Regulations

Finding 1: CO2 storage regulations should be established under the principle of promotion of safe

CCS. In the establishment of the regulations, the timely involvement of industry is important.

The creation of practical CO2 regulations is essential to promote the development and deployment of

CCS projects since it can provide a measure of certainty to potential CCS investors and project

developers. Tomakomai insists that CO2 storage regulations should be established under the principle

of promotion of safe CCS and that regulations without such a principle may increase the cost of CCS

projects by creating unnecessary interruptions in operations or by adding unnecessary monitoring

and/or research to satisfy a conservative regulatory approach. Quest experience indicates that to

create such regulations, the timely involvement of industry is critically important.

Review of Existing Regulations

Finding 2: Existing CO2 storage regulations can be improved through a review by diversified

stakeholders.

After CO2 storage regulations come into force, it may be effective to review the regulations by

diversified stakeholders in a comprehensive manner and amend them if necessary to make them

more practical. The Quest proponent was involved in not only the establishment of regulations but

also a comprehensive review of the regulations after established. This would be an ideal approach to

refine practical regulations.

42

Flexibility in Regulations

Finding 3: CO2 storage regulations should be flexible enough for various CCS projects with different

characteristics to move forward.

ROAD found that not detailed but general rules provided in their regulatory frameworks worked well,

which allows a systematic assessment for each CCS project applied based on its specific

characteristics. In this case, however, close communications between a permit applicant and a

regulatory authority is essential and adequate time and resources should be allocated for the

discussions and negotiations. Otway pointed out that the project approvals process should be able

to account the scale and the likely impact from the project.

Transitional Provisions in New or Amended Regulations

Finding 4: New or amended CO2 storage regulations should be flexible with transitional provisions

where necessary for continuation of existing valid projects if any.

Projects already in existence can be affected significantly by new legislation, replacement or

amendment of existing regulations. Sleipner and Otway have gone through a replacement of

regulatory frameworks in their project lifetime and concluded that the new frameworks should be

flexible, for example, with transitional provisions where necessary for ongoing valid projects

approved in the previous frameworks.

Validity of and Consistency in the Definitions of Key Terms

Finding 5: The definitions of key terms should be made with consideration of technical constraints

and should have consistency with those in other related laws and regulations.

The definitions of key terms should be harmonized, taking technical constraints and also public

perception into consideration. ROAD experienced confusion in definitions of terminologies in their

CO2 storage regulations and other applicable regulations. If CO2 goes out of a reservoir, the operator

would need to scale up a level of its monitoring. In their regulations, however, the movement of CO2

is regarded as not leakage but migration and does not require the operator to take corrective

measures. In addition, the definition of CO2 leakage in their CO2 storage regulations is different from

that of the EU ETS Directive. Using an inappropriate or misleading key term can impact the credibility

or understanding of a project immeasurably.

43

3.2 Findings for Effective CO2 Storage Permitting Process

The CO2 storage permitting process can be a major retardation factor in a planning and development

phase of CCS projects. The reduction of the length of time for permitting can benefit both a permit

applicant and a regulatory authority.

Regulations to be in Place

Finding 6: CO2 storage regulations should ideally be in place before a planning of the first CO2

storage project starts in order to promote the deployment of CCS projects in a country.

The majority of the CCS projects in this report initiated project planning before their regulatory

frameworks came into force and needed to proceed in regulatory uncertainties. ROAD and Decatur

found that delayed establishment of national CO2 storage regulations would give unnecessary

uncertainty to early CCS projects. As a matter of fact, Decatur was required re-permitting, resulting in

prolonged permitting process, changes in its monitoring plan, and cost increase for monitoring.

Experiences in Otway imply that regulations for other sectors such as the petroleum sector may help

to develop CO2 storage regulations. On the other hand, Peterhead points out that it should be

recognized that there are significant differences between CO2 storage and petroleum activities.

Practical Permitting Process

Finding 7: A permitting process should have adequate time and resources allocated and be

appropriate to the scale and the likely impact from the project.

Especially when a regulatory authority has no precedent experience, or regulatory frameworks have

uncertainties, adequate time and resources should be allocated for a permitting process. Otherwise,

the process would take a longer time than necessary. Decatur was required re-permitting and

experienced prolonged permitting process. The project insists that the reduction of the length of

time for permitting can benefit both a permit applicant and a regulatory authority. Otway, which is

pilot storage for the purpose of R&D, wanted the regulatory authority to have applied a simpler

process to it with consideration for its characteristics such as pilot scale and likely limited impacts.

44

Communications between a Permit Applicant and a Regulatory Authority

Finding 8: For efficient permit award, close communication is essential between a permit applicant

and a regulatory authority and should be initiated at an early stage. Such communications can be

expedited by diversified members and fixed contact points.

Close communication is essential between a permit applicant and a regulatory authority for efficient

permit award, in particular, when a regulatory authority has no precedent experience or regulations

have uncertainties. Regulatory authority’s sentiment supportive to the project was also essential for

a permit applicant to resolve the challenges reasonably and programmatically. The majority of the

case studies in this report referred to the importance of communications between a permit

applicant and a regulatory authority. Tomakomai pointed out its importance from a different

perspective based on their experience of difficulty to change conditions or regulatory requirements

radically once they have been approved. ROAD found that fixed contact points within a permit

applicant and a regulatory authority would be a key facilitation measure for such communications.

Communications with other Regulatory Authorities

Finding 9: A regulatory authority and a permit applicant should identify other regulatory authorities

who should be involved in a permitting process and commence communicate with them early.

Peterhead found a need to actively reach out to different teams within the regulatory authority. This

issue can emerge when the regulatory authority has no precedent experience and may result in a

prolonged permitting process. Otway recommends earlier commencement of the communications

with regulatory authorities in other sectors such as drinking water, petroleum and land access.

Communications with water authority may be essential when there are beneficial aquifers in the

vicinity of the project. The petroleum regulatory authority may have a valuable contribution to make

in carbon storage, based on their experience with the petroleum sector. Potential land access can be

an issue to be addressed.

Re-appraisal of Permit Application Documents

Finding 10: It would be helpful if a regulatory authority can recognize that key permit application

documents and plans will mature and should be resubmitted when appropriate.

ROAD found that it would be helpful if a regulatory authority recognizes that key documents and

plans will mature and should be resubmitted when appropriate. Fully developing all the studies,

collecting all necessary information, and issuing reports will be only completed after a final

investment decision (FID) is taken, and in order to take an FID, a valid storage permit is necessary.

Peterhead had a similar but different experience – the permit applicant altered their engineering

judgements and found that the actual wording of the storage permit was only determined after the

development of application documents.

45

Compliance with the 1996 London Protocol

Finding 11: A regulatory authority and a permit applicant in a national jurisdiction that is a

contacting party to the 1996 London Protocol should make sure that permit application documents

for offshore CO2 storage are in compliance with the Protocol Requirements.

The ROAD application documents were found to be generally in compliance with the requirements

of the 1996 London Protocol (officially, the 1996 Protocol to the Convention on the Prevention of

Marine Pollution by Dumping of Wastes and Other Matter, 1972), which is an international treaty

that allows sub-seabed geological CO2 storage under strict restrictions. Regulatory requirements for

sub-seabed CO2 storage in a jurisdiction that is a contacting party to the Protocol should be

compliant with the Protocol requirements but possibly implicitly. In such as case, a regulatory

authority and a permit applicant should make sure that the project fulfills the guidelines and criteria

of the Protocol.

More and more Parties are required to ratify 2009 Amendment on CO2 Export for Storage to remove

a barrier to future projects where London Protocol countries want to export CO2 to another country

for sub-seabed CO2 storage. The current London Protocol prohibits export of CO2 for offshore storage

by a Party to another country. An amendment to allow this activity was proposed by Norway in 2009

and adopted by the London Protocol, however to come into force it needs to be ratified by 2/3 of the

London Protocol Parties, currently 47 Parties. Since 2009, only three Parties have ratified it (UK,

Norway and Netherlands) so there is very slow progress to ratification.

46

3.3 Findings for Making Permit Application Documents and

Plans Pragmatic

Financial security related documents and monitoring plans are usually one of the major documents

in permit application for CO2 storage. These documents and plans should be able to reasonable and

pragmatic since otherwise final investment decision on a CCS project cannot be taken or a project

can be stopped in due course. An unnecessary suspension of project operation can deteriorate public

trust on the project and consequently hinder the project and also future projects.

Independent External Review

Finding 12: An independent external review may be useful to make permit application documents

better and streamlined.

Peterhead found that an independent external review on their permit application documents was

effective to make them better. The commission of such a review will increase costs but has the

potential to reduce costs if documents such as monitoring plans and criteria for storage site closure

are streamlined. It may be also beneficial for the project to have a third party confirmation for the

validity of the application and suitability of the CO2 storage site from the viewpoint of public

confidence for the project.

Earlier Commencement of Critical Negotiation

Finding 13: Negotiations between a permit applicant and a regulatory authority to address critical

issues in permitting should be initiated as early as possible. These issues may include financial

responsibilities of an operator and monitoring plans.

ROAD, Sleipner and Otway recommend that negotiations on arguable issues such as financial

responsibilities and liability should be commenced between a permit applicant and a regulatory

authority as early as possible. This recommendation can be applied to monitoring plans as well.

Tomakomai experienced unnecessary suspension of CO2 injection due to an inappropriate protocol

to response monitoring irregularities that the applicant had made based on short-notice instructions

from the regulatory authority.

47

Potential Arguable Financial Responsibilities

Finding 14: Financial responsibilities of an operator should be reasonable and pragmatic. Issues to

be addressed may include the length of the closure period5; financial contribution from an operator

for a regulatory authority's responsibility during the post-closure period6; and responsibility to

compensate unintended CO2 leakage by purchasing emission credits.

It is apparent that financial responsibility of operators should be reasonable and pragmatic since no

projects take place if costs for financial responsibility are deemed too onerous. ROAD and Sleipner,

both of which were permitted in the framework of the EU CCS Directive, re-emphasize the criticality

of this issue. As such challenges, ROAD refers to the length of a closure period for CO2 storage site;

operator’s financial contribution for a post closure period; and unforeseeable prices of emission

credits which is to compensate unintended CO2 leakage. It may be worthwhile to consider an

approach that Peterhead took to determine the length of closure period based not on time criteria

but on performance criteria. Sleipner also points out post-closure financial risks and insists that it is

reasonable for a regulatory authority to take the risks. If financial security is required to cover costs

for the purchase of emission credits if stored CO2 theoretically leaks, the CCS project would need to

deal with risks of increase in the prices of the credits and hence the project may be unfinanecable.

Principles in Monitoring Plans

Finding 15: Monitoring plans for CO2 storage should be risk-based and adaptive; be pragmatic when

responding to an irregularity or a potential irregularity; and use monitoring parameters that are well

understood and have sufficient baseline data for critical judgements.

Monitoring plans are one of the major documents in permit application. Decatur deems that

monitoring plans should be risk-based and adaptive. Quest supports the importance of adaptability,

because it enables monitoring plans to be optimized and streamlined. Tomakomai concluded that

monitoring plans should be reasonable and practical in how they respond to an irregularity or a

potential irregularity. It should be noted that inappropriate response can affect public trust on the

CCS project and future projects adversely. Tomakomai also emphasizes the importance of selection

of parameters for critical decisions such as CO2 injection suspension. The project deems that

chemical parameters in seawater can be an indicator for CO2 leakage from offshore reservoirs, but

that there is currently lack of expertise in using these parameters as a single identifier for CO2 leaks.

Alternative approaches are, however, in development, for example, in the UK.

5 A closure period is a period between the cessation of CO2 injection and the demonstration of compliance with criteria for storage site closure.

6 A post-closure period begins with the demonstration of compliance with criteria for storage site closure.

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4 Conclusions

Based on the 40 lessons learned from the seven case studies of project experiences with regulations

for geological CO2 storage, this report drew 15 findings presented in the previous chapter.

The findings should provide useful information in many situations including: regulatory authorities

develop regulations for geological CO2 storage, or review existing regulations for geological CO2

storage and amend them if necessary; and CCS project proponents apply for, or consider applying for

a geological CO2 storage permit (See APPENDIX: Check List for Regulatory Authority & Project

Proponent).

And in the future, experiences for the next generation of CCS projects should be examined to look

into how the issues to be addressed that have been identified in the findings in this report will have

been resolved in various jurisdictions. Many of the issues, including operator’s finance

responsibilities, may be specific to a first wave of CCS projects which has no or limited precedent

experiences in permitting for geological CO2 storage.

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APPENDIX: Check List for Regulatory Authority & Project Proponent

This is a check list of the findings from the case studies for regulatory authorities who will develop

regulations for CO2 storage or review existing regulations for CO2 storage and amend them if

necessary, and CCS project proponents who will or may apply for a CO2 storage permit.

Findings for Making CO2 Storage Regulations Practical Regulatory Authority

Project Proponent

Finding 1: CO2 storage regulations should be established under the principle of promotion of safe CCS. In the establishment of the regulations, the timely involvement of industry is important.

Finding 2: Existing CO2 storage regulations can be improved through a review by diversified stakeholders.

Finding 3: CO2 storage regulations should be flexible enough for various CCS projects with different characteristics to move forward.

Finding 4: New or amended CO2 storage regulations should be flexible with transitional provisions where necessary for continuation of existing valid projects if any.

Finding 5: The definitions of key terms should be made with consideration of technical constraints and should have consistency with those in other related laws and regulations.

Findings for Effective CO2 Storage Permitting Process Regulatory Authority

Project Proponent

Finding 6: CO2 storage regulations should ideally be in place before a planning of the first CO2 storage project starts in order to promote the deployment of CCS projects in a country.

Finding 7: A permitting process should have adequate time and resources allocated and be appropriate to the scale and the likely impact from the project.

Finding 8: For efficient permit award, close communication is essential between a permit applicant and a regulatory authority and should be initiated at an early stage. Such communications can be expedited by diversified members and fixed contact points.

Finding 9: A regulatory authority and a permit applicant should identify other regulatory authorities who should be involved in a permitting process and commence communicate with them early.

Finding 10: It would be helpful if a regulatory authority can recognize that key permit application documents and plans will mature and should be resubmitted when appropriate.

Finding 11: A regulatory authority and a permit applicant in a national jurisdiction that is a contacting party to the 1996 London Protocol should make sure that permit application documents for offshore CO2 storage are in compliance with the Protocol Requirements.

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Findings for Making Permit Documents and Plans Pragmatic Regulatory Authority

Project Proponent

Finding 12: An independent external review may be useful to make permit application documents better and streamlined.

Finding 13: Negotiations between a permit applicant and a regulatory authority to address critical issues in permitting should be initiated as early as possible. These issues may include financial responsibilities of an operator and monitoring plans.

Finding 14: Financial responsibilities of an operator should be reasonable and pragmatic. Issues to be addressed may include the length of the closure period; financial contribution from an operator for a regulatory authority's responsibility during the post-closure period; and responsibility to compensate unintended CO2 leakage by purchasing emission credits.

Finding 15: Monitoring plans for CO2 storage should be risk-based and adaptive; be pragmatic when responding to an irregularity or a potential irregularity; and use monitoring parameters that are well understood and have sufficient baseline data for critical judgements.

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Technical Group Documents

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Revised Draft: July 11, 2017 Prepared by CSLF Secretariat

DRAFT Minutes of the Technical Group Meeting

Abu Dhabi, United Arab Emirates Monday, 01 May 2017

LIST OF ATTENDEES Chair Åse Slagtern (Norway)

Delegates Australia: Andrew Barrett (Vice Chair), Max Watson Canada: Eddy Chui (Vice Chair), Mike Monea China: Ping Zhong, Yi-Ming Wei Czech Republic: Lubomir Mazouch European Commission: Jeroen Schuppers France: Didier Bonijoly, David Savary Italy: Paolo Deiana, Sergio Persoglia Japan: Ryozo Tanaka, Takashi Kawabata Korea: Chang-Keun Yi, Chong Kul Ryu Netherlands: Harry Schreurs Norway: Jostein Dahl Karlsen, Lars Ingolf Eide Saudi Arabia: Ammar AlShehri South Africa: Tony Surridge (Vice Chair), Landi Themba United Arab Emirates: Meshayel Omran AlAli, Fatma AlFalasi United Kingdom: Brian Allison United States: John Litynski, Stephanie Duran

Representatives of Allied Organizations Global CCS Institute: Jeff Erikson, John Scowcroft IEAGHG: John Gale CSLF Secretariat Richard Lynch

Invited Speakers Saudi Arabia: Tidjani Niass, Saudi Aramco United Arab Emirates: Fatima Al Foora Al Shamsi, Ministry of Energy Arafat Al Yafei, Abu Dhabi Carbon Capture Company Dipak Sakaria, Abu Dhabi Carbon Capture Company United States: Grant Bromhal, National Energy Technology Laboratory

John Hamling, University of North Dakota Energy and Environmental Technology Center Sallie Greenberg, University of Illinois

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Observers Algeria: Radia Sedaoui Australia: Sarah Chapman* Canada: Kathryn Gagnon*, Simon O’Brien India: Shishir Tamotia Japan: Jiro Tanaka Kuwait: Harish Reddy Norway: Bjørn-Erik Haugan, Roy Vardheim Saudi Arabia: Pieter Smeets United Arab Emirates: Ahmed AlHajaj, Kasia Waker United Kingdom: Jon Gibbins, Tom Howard-Vyse United States: John Harju, Frank Morton * CSLF Policy Group delegate 1. Chairman’s Welcome and Opening Remarks

The Chair of the Technical Group, Åse Slagtern, called the meeting to order and welcomed the delegates and observers to Abu Dhabi. Ms. Slagtern mentioning that this would be a busy meeting, with updates from several task forces as well as the working group that is updating the CSLF Technology Roadmap. In addition there would be discussion on possible future Technical Group activities.

Ms. Slagtern also mentioned that the current meeting would be, as usual, very content-rich, with many items of interest to attendees. This includes presentations from three projects that have been nominated for CSLF recognition, an update on carbon capture and storage (CCS) activities in the United Arab Emirates, a presentation on the newly-formed carbon storage data consortium, two presentations on carbon dioxide (CO2) utilization – one on use of CO2 in industry and one on brine extraction as it relates to enhanced water recovery, a report on results from the CSLF-recognized Uthmaniyah Enhanced Oil Recovery (EOR) Project, a report on recent activity of the ISO’s TC265 working group on CO2 capture, and updates from both the IEA Greenhouse Gas R&D Programme (IEAGHG) and the Global Carbon Capture and Storage Institute (GCCSI).

2. Meeting Host’s Welcome Her Excellency Fatima Al Foora Al Shamsi, Assistant Undersecretary for Electricity and Future Energy Affairs at the United Arab Emirates’ Ministry of Energy, welcomed the meeting attendees to Abu Dhabi. Dr. Al Shamsi stated that carbon capture, utilization and storage (CCUS) technology is rapidly evolving thanks to the efforts of governments around the world increasing their efforts to address climate change, and that the use of CCUS technologies has great potential in the United Arab Emirates. CCUS provides a viable route to competitive, low-carbon power and remains one of the few viable options for significant reductions in the emissions of heavy industries. However, it requires a spirit of innovation, research, and development, as well as human and financial resources.

Dr. Al Shamsi stated that the United Arab Emirates was the first country in the Middle East to set up a separate company for developing commercial-scale CCUS projects, the first being the Al Reyadah project which will be hosting a site visit as part of the overall CSLF meeting. The Al Reyadah project also shows that the United Arab Emirates is committed to climate action and responsible energy production through private and public sector partnerships. Dr. Al Shamsi closed her welcoming speech by urging meeting attendees to have many productive discussions during this important meeting.

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3. Introduction of Delegates Technical Group delegates present for the meeting introduced themselves. Sixteen of the twenty-six CSLF Members were represented. Observers from eleven countries were also present.

4. Adoption of Agenda The Agenda was adopted with no changes.

5. Approval of Minutes from Tokyo Meeting The Minutes from the October 2016 Technical Group Meeting in Tokyo, Japan were approved with no changes.

6. Report from CSLF Secretariat Richard Lynch provided a report from the CSLF Secretariat which reviewed highlights from the October 2016 CSLF Annual Meeting in Tokyo. This was a five-day event, including a technical workshop and a site visit to the Tomakomai CCS Demonstration Project. Presentations from all meetings and the workshop are online at the CSLF website.

Mr. Lynch stated that there were several key outcomes from the Tokyo Technical Group meeting. First and foremost, the Tomakomai CCS Demonstration Project and the NET Power Allam Cycle Demonstration Project were both recommended by the Technical Group to the Policy Group for CSLF recognition. Additionally, France agreed to form and lead a new task force on Industrial CCS and the other three existing task forces were given a goal to complete drafts of their final reports in time for the current meeting. Finally, the CSLF Technology Roadmap (TRM) working group was given a goal to complete a final draft of the 2017 TRM in time for the current meeting. As a follow-up, Mr. Lynch reported that a mostly-final version of the 2017 TRM has been completed and is included in the meeting documents book, but that the three task force chairs have all decided that, in light of their final report drafts being still under review, these documents would not yet be available to the full Technical Group.

7. CCUS in the United Arab Emirates Dipak Sakaria played a short video about the Abu Dhabi CCUS Project (in advance of a longer presentation later in the meeting) which gave a time-lapse depiction of construction of the project. Mr. Sakaria stated that the project, with its associated pipeline infrastructure, would be a working platform which would leverage future CCUS projects in the United Arab Emirates.

8. Update from the IEA Greenhouse Gas R&D Programme John Gale gave a concise presentation about the IEAGHG and its continuing collaboration with the CSLF’s Technical Group. The IEAGHG was founded in 1991 with the mission to provide information about the role of technology in reducing greenhouse gas emissions from use of fossil fuels. The focus is on CCS, and the goal of the organization is to produce information that is objective, trustworthy, and independent, while also being policy relevant but not policy prescriptive. The “flagship” activities of the IEAGHG are the technical studies and reports it publishes on all aspects of CCS, the seven international research networks about various topics related to CCS, and the

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biennial GHGT conferences (the next one in October 2018 in Melbourne, Australia). Other IEAGHG activities include its biennial post combustion capture conferences (the next one in September 2017 in the United States), its annual International CCS Summer School, peer reviews with other organizations, activity in international regulatory organizations such as the ISO and the London Convention, and collaboration with other organizations, including the CSLF.

Mr. Gale mentioned that since 2008 the IEAGHG and CSLF Technical Group have enjoyed a mutually beneficial relationship which allows each organization to cooperatively participate in the other’s activities. This has included mutual representation of each at CSLF Technical Group and IEAGHG Executive Committee (ExCo) meetings, and also the opportunity for the Technical Group to propose studies to be undertaken by the IEAGHG. These, along with proposals from IEAGHG ExCo members, go through a selection process at semiannual ExCo meetings. So far there have been four IEAGHG studies that originated from the CSLF Technical Group, plus an additional proposed study which became an International Workshop on Offshore Geologic CO2 Storage.

Mr. Gale concluded his presentation with a list of reports recently published, reports in progress to be published, studies underway, and studies awaiting start. Mr. Gale also briefly described IEAGHG events, including its webinar series and next year’s GHGT conference.

9. Update from the Global Carbon Capture and Storage Institute John Scowcroft gave a short presentation about the GCCSI and its vision for CCS. The Institute is an international membership organization with offices in Melbourne, Washington D.C., Brussels, Beijing, and Tokyo. It has a diverse international membership including governments, global corporations, small companies, research institutes, and NGOs. The strength of the Institute is that it has specialist expertise which covers the entire CCS/CCUS chain.

Mr. Scowcroft provided a summary of how the GCCSI perceives the global status of CCS. As of April 2017 there are 40 large-scale CCS projects throughout the world which are in operation, construction, or in the planning stages. The 22 projects operation or in construction can capture and store approximately 40 million tons of CO2 per year. However, this is only a small fraction of the estimated 4,000 million tons of CO2 per year which would need to be stored (by the year 2040) as part of the IEA’s 2 ºC scenario. Eighteen of these 40 large-scale projects are located in North America, with another eight in China. Of the 17 projects currently in operation worldwide, twelve of them are in North America. Large-scale CCS projects have been implemented in many different industries: power generation, coal-to-liquids, chemicals production, iron and steel production, synthetic natural gas production, fertilizer production, oil refining, natural gas processing, and hydrogen production.

Mr. Scowcroft closed his presentation by stating that the GCCSI is evolving in reaction to the ever-changing CCS landscape of the world – its new approach is more bold and provocative, while its support of research is less prolific and more deliberative and impactful. Overall, the GCCSI is moving from knowledge sharing towards advocacy.

10. Preview of Mission Innovation Experts Group Workshop Tidjani Niass gave a short presentation about Mission Innovation and its CCUS Innovation Challenge. The overall goal of the Mission Innovation initiative for the

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participating countries to double their clean energy R&D investment over five years, while encouraging greater levels of private sector investment in transformative clean energy technologies. To that end, planning is underway for an invitational “Experts Workshop” to discuss basic research needs for CCUS. The venue will be in the United States, and the projected dates for the event are September 25-29, 2017.

Dr. Niass stated that the overall objective for the CCUS Innovative Challenge is to develop a route to near-zero CO2 emissions from power plants and carbon intensive industries. This would involve identifying and prioritizing breakthrough CCUS technologies, developing pathways to close RD&D gaps, recommending multilateral collaboration mechanisms, and driving down the cost of CCUS through innovation. The United States and Saudi Arabia are the Workshop leads, with 18 other countries also participating. The Experts Workshop will focus on CO2 capture, utilization and storage science and will result in a report that will guide innovation on CCUS. Other parts of the work plan include establishing strategic partnerships with like-minded organizations and engaging industry via a subgroup focused on that aspect.

11. Report from the CSLF Projects Interaction and Review Team (PIRT) The PIRT Chair, Andrew Barrett, gave a short presentation which summarized PIRT activities and the previous day’s meeting. The PIRT is currently involved in three main activities: reviewing projects nominated for CSLF recognition, updating the CSLF Technology Roadmap, and finding ways to better engage sponsors of CSLF-recognized projects. Mr. Barrett reported that much of the PIRT meeting had been taken up by review of three projects that have been nominated for CSLF recognition and by discussions related to project engagement, and that there were three main outcomes from the meeting:

• The PIRT has recommended approval by the Technical Group for the Al Reyadah CCUS Project, the Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact, and the National Risk Assessment Partnership.

• The mostly-final draft of the 2017 TRM has been sent to all CSLF delegations, with a firm deadline of July 1st for receiving comments. A finalized version will be completed and sent to the CSLF Secretariat by September 15th and a publication-ready version will then be prepared for publication and inclusion in Ministerial Meeting briefing documents.

• The PIRT’s projects engagement initiative has produced useful information, but the CSLF still needs to ramp up its efforts in this area.

Mr. Barrett stated that there had been extensive discussion on project recognition criteria, about whether the existing criteria are still appropriate and if these criteria unintentionally exclude appropriate projects. From this, two actions emerged:

• The PIRT Chair and the CSLF Secretariat will review the CSLF and PIRT Terms of Reference documents to clarify project qualifications for CSLF recognition and to present recommendations at the next PIRT meeting. (Note: this has since expanded to include the Technical Group Executive Committee and the Chair of the Policy Group’s Communications Task Force.)

• The CSLF Secretariat will revise the Project Engagement survey form to include questions asking why the project sought CSLF recognition, or what benefits that project sponsors expect from CSLF recognition.

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12. Progress Report on 2017 CSLF Technology Roadmap (TRM) The Chair of the TRM working group, Andrew Barrett, gave a short progress report presentation about the 2017 TRM. The TRM working group had been formed at the 2015 Technical Group meeting in Riyadh with the mandate to produce a new TRM in time for the next CSLF Ministerial Meeting. The process chosen for the rewrite was to use the 2013 TRM as a basis and refresh its content as needed. Editorial responsibility for updating the document was shared among the working group, with Lars Ingolf Eide of Norway being the editor-in-chief. The Working Group has been chaired by Australia with representation from Norway, Canada, South Africa, the United Kingdom, the United States, the IEAGHG, and the CSLF Secretariat. In addition, there have been contributions from several international experts on CCS.

Mr. Barrett briefly described the main changes from the 2013 TRM: • New time horizons were being used for medium- and long-term recommendations

and targets (2025 and 2035 respectively, instead of the previous TRM’s target dates of 2030 and 2050).

• The “Background” chapter was revised to reflect COP21 targets, and quantitative targets which meet the IEA 2 ºC scenario were used for CO2 sequestration.

• A new section was included on non-technical measures such as regulations, and there is expanded discussion on CCS, CCU, and CCUS.

• The chapter on “Assessment of Present Situation” was shortened and merged into the “Technology Needs” chapter.

• There is less detail concerning specific technology types and fundamentals, and more emphasis on industrial and biomass CCS.

• There is a new separate section on sectors other than power, industry and biomass (though hydrogen production with CCS is the only topic so far).

• There is more emphasis on development of a “clusters and hubs” approach toward CCS, and also on ship transport of CO2.

• Recent CO2 storage projects and activities have been referenced, and description has been updated and expended about various aspects of CO2 utilization.

• There are identified actions to meet technology needs throughout the CCS chain. Mr. Barrett stated the main findings of the 2017 TRM are that CCUS works in power and industrial settings, but implementation of CCUS is well behind the trajectory of reaching the stated COP21 “less than 2 ºC temperature rise” goal. Additionally, CCUS is not possible without the right policy settings and the appropriate financial framework. There are several important recommendations made by the TRM:

• Based on the IEA 2 ºC scenario, governments and industry should work together to contribute to the COP21 targets by implementing sufficient large-scale projects in the power and industry sectors to: o Permanently store 0.5 gigatonnes (Gt) of CO2 per year by 2025 (or have

permanently captured and stored 2 GtCO2); and o Permanently store 2.7 GtCO2 per year by 2035 (or have permanently

captured and stored 20 GtCO2). • Governments and industry should work together to:

o Develop supportive policy incentives and support for CCS on similar terms as other low-carbon technologies;

o Develop markets and business models for CCUS support;

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o Accelerate legal and regulatory frameworks for CCS; and o Develop strategic transportation and storage infrastructures using a cluster-

and-hub approach, in particular for industrial CCUS, including early identification and characterization of potential CO2 storage sites.

• Improve CCUS public outreach and education, supporting educators as well as community proponents of CCUS projects.

• Facilitate exchange of data from operating large-scale CCUS projects. • Support RD&D for novel and emerging technologies along the entire CCUS

chain, in order to drive down costs. • Map opportunities, conduct technology readiness assessments, and resolve main

barriers for the implementation of CCUS.

Mr. Barrett concluded his presentations by briefly describing next steps. The mostly-final draft of the 2017 TRM has been sent to all CSLF delegations, with a firm deadline of July 1st for receiving comments, but there is understanding that information contained in the forthcoming IEA Energy Technology Perspectives 2017 report could possibly lead to additional edits to the TRM. Mr. Barrett stated that after all edits are finished, a finalized version will be completed and sent to the CSLF Secretariat by September 15th and a publication-ready version will then be prepared for publication and inclusion in Ministerial Meeting briefing documents.

13. Report from the Offshore CO2-EOR Task Force Task Force Chair Lars Ingolf Eide gave a brief update on the task force, which was established at the November 2015 meeting in Riyadh. The purpose of the task force is to highlight differences and issues between onshore and offshore CO2-EOR as well as offshore CO2-EOR and pure offshore CO2 storage. The task force will also highlight any technical solutions which benefit both pure offshore CO2 storage and offshore CO2-EOR. Task force members include Norway (as chair), Brazil, Canada, Mexico, the United States, and the IEAGHG.

Mr. Eide stated that the task force has held two teleconferences since the October 2017 CSLF meeting in Tokyo. A preliminary first draft of the task force’s final report has been completed, but it was still undergoing review at the time of the 2017 CSLF Mid-Year Meeting. The contents of the report will include chapters on the basics of offshore CO2-EOR, insights from the Brazilian “Lula” off-shore CO2-EOR project, approaches and emerging technical solutions toward enabling offshore CO2-EOR, description of potential CO2 supply chain issues, issues involved with monitoring and verification of storage, description of regulatory requirements for offshore CO2 utilization and storage, and recommendations for overcoming any barriers to accomplishing offshore projects. Mr. Eide stated that revisions and a final review by the task force members would be completed by mid-October and that the task force report will be ready in time for the 2017 CSLF Ministerial Meeting.

14. Report from the Bioenergy with CCS (BECCS) Task Force Task Force Chair John Litynski gave a brief update on the task force, which was established at the November 2015 meeting in Riyadh. The focus of the task force is to identify and summarize global efforts, successes, and challenges to deployment for BECCS. This includes surveying and identifying existing projects, government programs, market drivers, barriers to large-scale deployment, and opportunities for

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BECCS technologies. The task force mandate includes developing a concise information resource, in its final report, which will help to point the way forward for the CSLF and its member countries in this area.

Mr. Litynski stated that a first draft of the task force report was completed in mid-March. Comments received by task force members went into a second draft, which had been distributed to task force members just prior to the 2017 CSLF Mid-Year Meeting. A finalized version of the report will be ready for the 2017 CSLF Ministerial Meeting. The overall structure of the report includes an introductory chapter which describes BECCS challenges and benefits, a summary of BECCS resource assessments and emissions profiles, a summary of the commercial status of BECCS technology deployment, an overview of BECCS technology options and pathways, and a concluding chapter of findings and recommendations. Next steps for the task force will be to address all task force comments and complete unfinished sections (including the executive summary), finalize the report and obtain comments from Technical Group delegates, and prepare the final report for publication.

15. Report from the Improved Pore Space Utilisation Task Force Task Force Co-Chair Brian Allison gave a brief update on the task force, which was established at the November 2015 meeting in Riyadh. The purpose of the task force is to investigate the existing capabilities in improved pore space utilisation for CO2 storage. This includes summarizing the effectiveness and readiness of various techniques and developing ideas for necessary R&D to develop capability in the most opportune technologies. Current task force members include Australia and the United Kingdom (as co-chairs), Canada, France, Japan, the United Arab Emirates, the United States, and the IEAGHG. Mr. Allison stated that the task force is still in the information collection stage, and called on other task force members for updates on their focal areas.

John Gale reported that the IEAGHG was still preparing the chapter about non-technical issues and that a draft would be ready a few weeks after the 2017 Mid-Year Meeting. Ryozo Tanaka stated that another chapter of the report would include information about microbubble injection, which he described in his presentation at the 2016 CSLF Mid-Year Meeting in London. Didier Bonijoly mentioned that the report will include information on application of pore space optimization for new technologies such as the combination of CCS with hydrothermal geothermal energy. Mr. Allison stated that the British Geological Survey and other organizations were adding their input to a section on non-technical aspects such as regulatory issues.

Task Force Co-Chair Max Watson stated that improved pore space utilisation related to EOR was not being considered by the task force and neither was reservoir stimulation, as these would greatly increase the level of effort and require expertise beyond what exists with task force participants. Dr. Watson mentioned that the chapters on technical aspects were progressing well, but that there were many different technologies being looked at. Recommendations from the task force will be two-fold: a “low cost” option and a “high efficiency” option. Dr. Watson also stated that it was likely that new injection technologies to be tested at the CSLF-recognized Otway Project and possibly elsewhere would be influenced by outcomes from this task force.

Mr. Allison concluded the group presentation by stating that the task force timeline may not result in its final report being ready in time for the 2017 Ministerial Meeting, though a draft of it would be done by then and recommendations for the CSLF Ministers would

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also be ready. The task force will most likely continue into 2018, as the some of the recommendations will set the stage for future work by the task force.

During ensuing discussion, Jeroen Schuppers mentioned that a European Commission-funded project in Iceland had utilized microbubble techniques for injecting CO2 from a geothermal plant into a basalt geologic storage formation. Mr. Schuppers stated that the CO2 had mineralized within one year, and that this might be a new technology area that could be referenced in the task force report.

16. Report from the CCS and Industry Task Force Task Force Chair Didier Bonijoly gave a brief update on the task force, which was established at the October 2016 meeting in Tokyo. The task force mandate is to investigate the opportunities and issues for CCUS in the industrial sector. The task force is currently comprised of members of France’s Club CO2, and that delegates and stakeholders from Germany, the Netherlands, Norway, Saudi Arabia, and the United States had also expressed interest in joining.

Dr. Bonijoly stated that the industry currently accounts for about 21% of CO2 emissions (Process CO2), which is nearly as much as the amount of CO2 being emitted from electricity and thermal power plants (Combustion CO2). In particular, large industries are major contributors and for these there is little recourse – a power generating facility can be switched to utilize lower emitting technologies, but those options do not always exist for heavy industry.

Dr. Bonijoly stated that the task force will not have a final report ready for the upcoming 2017 Ministerial Meeting, and its activities would carry over into 2018. Areas of interest for the task force include investigating aspects of various technologies that could be used to capture CO2 in an industrial setting, and also determining what are the principle obstacles for development of CCS in industry. There would be a focus on the most critical industries and the task force would also investigate possible alternatives to CCS, such as CO2 utilization, to see if these are workable at any relevant scale.

17. CO2 Utilization in Industry: Overview, Prospects and Recommendations David Savary gave a presentation which provided a useful overview of CO2 utilization prospects for industry. As a background, annual worldwide CO2 emissions from fossil fuel use in industry and for power generation reached approximately 36 gigatonnes (Gt) in 2015, which constituted a 60% increase from 1990 levels. As a comparison, annual current utilization of CO2 for production of chemicals and for EOR is approximately 250 megatonnes (Mt), or about 0.7% of the amount of CO2 annually generated. However, given appropriate business models and regulatory environment, annual worldwide CO2 utilization has the potential for being as high as about 4% of the amount of CO2 annually generated. Mr. Savary stated that France’s Club CO2, representing CCS stakeholders throughout the country, has been actively investigating opportunities for CO2 utilization and in October 2016 sponsored the 2nd CO2 Utilization Workshop, in the city of Lyon.

Mr. Savary stated that there were many conclusions and recommendations that resulted from the workshop. Concerning research, development and innovation, there was consensus that public-private collaborations are essential to make any significant inroads toward increased CO2 utilization and that demonstration-scale projects are needed. These projects should involve all stakeholders, including economic development agencies, civil society organizations, and other NGOs. This would help to increase awareness and

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reassure the public as well as convincing civil society about the worth of such projects. Valorization of CO2 is also needed, as a means of partially offsetting the cost of capturing the CO2. A greater value of CO2 would be a driver for increased utilization. Such valorization could happen not only from consideration of CO2 as a valuable chemical intermediate but also from environmental benefit considerations.

Mr. Savary ended his presentation by summarizing France’s proposals for the Mission Innovation CCUS Challenge. These include development of a simple and widely-acceptable life cycle analysis methodology in order to assess environmental impacts of manufactured products involving CO2 utilization, finding means for direct use of CO2 from flue gases for purposes such as algae and carbonate mineral production, and reducing energy consumption required in CO2 utilization processes via new methodologies involving catalysis and mineralization.

18. Brine Extraction and Storage Test Program in the United States John Hamling gave a presentation which provided a background and description of field projects for using brine extraction as a means for pressure management of CO2 storage in deep saline aquifers. In general, brine extraction for pressure management purposes can enable dedicated CO2 storage and improve the geologic CO2 storage potential of a deep saline aquifer. Brine extraction can also be used for active reservoir management (ARM), which allows geosteering the CO2 plume in the aquifer reservoir, diverting pressure from leakage pathways, and reducing stress on the cap rock layer above the reservoir. Additionally, brine extraction and its subsequent treatment, in arid areas of the world, can provide a valuable source of water. However, use of brine extraction adds incremental infrastructure, operating and energy costs, brings in the requirement for treatment and discharge/ reinjection of the extracted brine, adds complexity and possible efficiency loss to the project, and can lead to added health, safety and environmental considerations.

Mr. Hamling described two field projects in the United States which will be evaluating ARM strategies and economics, validating models, and testing monitoring techniques. The Energy & Environmental Research Center (EERC) project in western North Dakota is making use of a commercial saltwater disposal facility and included an enclosed water treatment test bed. The Electric Power Research Institute (EPRI) project in northwestern Florida is sited at a coal-fueled power plant with active wastewater disposal and an open-air water treatment test bed. These projects will include field testing of pressure management strategies and scenarios, active reservoir surveillance, and evaluation of various brine treatment technologies. The overall program is focused on dedicated geologic CO2 storage applications, but outcomes could benefit a broad range of industries.

19. Review of Technical Group Action Plan and Possible New Technical Group Activities Åse Slagtern provided a brief update on the Technical Group Action Plan, in follow up to a preliminary discussion on the topic that had occurred at the previous day’s PIRT meeting. Over the past four years, seven Technical Group task forces have completed final reports. There are four currently active task forces, all of which are on track to complete their activities in 2017 or 2018. Ms. Slagtern stated that there are at least ten possible future actions, identified by a Technical Group working group back in 2015, but there had not yet been any consensus to form task forces around any of these.

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Ensuing discussion led to consensus on a proposal from Ms. Slagtern to create a small working group, to be led by Norway, which would evaluate the existing list as well as any other ideas for possible future Technical Group actions. This includes a new action on CO2 capture from hydrogen production which has been proposed by Norway and supported by the United Kingdom, Australia, and Japan. Delegates from Australia, Saudi Arabia, the United Kingdom, and the United States volunteered to participate in the new working group, while delegates from Canada, Japan, and the Netherlands offered to provide input as needed.

20. Review and Approval of Project Proposed for CSLF-Recognition: Al Reyadah CCUS Project (nominated by the United Arab Emirates [lead], Australia, Canada, China, the Netherlands, Norway, Saudi Arabia, South Africa, the United Kingdom, and the United States) Arafat Al Yafei, representing project sponsor Abu Dhabi Carbon Capture Company, gave a technically detailed presentation about the Al Reyadah project. This is an integrated commercial-scale project, located in Mussafah, Abu Dhabi, United Arab Emirates, which is capturing CO2 from the flue gas of an Emirates Steel production facility, and injecting the CO2 for EOR in the Abu Dhabi National Oil Company’s nearby oil fields. The main objectives are to reduce the carbon footprint of the United Arab Emirates, implement EOR in subsurface oil reservoirs, and free up natural gas which would have been used for oil field pressure maintenance. The Al Reyadah Project includes capture, transport and injection of up to 800,000 tonnes per year of CO2 (processed at the required specifications and pressure) and is part of an overall master plan which could also create a CO2 network and hub for managing future CO2 supply and injection requirements in the United Arab Emirates.

After a brief discussion, there was consensus to recommend to the Policy Group that the project receive CSLF recognition.

21. Review and Approval of Project Proposed for CSLF-Recognition: Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact (CCSI/CCSI2) (nominated by the United States [lead], China, France, and Norway) Grant Bromhal, representing project sponsor the U.S. National Energy Technology Laboratory (NETL), gave a technically detailed presentation about CCSI/CCSI2. This is a computational research initiative, with activities ongoing at NETL, four other National Laboratories, and five universities across the United States, with collaboration from other organizations outside the United States including industry partners. The overall objective is to develop and utilize an integrated suite of computational tools (the CCSI Toolset) in order to support and accelerate the development, scale-up and commercialization of CO2 capture technologies. The anticipated outcome is a significant reduction in the time that it takes to develop and scale-up new technologies in the energy sector. CCSI2 will apply the CCSI toolset, in partnership with industry, in the scale-up of new and innovative CO2 capture technologies. A major focus of CCSI2 will be on model validation using the large-scale pilot test information from projects around the world to help predict design and operational performance at all scales including commercial demonstrations. These activities will help maximize the learning that occurs at each scale during technology development.

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After a brief discussion, there was consensus to recommend to the Policy Group that the project receive CSLF recognition.

22. Review and Approval of Project Proposed for CSLF-Recognition: National Risk Assessment Partnership (NRAP) (nominated by the United States [lead], Australia, China, and France) Grant Bromhal, representing project sponsor NETL, gave a technically detailed presentation about NRAP. This is a risk assessment initiative, with activities ongoing at NETL and four other National Laboratories across the United States, including collaboration with industry, regulatory organizations, and other types of stakeholders. The overall objective is development of defensible, science-based methodologies and tools for quantifying leakage and seismic risks for long-term CO2 geologic storage. The anticipated outcome is removal of key barriers to the business case for CO2 storage by providing the technical basis for quantifying long-term liability. To that end, NRAP has developed and released a series of computational tools (the NRAP toolset) that are being used by a diverse set of stakeholders around the world. The toolset is expected to help storage site operators design and apply monitoring and mitigation strategies, help regulators and their agents quantify risks and perform cost-benefit analyses for specific CCS projects, and provide a basis for financiers and regulators to invest in and approve CCS projects with greater confidence because costs of long-term liability can be estimated more easily and with greater certainty.

After a brief discussion, there was consensus to recommend to the Policy Group that the project receive CSLF recognition.

23. Results from CSLF-recognized Project: Uthmaniyah CO2-EOR Demonstration Project Ammar AlShehri provided a brief update on the progress and activities for the CSLF-recognized Uthmaniyah CO2-EOR Demonstration Project. This is a commercial-scale demonstration, recognized in 2013 at the 5th CSLF Ministerial Meeting, which is capturing and utilizing approximately 800,000 tonnes of CO2 per year for enhanced oil recovery. Dr. AlShehri stated that the Uthmaniyah project is part of Saudi Aramco’s overall carbon management activities and that Saudi Aramco has developed a technology roadmap that includes capturing CO2 from fixed and mobile sources, CO2 conversion into industrial applications, and CO2 sequestration as focal areas in addition to CO2-EOR.

Dr. AlShehri stated that the Uthmaniyah project captures CO2 from natural gas processing operations and includes an 85-kilometer pipeline to transport the CO2 to the injection site. A key feature of the project is its monitoring regime, which includes seismic monitoring, electromagnetic surveys, plume tracking, and inter-well tracer tests to accurately determine the CO2 flow path. Monitoring parameters include the volume of the sequestered CO2, plume evolution, CO2 migration and containment, and incremental oil recovered. This monitoring is being carried out continuously with data routed through a field center. Dr. AlShehri concluded his presentation by mentioning that this project is only a test to determine the feasibility of CO2-EOR in Saudi Arabia, as there will not be a need for widespread use of this technology for probably several decades. However, advances that will result from this project will add to the overall knowledge base for EOR and as a result, improve the economics for its deployment.

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24. Results from CSLF-recognized Project: Illinois Industrial CCS Project Sallie Greenberg provided a brief update on the progress and activities for the CSLF-recognized Illinois Industrial CCS Project. This is a commercial-scale demonstration, recognized at the 2012 CSLF Annual Meeting, which is sequestering approximately 3,000 tonnes of CO2 per day. Dr. Greenberg stated that this project is a collaboration between the Archer Daniels Midland Company and the Midwest Geological Sequestration Consortium, plus other corporations and organizations, and is so far the only large-scale project in the United States that is storing CO2 into a deep saline aquifer geologic storage formation. A companion project, the Illinois Basin Decatur Project, has already stored nearly one million tonnes of CO2 into the same geologic formation as part of a comprehensive research program whose monitoring component has led to gains in knowledge about reservoir modeling, plume forecasting, and risk assessment.

Dr. Greenberg stated that the Illinois Industrial CCS Project began large-scale CO2 injection just prior to the current CSLF Mid-Year Meeting. A rate-limiting step in the overall schedule had been completion of the permitting process. An Underground Injection Control (UIC) “Class VI” Permit was required from the U.S. Environmental Protection Agency (EPA) before injection could start, and this was the first such UIC Class VI permit that has been issued. The project includes development and validation of software tools as part of an “Intelligent Monitoring System” approach which will enable access, integration and analysis of real-time surface/subsurface data for decision-making and automation of sequestration activities.

Dr. Greenberg concluded her presentation by mentioning that the Illinois Industrial CCS Project will, in the end, store up to about 5.5 million tonnes of CO2. The saline aquifer that will sequester the CO2 has a much larger capacity than that, and a follow-on U.S. Department of Energy program, the Carbon Storage Assurance and Facility Enterprise (CarbonSAFE), could result in greater than 50 million tonnes of CO2 being sequestered there. The overall goal of CarbonSAFE will be to improve the overall knowledge base for large-scale CO2 storage, validate models and various technologies related to geologic CO2 storage, and contribute to best practice manuals which will be of use to future commercial CO2 storage projects.

25. Overview and Status of the Carbon Storage Data Consortium Sallie Greenberg provided a brief update on the Carbon Storage Data Consortium (CSDC), which had been created in 2016 following discussions in 2015 between United States and Norway researchers. The CSDC underpins another CSLF initiative, the Large-Scale Saline Storage Project Network, whose formation had been announced in November 2015 at the 6th CSLF Ministerial Meeting. Current membership of the CSDC include two organizations in the United States, four in Norway, and the IEAGHG.

Dr. Greenberg described how the CSDC data sharing network could work. Sponsoring organizations involved with geologic CO2 storage would provide information to a CSDC project team, which would process/screen the data and make it available to a broader user community via a data-hub provider. The CSDC is currently exploring alternative technical solutions for data sharing, ranging from the simple, low-cost-but-low-flexibility to the complex, higher cost-and-full-flexibility approaches. The initial goal of the CSDC is to secure international co-funding to ensure long-term operations, and to expand its membership by inviting organizations in other countries besides the United States and Norway to join. A near term objective is to formally launch the consortium and make the first CO2 storage datasets available before the end of 2017.

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26. Update on Activities of the ISO/TC265

Ryozo Tanaka provided a brief update about the International Organization for Standardization (ISO) TC265 technical committee. The objective of TC265 is to prepare standards for the design, construction, operation and related activities in the field of CO2 capture, transportation and geologic storage. The TC265 is comprised of six working groups focused on different aspects of CCS, each with proposed standards working their way through review and approval procedures. The most recent meeting of TC265 was in late November 2016, in Sapporo, Japan. At that meeting, Mr. Tanaka gave a short presentation about the CSLF that included information on its objectives, organization, previous meetings, and activities of CSLF Technical Group task forces. The next meeting of TC265 will in November 2017 in Sydney, Australia. There was consensus that Sallie Greenberg would represent the CSLF at that meeting.

27. Update on Future CSLF Meetings Richard Lynch provided a brief logistical update about the site visit to the Al Reyadah CCUS Project, and stated that information about the 7th CSLF Ministerial Meeting, to be held in Abu Dhabi near the end of 2017, would be forthcoming at the Policy Group’s meeting later in the week. There was nothing to report about the 2018 Mid-Year Meeting, but Max Watson stated that Australia has offered to host the 2018 Annual Meeting, at a date in October 2018. Additional details would also be forthcoming at the Policy Group’s meeting.

28. Open Discussion and New Business Sergio Persoglia provided a preview of the following week’s meeting of the CO2 GeoNet Association in Venice, Italy and Paolo Deiana gave a brief illustration of the Sulcis International CCS Summer School scheduled in the week from 19 to 23 June in Carbonia, SW Sardinia, Italy.

Mike Monea stated that there would be a CCS workshop in Regina, Saskatchewan, Canada in early October, which would focus on SaskPower’s Boundary Dam Project and the related Aquastore Project.

Lars Ingolf Eide reported that he would be making a presentation about the CSLF at an upcoming conference in Trondheim, Norway, and would be vetting his presentation through the Technical Group’s Executive Committee for comments and any suggested changes.

Stephanie Duran mentioned that the newly-designed CSLF website includes a list of such meetings and conferences and requested that information on upcoming events be sent to the CSLF Secretariat so that they can be given additional visibility through the website.

29. Closing Remarks / Adjourn Åse Slagtern noted that this was the final CSLF meeting for Takashi Kawabata, who is moving on to other duties at Japan’s Ministry of Economy, Trade and Industry. Mr. Kawabata was given a round of applause for his many years of involvement with the CSLF. Ms. Slagtern then thanked the meeting host United Arab Emirates Ministry of Energy, the Secretariat for its support, and the delegates for their active participation. She then adjourned the meeting.

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Summary of Meeting Outcomes

• The Al Reyadah CCUS Project is recommended by the Technical Group to the Policy Group for CSLF recognition.

• The Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact initiative is recommended by the Technical Group to the Policy Group for CSLF recognition.

• The National Risk Assessment Partnership initiative is recommended by the Technical Group to the Policy Group for CSLF recognition.

• The Technical Group will form a new working group, to be chaired by Norway, which will evaluate existing and new ideas for possible future Technical Group actions.

• Sallie Greenberg will represent the CSLF at the next meeting of the ISO/TC265, in November 2017 in Sydney, Australia.

TECHNICAL GROUP

Action Plan Status

Background At the Regina meeting in June 2015, a working group was formed to develop and prioritize potential new Action Plan activities. The working group presented its recommendations at the Riyadh meeting in November 2015, which resulted in three new task forces being formed in the areas of Offshore CO2-EOR, Improved Pore Space Utilisation, and Bio-energy with CCS. At the Tokyo meeting in October 2016, a task force on Industrial CCS was formed.

This paper, prepared by the CSLF Secretariat, is a brief summary of the Technical Group’s current actions, potential actions that have so far been deferred, and completed actions over the past several years.

At the 2017 CSLF Mid-Year Meeting in Abu Dhabi, a working group (led by Norway) was created to evaluate the list of deferred potential actions shown in this paper as well as any other ideas for possible future Technical Group actions. Delegates from Australia, Saudi Arabia, the United Kingdom, and the United States volunteered to participate in the new working group, while delegates from Canada, Japan, and the Netherlands offered to provide input as needed. The working group will be providing a report on its recommendations at the upcoming Technical Group meeting. Action Requested In advance of the report from the working group, the Technical Group is requested to review the Secretariat’s status summary of Technical Group actions.

CSLF Technical Group Action Plan Status (as of October 2017)

Current Actions

• Offshore CO2-EOR (Task Force chair: Norway) COMPLETED IN 2017 • Improved Pore Space Utilisation (Task Force co-chairs: Australia and United Kingdom) • Bio-energy with CCS (Task Force chair: United States) • CCS and Industry (Task Force chair: France) Potential Actions (all of which have been deferred)

• Geo-steering and Pressure Management Techniques and Applications (Note: Geo-Steering has been incorporated into Improved Pore Space Utilisation action.)

• Advanced Manufacturing Techniques for CCS Technologies • Dilute Stream / Direct Air Capture of CO2 • Global Residual Oil Zone (ROZ) Analysis and Potential for Combined CO2 Storage and

EOR • Study / Report on Environmental Analysis Projects throughout the World • Update on Non-EOR CO2 Utilization Options • Ship Transport of CO2 • Investigation into Inconsistencies in Definitions and Technology Classifications • Global Scaling of CCS • Compact CCS Completed Actions (previous four years)

• Technical Challenges for Conversion of CO2-EOR Projects to CO2 Storage Projects (Final Report in September 2013)

• CCS Technology Opportunities and Gaps (Final Report in October 2013) • CO2 Utilization Options (Final Report in October 2013) • Reviewing Best Practices and Standards for Geologic Storage and Monitoring of CO2

(Final Report in November 2014) • Review of CO2 Storage Efficiency in Deep Saline Aquifers (Final Report in June 2015) • Technical Barriers and R&D Opportunities for Offshore Sub-Seabed CO2 Storage (Final

Report in September 2015) • Supporting Development of 2nd and 3rd Generation Carbon Capture Technologies (Final

Report in December 2015)

CSLF Working Group on Evaluating Existing and Date: 9 November 2017 New Ideas for Possible Future Technical Group Actions

TECHNICAL GROUP

Working Group on Evaluating Existing and New Ideas for Possible Future Technical Group Actions

Recommendations

CSLF Technical Group Meeting

Abu Dhabi, United Aran Emirates 04 December, 2017

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Recommended actions With reservation that a low response rate from the CSLF working group and the CSLF Technical Group delegates introduces uncertainties in the results, the flowing recommendations are given:

1. CSLF Technical Group awaits the results of the Task Force on Pore space utilisation before a decision is made regarding a new Task Force on Geo-steering and pressure management techniques and applications to see how much has been incorporated into the Pose Space Utilization report.

2. CSLF Technical Group considers establishing task forces or to undertake appraisals, as resources will allow, on the following topics, in order of priority:

Topic Possible lead Contributors 1. Hydrogen as a tool to decarbonize

industries Norway Netherlands, Saudi-Arabia, UK

2. Reviewing Best Practices and Standards for Geologic Monitoring and Storage of CO2

Australia, France, Norway, Saudi-Arabia,

3. Capture by mineralisation

France, Netherlands, Saudi-Arabia

4. Global scaling of CCS

France, Saudi-Arabia

3. In addition, CSLF Technical Group considers if the topic Utilisation options of CO2 should be added to the list of potential new task forces.

Background information At the Technical Group meeting in Abu Dhabi, United Arab Emirates, May 1, 2017 it was decided to form a review group to: 1. Appraise all unaddressed items in the Action Plan from 2015. 2. Propose new topics for appraisal 3. Review past task force reports with the aim to see if any updates are needed. Delegates from Australia, Saudi Arabia, the United Kingdom, and the United States volunteered to participate in the new working group, while delegates from Canada, Japan, and the Netherlands offered to provide input as needed. This group would: 1. Review any existing documents and other materials relevant to the unaddressed and new actions

as well as past task force topics 2. Recommend which, if any, activities are worth pursuing for these actions. Possible actions are:

• Start with an appraisal for later decision on how to proceed (stop or carry on with one of the other options)

• Establish Task Forces with voluntary participants from CSLF members. These will review status and give recommendations on next steps in a report.

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• In case where the resource requirements will be too extensive for CSLF, suggest the topic as study for or in cooperation with an organization with a budget, e.g. IEAGHG or GCCSI.

The topics that were up for discussion are described in Attachment 1, a total of 24 topics. The list in Attachment 1 was distributed to the group July 2. As of September 16, 2017, three responses had been received from the review group, despite reminder, of which one only commented on the text of a new topic. Based on a fairly free interpretation of the limited input, see Attachment 2, several topics were removed from the list and the following 12 remained on a shortlist: 1. From the 2015 list

a. Geo-steering and pressure management techniques and applications b. Ship transport (from the 2015 list) c. Dilute stream/direct air capture of CO2, see if sufficient data exists d. Global Residual Oil Zone (ROZ) analysis and potential for combined CO2 storage and

EOR e. Definitions of TRL f. Capturing CO2 from mobile sources g. Global scaling of CCS

2. New proposals: a. Hydrogen as one of the tools to decarbonise industries (proposed by Norway) b. Mineralization to use CO2 permanently in products (Proposed by Netherlands)

3. Updates. a. Review and Identification of Standards for CO2 Storage Capacity Estimation b. Examine Risk Assessment Standards and Procedures c. Technical Challenges of Conversion of CO2-EOR Projects to CO2 Storage Projects d. Reviewing Best Practices and Standards for Geologic Monitoring and Storage of CO2.

The main reason is have an updated web version, now residing at GCCSI (cooperation?)

Comments: 1. Topic 1.a - Geo-steering and pressure management techniques and applications – should to some

extent be covered by the Task Force on Pore space utilisation. Further action awaits until the report is published.

2. Update of Utilization options of CO2 was not included due a misunderstanding. Given the low feedback from the review group both the longlist (Attachments 1 and 2 to this note) and the shortlist were sent to 41 delegates to the Technical Group. The delegates were invited to comment and suggest new topics, as well as to pick their four highest priority votes on the short list, ranking from 1 (highest) to 4 (lowest). The invitation was sent out 22 September and deadline was set to 13 October.

Main Findings 11 delegates out of 41 responded to the shortlist, even with an extended deadline. The 11 represent six member states and the European Commission. The scores were turned around, so that 4 is highest priority, 1 is lowest, resulting in a ranking were highest scores is top priority. A system with 2 given to first priority and 1 to the three other prioritized topics, used by IEAGHG, was also tried, with the same overall ranking. Table 1 shows the results and form the basis for the recommendations. A few delegates marked or scored all 12 topics. For these, only the four of highest priorities are ranked in Table 1. Seven member states volunteered contributions, only one has so far volunteered task force leadership.

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Table 1. Ranking of topics on the short list of potential new CSLF Technical Group task forces. 4 is top priority, 1 is lowest priority. Delegates picked four topics to rank, those without scores have not received votes.

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ATTACHMENT 1 Summaries of potential task forces Abu Dhabi December 2017 Proposals from 2015 list (not prioritized): Advanced Manufacturing Techniques for CCS Technologies. Advanced manufacturing techniques such as 3-D printing have the potential to revolutionize the synthesis and functionality of advanced technologies in many different fields. Objective of this effort is to explore the potential application of advanced manufacturing techniques to CCS technologies.

Geo-steering and pressure management techniques and applications. Brine production is considered a potential mechanism for “geo-steering” of CO2 plume, and reservoir and pressure management. This study will investigate novel methods such as brine extraction for pressure and reservoir management in carbon storage operations. To be redefined (geo-steering covered, include risk management issues)

Dilute stream/Direct Air Capture of CO2. This effort will explore the current state of the art of technologies that can capture dilute streams of CO2 (<1% CO2 concentration) and the economic and technical challenges. Global Residual Oil Zone (ROZ). Analysis and Potential for combined CO2 Storage and EOR. Residual oil zones are currently uneconomic but have great potential to store large volumes of CO2 while producing additional oil. This task force will explore the current status of ROZ resource in the world and its CO2 storage potential, technical challenges and R&D opportunities. Study/Report on Environmental Analysis projects throughout the world. Several projects throughout the world have explored the environmental impacts of CO2 release/CCS (e.g., QICS, CO2 Field Lab, Montana State University ZERT facility, etc.). This study/report would summarize the findings in one concise document and draw conclusions from the work to date and identify opportunities for future work. Update on non-EOR Utilization Options. NOTE: Not suggesting to immediately re-form this task force, but I think in the 2017 timeframe it might be good to re-visit the previous reports and identify progress, status, new ideas. For example, some new ideas for suggested inclusion are compressed air storage as buffer for power generation, and upgrading and treatment of produced brines/enhanced water recovery. Ship transport. So far pipelines is the dominant way to transport CO2 for storage. Transport by ships may be an interesting alternative when pipeline is too expensive, e.g. when the need for CO2 injection is time limited; or when small amounts are to transferred to a hub. This study will review and summarize what has been done so far and give recommendations for further work. Definitions, TRL, scales and other. The work with 2nd and 3rd generation technologies revealed deficiencies and inconsistencies in present definitions and classification of technology maturity for CO2 capture. Even the NETL definitions are not straightforward to interpret and not well suited for industrial applications. The latter also applies to some extent to metrics for cost performance. Further, apparently, there is no commonly accepted and used definition of what is meant by bench-, lab-, pilot- and demo-scale tests in terms of CO2 captured, flue gas treated, power delivered or product output. This work will suggest definitions that, when developed in cooperation with IEAGHG and GCCSI, will have a chance of being generally accepted. NOTE: One could expand to include guidelines on how to assess other performances, e.g. energy penalty, although ISO TC265 is looking into this. CSLF probably has a broader participation than ISO and can work faster.

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Global Scaling of CCS. Produce a simple global model which incorporates by country/region descriptions of current CO2 emissions by source (e.g., coal power stations, vehicles, etc.). Design the model to allow the user to show the effects on emissions of trends e.g. x%/a closure of coal, y %/a increase in gas , z%/a increase in CCS. Sustain energy use along lines of current trends and track CO2 storage required is within current storage range estimates. Use the model to explore under which conditions CCS makes its largest/smallest contribution to the prevention of global warming; perhaps using IEA fossil fuel use scenarios and emission reduction scenarios as the reference guide to assessing the role of CCS as a start. Compact CCS. New technologies such as those using supercritical CO2 are being developed and offer small plant footprints, at least for power production and capture. A study which evaluates how ”small” various CCS plants could be made could inform us about potential operation in areas sensitive to plant size (height or footprint), or the potential for offshore operation, with savings on long gas pipelines. Capturing CO2 from mobile application. This is to evaluate CO2 Capture System on-board a vehicle that mitigates CO2 emissions from transportation system. It is done through the separation of CO2 after the combustion process using post-combustion CO2 capture technology. Previous Task Force Reports, candidates for updates Identifying Gaps in CO2 Capture and Storage (Nov. 2006). The task force handled only capture and transport steps of the full CCS chain. Describes R&D gaps to be fulfilled to meet cost target of 10-20 €/ton CO2 by 2020. Identifying Gaps in Monitoring and Verification of Geologic CO2 Storage (Nov. 2006). Cooperation with IEAGHG and also IEAGHG Report Number: 2006/TR1(REVISED). The report reviews gaps listen in the 2005 IPCC Special Report on CC (SRCCS), assesses the significance of the gaps and the R&D needs identified in SRCCS. Review and Identification of Standards for CO2 Storage Capacity Estimation (Aug. 2005, June 2007, April 2008). The CSLF Task Force recommended a consistent set of methodologies for estimation of CO2 storage capacity in coal beds, oil and gas reservoirs and aquifers in March 2007 (Phases I and II). In Phase III this set was compared to standards for CO2 storage capacity estimation developed for the US dep. of Energy by the Regional Carbon Sequestration Partnership Programs. Examine Risk Assessment Standards and Procedures (Oct. 2009, May 2012). Phase I gave an overview of risk assessment methodologies, including literature survey, summary of on-going activities and identification of needs for additional information. Phase II included a gap assessment to identify CCS- specific tools and methodologies that will be needed to support risk assessment, and a feasibility assessment of developing general technical guidelines for risk assessment that could be adapted to specific sites and local needs. Utilization Options of CO2 (Oct. 2012, Oct. 2013). This report identified the most economic and promising CO2 utilization options with potential to yield a meaningful net reduction of CO2 emissions and/or facilitate development and/or deployment of other CCS technologies. Technical Challenges of Conversion of CO2-EOR Projects to CO2 Storage Projects (Sept. 2013). The task force reviewed, compiled and reported on technical challenges that may constitute a barrier to a broad use of CO2 for EOR and the conversion of CO2-EOR operations to CCS operations. CCS Technology Opportunities and Gaps (Oct. 2013). The task force identified and monitored key CCS technology gaps and related issues, reviewed the effectiveness of on-going RD&D activities for addressing these gaps, and recommended RD&D that address gaps and issues.

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Reviewing Best Practices and Standards for Geologic Monitoring and Storage of CO2 (Oct. 2013). The task force compiled and summarized relevant guidelines, best practices and manuals on CO2 storage. Also published online by GCCSI, with the Intention to give a quick look at available standards, guidelines and best practice manuals Technical Barriers and R&D Opportunities for Offshore, Sub-Seabed Storage of CO2 (Sept. 2015). The report provided an overview of the current technology status, technical barriers, and research and development (R&D) opportunities associated with offshore, sub-seabed geologic storage of CO2. CO2 Storage Efficiency (Published in IJGGC, Sept. 2015). This report was an update of earlier CSLF Task Force reports on CO2 storage efficiency. 2nd and 3rd Generation Carbon Capture Technologies (Dec. 2015). This Task Force was a joint venture between the Policy and Technical Groups. The report described efforts to identify emerging technologies for emerging (2nd and 3rd generation) technologies, identified potential testing facilities to bring the technologies our of lab- and pilot-scale to demonstration scale, gave recommendation to the Policy Group. New proposals 2017 Hydrogen as one of the tools to decarbonise industries (Proposed by Norway). Fossil fuels are used for transportation, industry and household heating and cooking around the world. This results in millions of small emission sources from which CO2 capture will be impractical. In this case, hydrogen produced from oil, gas or gasification of coal, petcoke, vacuum residue, or biomass can be used to complement other technologies that reduce GHG. This allows for centralised capture of CO2 that would otherwise be produced locally at the site of use. There are no technical barriers to CO2 capture associated with large-scale hydrogen production. However, the Task Force will look into issues like:

• Process intensification, i.e. more compact, efficient and economic solutions, e.g. high-temperature hydrogen membranes and technologies for catalytic reforming of the fuel and simultaneous separation of H2 and CO2.

• Process integration in co-production of H2 and, for example: • Electricity and heat production • In industrial processes where H2, or H2 enriched natural gas, can replace fossil fuel-based

feedstock. • Large scale CO2 transport and storage infrastructure, local clusters for synergies. • Policies and support mechanisms.

Mineralization to use CO2 permanently in products (Proposed by Netherlands a.i). The use of CO2 takes place mainly in EOR and newer developments like fuels, chemicals or specialities (feed-in to glass houses). In all these cases the CO2 will be more or less back in the atmosphere. A goal for development should be to use CO2 in a permanently stored way, preferable in large(r) scale application(s). A solution is the binding affinity of CO2 to certain minerals, like for instance olivine. Research in (very) small scale, far less than 1 kg, is worldwide starting up. First research activities have already shown potential to avoid the very slow natural process. Produced material shows applicability to substitute for instance filler material in polymer, paper and betony. Small scale applications, like filler for 3D-printers, looks promising. The Task Force will look into issues like:

• Inventory of the work in progress, including (types of) minerals. • Scale-up of production facility (autoclaves, process conditions). • Use of the exothermal binding reaction (on-site combination with CO2 capture) . • Markets to penetrate, starting with low-volume/high-price applications. • Contribution to CO2 reduction and saving on use of minerals.

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ATTACHMENT 2: Comments received from the review group on possible new CSLF Technical Group Task Forces Topic Start with

appraisal Establish Task Force

Comments (e.g. suggest to or cooperate with others; other comments) Update needed

1 From 2015-list

Advanced Manufacturing Techniques for CCS Technologies

May become a IEAGHG study, to be decided in Nov. 2017

2 From 2015-list

Geo-steering and pressure management techniques and applications

Wait for Pore Space TF to complete

3 From 2015-list

Dilute stream/Direct Air Capture of CO2

Yes Appraisal to see if sufficient data to do anything meaningful

4 From 2015-list

Global Residual Oil Zone (ROZ) Analysis and Potential for combined CO2 Storage and EOR

Yes

5 From 2015-list

Study/Report on Environmental Analysis projects throughout the world

No No See Roberts and Stalker, 2017 http://www.sciencedirect.com/science/article/pii/S1876610217319112

6 From 2015-list

Update on non-EOR Utilization Options

IEAGHG undertaking comprehensive study on CCU accounting. Wait for the result

7 From 2015-list

Ship transport Yes IEAGHG has produced two reports which should be updated

8 From 2015-list

Definitions, TRL, scales and other

Yes No Could suggest to ISO TC265, who should be lead on this

9 From 2015-list

Global Scaling of CCS

10 From 2015-list

Compact CCS Wait for status of NET power project report, hinges on that working!!

11 From 2015-list

Capturing CO2 from mobile application

Yes

12 New Hydrogen as tool to decarbonise industries

Yes Good idea. IEAGHG studies on CCS on H2, and Leeds and Statoil work can feed-in.

13 New Mineralization Yes

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14 Update Identifying Gaps in CO2 Capture and Storage

No No Probably covered, at least partly, by Nos. 2, 15, and 24

No

15 Update Identifying Gaps in Monitoring and Verification of Geologic CO2 Storage

No No Covered in IJGGC SI 2015, see also ZEP (2017), GCCSI (2016), CSKl TRM

No

16 Update Review and Identification of Standards for CO2 Storage Capacity Estimation

17 Update Examine Risk Assessment Standards and Procedures

A maturing area.

18 Update Utilization Options of CO2 See no. 6 Yes? 19 Update Technical Challenges of

Conversion of CO2-EOR Projects to CO2 Storage Projects

20 Update CCS Technology Opportunities and Gaps

No No Probably covered, at least partly, by Nos. 2, 15, and 24

No

21 Update Reviewing Best Practices and Standards for Geologic Monitoring and Storage of CO2

A maturing area, and covered in part by ISO. However, web-solution was developed (GCCSI) and it could be

updated by GCCSI

Y?

22 Update Technical Barriers and R&D Opportunities for Offshore, Sub-Seabed Storage of CO2

No No On-going Workshops on this topic No

23 Update CO2 Storage Efficiency No No IEAGHG has two recent studies on this, and is an ongoing topic No 24 Update 2nd and 3rd Generation

Carbon Capture Technologies No No IEAGHG doing second phase on this

CSLF Offshore CO2-EOR Task Force Page 1 of 80 Version: Final 08 November 2017

CARBON SEQUESTRATION LEADERSHIP FORUM

TECHNICAL GROUP

TASK FORCE ON

OFFSHORE CO2-EOR

Enabling Large-scale CCS using Offshore CO2 Utilization and Storage Infrastructure Developments

CSLF Offshore CO2-EOR Task Force Page 2 of 80 Version: Final 08 November 2017

EXECUTIVE SUMMARY This report represents a review of the current status and potential for offshore CO2EOR and does not necessarily represent the views of individual contributors or their respective employers. RECOMMENDATIONS TO DECISION MAKERS FOR OVERCOMING BARRIERS TO OFFSHORE CO2-EOR The key recommendations from this work is that governments and industry should work together to: Increase the pace in deployment of CCS. This is a prerequisite for offshore CO2-EOR and needs attention at the highest political level. Slow deployment may lead to missed windows of opportunity for CO2-EOR, as the effect of CO2-EOR will be reduced as the field gets more mature and, at some point, the benefit will be insufficient. There are few, if any, developed sources of CO2 close to the offshore fields amenable to CO2-EOR. Start planning regional hubs and transportation infrastructures for CO2. Building the networks will require significant up-front investments and the coordination of stakeholders, including industries, business sectors, and authorities that will have to work together. A one-on-one source to CO2-EOR field linkage is likely to be more expensive per tonne CO2 than a network, and to have low flexibility with respect to reduced need for fresh CO2 and temporary stops in the CO2 production. The activities will include CO2 capture at regional clusters of power and industrial plants, transportation of the CO2 to hubs and to the individual receiving fields, and injection management. Preliminary studies of the feasibility of such systems have already started in some regions, most notably the Gulf of Mexico and the North Sea. Such studies must be followed up. Develop business models for offshore CO2-EOR. Establishing offshore CO2 networks will create many interdependencies and commercial risks concerning both economics and liabilities. Risk- and cost-sharing will be needed. The literature has a few examples that provide some thoughts, but these need to be matured. The business models must include fiscal incentives, e.g., in term of taxes or tax rebates. Support RD&D to develop new technologies. CAPEX and OPEX for offshore CO2-EOR are significant due to needed modifications and additional equipment on the platforms to separate CO2 from the produced oil and gas and to make existing wells and pipes resistant to CO2 corrosion. Development of new technologies can reduce the need for modifications and new equipment, for example, better mobility control or sub-surface separation systems. Use of existing pipelines may also be a way to keep investment costs down. Continue to develop regulations specific to offshore CO2-EOR. Many jurisdictions do not have regulations for offshore CO2-EOR in place. Regulations should include monitoring the CO2 in the underground, both during and particularly after closure and guidelines for when the field transfers into a CO2 storage site. BACKGROUND AND SUMMARY At the Carbon Sequestration Leadership Forum (CSLF) Ministerial meeting in Riyadh, Saudi Arabia, in November 2014, the CSLF Technical Group formed a task force to identify technical barriers and R&D needs/opportunities for offshore enhanced oil recovery using carbon dioxide (CO2-EOR), as a follow-up to earlier task forces on the technical barriers and R&D needs/opportunities related to sub-seabed storage of carbon dioxide and to technical challenges of conversion of CO2-EOR projects to CO2 storage projects.

CSLF Offshore CO2-EOR Task Force Page 3 of 80 Version: Final 08 November 2017 The purpose of Carbon Capture and Storage (CCS) is to reduce emissions of greenhouse gases to the atmosphere as a climate change mitigation activity. CO2-EOR as a technique can serve two purposes:

• Recover additional oil, thus supplying affordable energy and increasing revenues. • Mitigate climate change by reducing CO2 emissions to the atmosphere.

Which of these will be the main driver may differ between countries; however CO2-EOR is widely recognised as a key component of the Carbon Capture Utilization and Storage (CCUS) concept. This report provides an overview of the current technology status, technical barriers, and research and development (R&D) opportunities associated with offshore CO2-EOR. Specifically, the report includes: • Differences between onshore and offshore CO2-EOR. These include more costly facilities

offshore, issues related to CO2 purity, regulatory issues including requirements for monitoring and maturity, well patterns and density, and already high recovery on many offshore fields.

• Summary of global potential and economics of offshore CO2-EOR. The global potential for enhanced oil recovery from offshore field using CO2-EOR is significant but assessments show variations as a result of different approaches.

• Description of the world’s first offshore CO2-EOR project. The Lula project offshore Brazil started injecting CO2 in 2011. Project development history is described.

• Brief description of approaches that may be used to enable offshore CO2-EOR. This includes late-life oil-field infrastructure, isolated satellite projects, reservoir modelling and focus on the residual oil zone (ROZ).

• New and emerging technologies that can reduce the cost of offshore CO2-EOR. Smart and cost efficient topside solutions for processing CO2-rich fluids, subsea technologies for separation and injection of CO2, as well as solutions for improved mobility control are described.

• Brief discussion of the supply chain needed for offshore CO2-EOR. This includes status on pipeline and ship transport, discussions on the need for CO2 infrastructure, and some case studies.

• Discussions on monitoring, verification and accounting (MVA) issues, with emphasis on what is needed and the differences between CO2-EOR and CO2 storage.

• Regulatory requirements and issues for offshore utilization and storage. Examples of national regulations are given, differences between EOR and storage, as well as status on regulations regarding transition from EOR to storage.

Identified barriers to deployment of offshore CO2-EOR CO2-EOR has been used onshore for many decades, particularly in North America but also to some extent in Europe (e.g. in Hungary and Croatia). In the United States (U.S.), the technique currently contributes 280,000 barrels of oil per day, just over 5% of the total U.S. oil production. Offshore, there is only one active project at the Petrobras operated field Lula offshore Brazil. This work has revealed few, if any, technical barriers to offshore CO2-EOR. Elsewhere, the lack of offshore CO2-EOR projects appears to be caused primarily by several barriers, some of which are shared by offshore CO2 storage. The barriers fall in several categories: • Related to technology:

a. High investment costs, CAPEX and additional operational costs, OPEX. b. Loss of production while modifying facilities represents an additional up-front cost.

Technology development can contribute to reduce the cost, although the value is also dependent on the required rate of return.

c. Reservoir characteristics are usually well known for mature oil fields but there will still be uncertainties around reservoir performance and the yield of addition oil.

CSLF Offshore CO2-EOR Task Force Page 4 of 80 Version: Final 08 November 2017 • Related to implementation of CCS in general, where politicians and other decision makers can

contribute: a. Access to sufficient and timely supply of CO2. b. Lack of business models, also for offshore CO2-EOR.

• Regulatory issues that regulators can mitigate: a. There are uncertainties around regulations. It is not clear what requirements different

jurisdictions will place on monitoring the CO2 in the underground. While not being a barrier in itself, monitoring will require different considerations compared to offshore CO2 storage and to onshore CO2-EOR.

• Uncertainties around the revenues, namely the oil price and the cost of CO2. a. Volatile oil prices may prevent operators from implementing offshore CO2-EOR unless

new business models and/or changed tax regimes are implemented to de-risk investments. b. Uncertainties around the price of CO2 the oil field operator must pay to the CO2 supplier,

including the price of the CO2 itself and the transportation costs. The first will often be subject to negotiations between seller and buyer and could be influenced by CO2 prices in a trading scheme.

CSLF Offshore CO2-EOR Task Force Page 5 of 80 Version: Final 08 November 2017

Contents

EXECUTIVE SUMMARY .................................................................................................................................... 2 ACKNOWLEDGEMENTS .................................................................................................................................. 9 1. INTRODUCTION ..................................................................................................................................... 10

1.1. CARBON SEQUESTRATION LEADERSHIP FORUM (CSLF) ........................................................................... 10 1.2 MOTIVATION FOR DOING OFFSHORE CO2-EOR – MAIN DIFFERENCE TO CCS ......................................... 10 1.3 TASK FORCE MANDATE AND OBJECTIVE OF REPORT ................................................................................... 11

2. REVIEW OF OFFSHORE CO2-EOR STORAGE ................................................................................. 12 2.1 CO2-EOR – HOW IT WORKS .............................................................................................................................. 12

2.1.1 In the reservoir ................................................................................................................................................12 2.1.2 CO2 stream quality .........................................................................................................................................13 2.1.3 Facilities for offshore CO2-EOR .................................................................................................................14

2.2 DIFFERENCES ONSHORE VS. OFFSHORE CO2-EOR ........................................................................................ 14 2.3 HISTORY AND STATUS OF OFFSHORE CO2-EOR ............................................................................................ 15 2.4 GLOBAL TECHNICAL POTENTIAL FOR CO2-EOR INCREMENTAL OIL AND CO2 STORAGE........................ 16 2.5 REGIONAL UPDATES OF GLOBAL TECHNICAL POTENTIAL ............................................................................. 17

2.5.1 USA ........................................................................................................................................................................17 2.5.2 North Sea ............................................................................................................................................................17 2.5.3 Other basins and revised global potential ..........................................................................................18

2.6 ECONOMICS OF OFFSHORE CO2-EOR .............................................................................................................. 20 3 INSIGHTS FROM LULA PROJECT – THE WORLD’S FIRST OFFSHORE CO2- EOR PROJECT 23

3.1 BACKGROUND ...................................................................................................................................................... 23 3.2 RESERVOIR CHARACTERIZATION ..................................................................................................................... 25 3.3 ROBUST & FLEXIBLE DEVELOPMENT STRATEGY .......................................................................................... 26 3.4 MATERIALS .......................................................................................................................................................... 27 3.5 INTELLIGENT COMPLETION ............................................................................................................................... 27 3.6 PRODUCTION UNITS/TOPSIDE FACILITIES .................................................................................................... 28 3.7 LULA WAG PILOT ............................................................................................................................................... 28

4. APPROACHES FOR ENABLING OFFSHORE CO2-EOR .................................................................. 29 4.1 SMART SOLUTIONS FOR OFFSHORE CO2-EOR OPERATIONS: ...................................................................... 30 4.2 USING LATE-LIFE OILFIELD INFRASTRUCTURE .............................................................................................. 30 4.3 USING ISOLATED OILFIELD SATELLITE PROJECTS FOR DEDICATED CO2-EOR PROJECTS ........................ 30 4.4 FOCUSING ON CO2-EOR FOR RESIDUAL OIL ZONE RESERVOIRS OFFSHORE ............................................. 31 4.5 CO2-EOR RESERVOIR MODELLING, SIMULATION AND OPTIMIZATION ISSUES ....................................... 31 4.6 APPLICATION OF NUMERICAL RESERVOIR SIMULATION IN CO2-EOR ....................................................... 32

5. EMERGING TECHNICAL SOLUTIONS FOR OFFSHORE CO2-EOR AND STORAGE ............. 33 5.1 INTRODUCTION .................................................................................................................................................... 33 5.2 TOPSIDE SOLUTIONS ........................................................................................................................................... 34

5.2.1 Goodyear study ................................................................................................................................................34 5.2.2 Salim study ........................................................................................................................................................35 5.2.3 Energy Institute assessment ......................................................................................................................36 5.2.4 Studies on the Norwegian Continental Shelf (NCS) ........................................................................37

5.3 SUBSEA SOLUTIONS ............................................................................................................................................. 40

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5.3.1 Subsea CO2 processing ..................................................................................................................................40 5.4 NOVEL TECHNOLOGY ENABLING CO2-EOR .................................................................................................... 42

5.4.1 CO2 separation .................................................................................................................................................42 5.4.2 Oxy-fuel power generation .........................................................................................................................44

5.5 NOVEL WELL TECHNOLOGY ............................................................................................................................... 46 5.5.1 SWAG – Water Above Gas ...........................................................................................................................46 5.5.2 WAG – alternating water gas injection ................................................................................................48

5.6 MOBILITY CONTROL FOR CO2-EOR .............................................................................................................. 48 5.7 CONCLUSIONS ...................................................................................................................................................... 51

6. CO2 SUPPLY CHAIN ISSUES ................................................................................................................ 51 6.1 CONSIDERATIONS WHEN CHOOSING TRANSPORT METHODS ...................................................................... 51 6.2 STATUS AND CHALLENGES - PIPELINES ........................................................................................................... 52 6.3 STATUS AND CHALLENGES – SHIP TRANSPORT .............................................................................................. 53 6.4 INITIATING NEW OFFSHORE TRANSPORT SYSTEMS ....................................................................................... 55 6.5 CASE STUDIES ...................................................................................................................................................... 55

6.5.1 UK case studies.................................................................................................................................................55 6.5.2 A Norwegian case – Gullfaks .....................................................................................................................56 6.5.3 A Vietnam case – Rang Dong Field .........................................................................................................57

6.6 CONCLUSIONS ...................................................................................................................................................... 58 7. MONITORING, VERIFICATION AND ACCOUNTING TOOLS FOR OFFSHORE CO2-EOR ... 58

7.1 ROLES AND EXPECTATIONS OF MONITORING, VERIFICATION AND ASSESSMENT FOR OFFSHORE CO2-EOR 60 7.2 DIFFERENCES BETWEEN MVA FOR CO2-EOR AND STORAGE OF CO2 ...................................................... 62 7.3 DIFFERENCES BETWEEN MVA FOR ONSHORE CO2-EOR AND OFFSHORE CO2-EOR ............................. 63 7.4 TRANSITION CO2-EOR TO STORAGE – IMPACT ON MONITORING .............................................................. 64 7.5 CONCLUSIONS ...................................................................................................................................................... 64

8. REGULATORY REQUIREMENTS FOR OFFSHORE CO2 UTILIZATION AND STORAGE ..... 65 8.1 INTRODUCTION AND SCENE-SETTING .............................................................................................................. 65 8.2 EXAMPLES OF SPECIFIC NATIONAL REGULATORY REQUIREMENTS ........................................................... 65

8.2.1 UK ...........................................................................................................................................................................65 8.2.2 United States .....................................................................................................................................................66 8.2.3 Brazil ....................................................................................................................................................................66 8.2.4 Gulf Cooperation Council Countries .......................................................................................................66

8.3 DIFFERENCES BETWEEN REGULATORY FRAMEWORKS FOR STORAGE AND EOR ..................................... 67 8.4 REGULATIONS ON TRANSITION OF CO2-EOR TO STORAGE: WHAT IS LACKING AND RECOMMENDATIONS HOW THIS MAY BE ACHIEVED .................................................................................................. 67 8.5 CONCLUSIONS ...................................................................................................................................................... 68

9. SUMMARY OF BARRIERS FOR DEPLOYMENT OF OFFSHORE CO2-EOR ............................. 68 10. RECOMMENDATIONS FOR OVERCOMING BARRIERS FOR OFFSHORE CO2-EOR .......... 69 REFERENCES ................................................................................................................................................... 70 LIST OF FIGURES Figure 2.1. Schematic showing the principles of miscible CO2-EOR. From ARI & Meltzer Consulting (2010)……………………………………………………………………………..13 Figure 2.2. Schematic diagram of offshore CO2-EOR project facilities. From Goodyear et al. (2011)…………………………………………………………………………..14 Figure 2.3. Basins for which the potential for incremental oil production and CO2 storage have been assessed, see Table 2.3………………………………………………………………………………...19

CSLF Offshore CO2-EOR Task Force Page 7 of 80 Version: Final 08 November 2017 Figure 2.4. Possible cash flow in an offshore CO2-EOR project. All numbers are fictitious but the presentation form is based on examples in Welkenhyusen et al. (2015) and IEAGHG (2016). ………………………………………………………………………….21 Figure 2.5. Gulf of Mexico oil recovery potential with current as well as “next generation” technology (After Malone et al., 2014)………………………………………………………………..22 Figure 3.1- Location of the Lula Filed (red cross)…………………………………………………….23 Figure 4.1- Illustration of the subsea satellite fields Alve, Stær and Svale developed by tie-back to the main Norne field (photo courtesy of Statoil ASA)…………………………..............,,.31 Figure 5.1. Areas that are affected on topsides facilities by introducing offshore CO2-EOR operations according to Salim et al (2012)………………………………………………………….....35 Figure 5.2. Processing facilities on a new topsides EOR module according to Salim et al (2012)……………………………………………………………………………………...36 Figure 5.3. A proposed schematic of two various options for topsides treatment of well stream from a CO2 flood from EI (2013)…………………………………………………………37 Figure 5.4. Interfaces between existing infrastructure and new building blocks (Courtesy Aker Solutions)……………………………………………………………….…….38 Figure 5.5. Flow diagram showing modifications to and new equipment for the case C4. (Courtesy Aker Solutions)…………………………………………………………………...39 Figure 5.6. Main functions of a typical processing concept for CO2-EOR. (Courtesy Aker Solutions)……………………………………………………………………………..41 Figure 5.7. Supersonic nozzle with liquid separation. (From Netušil and Ditl, 2012)………………..43 Figure 5.8. Basic system for supersonic CO2 separation. (From Imaev et al,, 2014)………………....44 Figure 5.9. Illustration of subsea zero emission offshore power generation concept (Courtesy Aker Solutions)………………………………………………………………………….....46 Figure 5.10. XMT and downhole schematic, SWAG water injection through annulus. (Courtesy Aker Solutions)…………………………………………………………………………......47 Figure 6.1. Bow to stern loading from shuttle tanker (Courtesy Aker Solutions)………………….....54 Figure 6.2 Shuttle tanker connecting directly to offloading buoy. (Courtesy Aker Solutions)…….....54 Figure 6.3. Conceptual vision of CO2 storage beneath the North Sea, linked to emission sources with capture. The insert shows fields in the UK Central North Sea which have been found particularly suitable technically and economically for CO2-EOR. From SCCS (2015)……………………………....,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,……...56 Figure 6.4. A network of sources and transportation means to supply Gullfaks with 5.5 MT CO2/year. From Elsam (2003)…………………………………………………………...57 Figure 6.5. Location of the Rang Dong Field relative to the CO2 sources. From (Kawahara, 2016)……………………………………………………………………………......58 LIST OF TABLES Table 2.1. US Gulf of Mexico technical oil recovery potential and associated CO2 storage potential, current and “next generation” technologies……………………………….…...17 Table 2.2. Potential incremental oil production and CO2 stored from applying CO2-EOR in the North Sea ……………………………………………………………………………18 Table 2.3. Potential incremental oil production and CO2 permanently stored in he basins shown in Figure 2.3………………………………………………………………………….19 Table 2.4. Some key input parameters to CO2-EOR profitability studies and their relevant scales………………………………………………………………………….. ………..20 Table 2.5. US Gulf of Mexico economic oil recovery and associated CO2 storage potential, current and “next generation” technologies………………………………………...22 Table 4.1. Comparison of oil recovery factor using various injection techniques in an off-shore reservoir…………………………………………………………………...33 Table 7.1. Examples of MVA studies and projects for storage settings other than offshore EOR…………………………………………………………………………………….59 Table 7.2. General background on MVA (not specific to Offshore CO2 EOR settings……………....59

CSLF Offshore CO2-EOR Task Force Page 8 of 80 Version: Final 08 November 2017 Table 7.3. Resources on offshore monitoring……………………………………………………….59 Table 7.4. Resources on CO2 EOR monitoring (with a focus on onshore settings)………………...60 Table 7.5. Comparing risks for CO2-EOR and storage of CO2 (Adapted from Hill et al., 2013)…………………………………………………………………….62 Table 8.1. Overview of regulatory status of selected countries/regions (after CCP, 2016)………...67

CSLF Offshore CO2-EOR Task Force Page 9 of 80 Version: Final 08 November 2017 ACKNOWLEDGEMENTS This report was prepared for the CSLF Technical Group by the Task Force on Offshore CO2-EOR. The Task Force chair, Lars Ingolf Eide (Norway) thanks the following participants for their contributions and efforts: Susan Hovorka, (University of Texas at Austin, U.S.) Melissa Batum (U.S. Department of the Interior, Bureau of Ocean Energy Management) Tim Dixon (IEA Greenhouse Gas R&D Programme) David Ryan (Natural Resources Canada | Resources naturelles Canada) Raphael Augusto Mello Vieira(Petrobras, B razil) Heron Gachuz Muro (Pemex Exploration and Production, Mexico Philip Ringrose (Statoil, Norway) Sveinung Hagen (Statoil, Norway) Bamshad Nazarian (Statoil, Norway) Arne Graue (University of Bergen, Norway) Pål Helge Nøkleby (Aker Solutions, Norway) Geir Inge Olsen (Aker Solutions, Norway) Zabia Elamin (Aker Solutions, Norway) Each individual and their respective country have provided the necessary resources to enable the development of this work. The task force members would like to thank John Huston of Leonardo Technologies, Inc. (United States), reviewing and suggest valuable editorial input to the report. This report represents a review of the current status and potential for offshore CO2-EOR and does not necessarily represent the views of individual contributors or their respective employers.

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1. Introduction

1.1. Carbon Sequestration Leadership Forum (CSLF) The Carbon Sequestration Leadership Forum (CSLF; https://www.cslforum.org ) is a Ministerial-level international climate change initiative that is focused on the development of improved cost-effective technologies for the separation and capture of CO2 for its transport and long-term safe storage. Its mission is to facilitate the development and deployment of such technologies via collaborative efforts that address key technical, economic, and environmental obstacles. The CSLF comprises a Policy Group (PG) and a Technical Group (TG). The PG governs the overall framework and policies of the CSLF, and focuses mainly on policy, legal, regulatory, financial, economic, and capacity building issues. The TG reports to the PG and focuses on technical issues related to Carbon Capture, Utilization and Storage (CCUS) and on CCUS projects in member countries. At the CSLF Ministerial meeting in Riyadh, Saudi Arabia, in November 2014, the CSLF Technical Group formally moved forward with a task force to identify technical barriers and R&D needs/opportunities for offshore enhanced oil recovery (EOR) using carbon dioxide (CO2-EOR), as a follow-up to earlier task forces on the technical barriers and R&D needs/opportunities related to sub-seabed storage of carbon dioxide (CSLF, 2015) and to technical challenges of conversion of CO2-EOR projects to CO2 storage projects (CSLF, 2013).

1.2 Motivation for doing offshore CO2-EOR – main difference to CCS The purpose of injecting of CO2 into an oil reservoir is to enhance oil recovery (hereinafter called CO2-EOR). The technology has been in operation onshore for over 40 years (Enick et al., 2012), particularly in North America. In the United States, the technique currently contributes 280,000 barrels of oil per day, just over 5% of the total U.S. oil production. CO2 injection for EOR can be an effective way to recover additional oil after water-floods or pressure depletion, while at the same time store large quantities of CO2 underground (Malik and Islan, 2000). The purpose of Carbon Capture and Storage (CCS) is to reduce emissions of greenhouse gases to the atmosphere as a climate change mitigation activity. CCS with CO2 injection into sedimentary rocks is considered to be an important, large-scale solution for reducing the emission of anthropogenic CO2 (IPPC, 2005). For example, the storage capacity in saline aquifers and mature hydrocarbon reservoirs located in the North Sea formations will likely be sufficient for all EU point sources for the fossil era. Offshore injection and storage of CO2 into geological formations for the purpose of preventing it from reaching the atmosphere (Carbon Capture and Storage, hereinafter called CCS) has taken place in Norway since 1996 (IEA, 2016a). CO2-EOR as a technique can thus serve two purposes:

• Recover additional oil, thus supplying affordable energy and increasing revenues. • Mitigating climate change by reducing CO2 emissions to the atmosphere.

Which of these will be the main driver may differ between countries.

CSLF Offshore CO2-EOR Task Force Page 11 of 80 Version: Final 08 November 2017 Other differences between CCS and CO2-EOR are (CSLF, 2013; CCP1, 2016):

• CO2 quality and purity: CCS projects are based on anthropogenic CO2 whereas the majority of CO2-EOR projects have used natural occurring CO2 until the present.

• Regulatory issues: CO2-EOR and CCS projects are regulated differently (see Section 7.3). Benefits and technical aspects of CO2-EOR are discussed in earlier CSLF reports (CSLF 2013, 2015). CO2-EOR projects are primarily implemented to increase tertiary oil production and any long-term storage of CO2 will be a potential ancillary benefit. When projects are designed as CCS projects from the start, there is typically a site evaluation process to review the storage formation according to best practice criteria for CCS. Offshore CO2-EOR is seen as a way to catalyse offshore storage opportunities and start building the necessary infrastructure networks. It will also help to address both global energy needs and the current climate-change challenges. Huge amounts of energy are needed for future generations to sustain or improve standard of living, thus existing energy supply needs to be optimized in an environmental friendly way and new energy resources must be found. IEA2 estimates that 45% of the primary energy supply, even in a two-degree scenario (2DS3), will be from fossil fuels by 2050 (IEA, 2016). To keep CO2 emissions from the fossil sources sufficiently low to meet the 2DS target, IEA argues that CCS will have to play a significant role. Two aspects of these strategies utilise CO2 as a commodity: CO2 for EOR as enabler of CCUS (Carbon Capture, Utilization and Storage), and CO2 injection in hydrates; the latter being a potential win-win situation for CO2 storage with simultaneous natural gas production (Graue et al. 2006, Birkedal, et al., 2010, Graue et al., 2008, Kvamme et al., 2007). However, CO2 injection in hydrates is an immature technology and a major challenge is up-scaling laboratory results to the field scale.

A plausible future scenario is that the need for reduced CO2 emissions may be reached by CCS and CCUS, with CO2-EOR and saline aquifer storage as the main contributors. An international approach will ensure that the effort has interdisciplinary expertise from different countries, such as the knowledge transfer opportunities from CCUS experience in the USA combined with sharing experience from recent large scale offshore experience from Brazil. Collaboration between countries on different continents contributes to effectively disseminate results globally.

1.3 Task Force Mandate and Objective of report The main barriers reported widely for offshore CO2-EOR projects are the investment required for the modification of platforms and installations, the lost revenue during modification, the lack of CO2, and the lack of a transportation infrastructure. Recent advances in subsea separation and processing could extend the current level of utilization of sea bottom equipment to also include the handling of CO2 streams. It has been recommended that RD&D activities explore opportunities to leverage existing infrastructure and field test advances in subsea separation and processing equipment (CSLF, 2015).

The CSLF Offshore Storage Task Force report (CSLF, 2015) covered some of the above topics related to offshore CO2-EOR, but the CSLF TG found that a more in-depth review may be warranted. Thus, the Offshore CO2-EOR Task Force was mandated to review and summarize recent findings, including

1 CCP4 = CO2 Capture Project (CCP) is a partnership of major energy companies working together to advance CCS technologies 2 IEA: International Energy Agency 3 An emissions trajectory that will give a 50 % chance of limiting the rise in the average global temperature from anthropogenic GHG emissions to 2oC

CSLF Offshore CO2-EOR Task Force Page 12 of 80 Version: Final 08 November 2017 the additional monitoring techniques that may be applied offshore. It may position CSLF to encourage members to implement the technology. Norway volunteered to serve as chair of the task force whose mandate is to develop a report that will:

• Summarize current assessment or understanding (using available analyses) on the status of global offshore CO2-EOR storage potential;

• Identify existing projects and characterization activities worldwide on offshore CO2-EOR storage and progress to date;

• Identify the technical barriers/challenges to offshore CO2-EOR storage (e.g., availability of CO2, HSE4, monitoring, use of existing offshore facilities; transport challenges and R&D opportunities);

• Summarize the main differences between offshore and onshore CO2-EOR; • Discuss issues that are different between offshore CO2-EOR and pure offshore CO2 storage; • Point to technical solutions that will benefit both pure offshore CO2 storage and offshore CO2-

EOR; • Identify potential opportunities for global collaboration; and • Include conclusions and recommendations for consideration by CSLF and its member

countries.

2. REVIEW OF OFFSHORE CO2-EOR STORAGE

2.1 CO2-EOR – how it works 2.1.1 In the reservoir Enhanced oil recovery (EOR) is a term used for a set of techniques that increase the amount of crude oil that can be extracted from an oil field. Oil recovery is also classified as using primary pressure depletion, secondary (mainly waterflooding) and tertiary recovery mechanisms (including CO2 or gas injection). Waterflooding is the dominant oil recovery mechanism globally, but tertiary mechanisms are being increasingly applied. In the United States the injected gas is primarily CO2, whereas in the North Sea natural gas injection dominates. In CO2 injection projects, the injected CO2 may contain H2S in which case the process is then termed sour gas injection. In the CO2-EOR process, CO2 is injected into an oil reservoir under high pressure. Oil displacement by CO2 injection relies on the phase behaviour and properties of the mixture of CO2 and oil, which are strongly dependent on reservoir temperature, pressure and oil composition. There are two main types of CO2-EOR processes (ARI and Melzer, 2010): Miscible CO2-EOR is a multiple contact process involving interactions between the injected CO2 and the reservoir’s oil. During this multiple contact process, CO2 vaporizes the lighter oil fractions into the injected CO2 phase and CO2 condenses into the reservoir’s oil phase. This leads to two reservoir fluids that become miscible (mixing in all parts), with favourable properties of low viscosity, enhanced mobility, and low interfacial tension. The primary objective of miscible CO2-EOR is to remobilize and dramatically reduce the residual oil saturation in the reservoir’s pore space after water flooding. Figure 2.1 provides a one-dimensional schematic showing the dynamics of the miscible CO2-EOR process. Miscible CO2-EOR is by far the most dominant form of CO2-EOR deployed. In some cases, the miscible CO2-EOR process may not be fully miscible with portions of the displacement being

4 HSE = Health, Safety and Environment

CSLF Offshore CO2-EOR Task Force Page 13 of 80 Version: Final 08 November 2017 immiscible (e.g., due to pressure drops). Immiscible CO2-EOR occurs when insufficient reservoir pressure is available or the reservoir’s oil composition is less favourable (heavier). The main mechanisms involved in immiscible CO2 flooding are: (1) oil phase swelling, as the oil becomes saturated with CO2; (2) viscosity reduction of the swollen oil and CO2 mixture; (3) extraction of lighter hydrocarbon into the CO2 phase; and, (4) fluid displacement. This combination of mechanisms enables a portion of the reservoir’s remaining oil to still be mobilized and produced, and is commercial in many instances.

Figure 2.1. Schematic showing the principles of miscible CO2-EOR. From IEAGHG (2009 reprinted

with permission from IEAGHG

2.1.2 CO2 stream quality The exact conditions for achieving miscibility are reservoir-specific because flooding a reservoir with CO2 for CO2-EOR must meet a specific combination of conditions defined by reservoir temperature, reservoir pressure, injected gas composition, and oil chemical composition. Impurities in the injected CO2 stream in a CO2-EOR project could hinder the ability of the injected fluid to meet the criteria for achieving miscibility (Godec, 2011). The specifications for the CO2 stream quality will also be dictated by requirements for the safe, reliable, and cost effective transport of the CO2. Impurities in the CO2 stream can impact the transport capacity of the pipeline, the potential for micro-fractures in the pipeline, and other safety and operational considerations. Meeting such pipeline standards has permitted the CO2 pipeline industry to safely transport CO2 with no demonstrated examples of substantial leakage, rupture, or incident. In fact, CO2 pipelines in the U.S. have a safety record which is better than that of comparable natural gas pipelines. Thus, meeting the specifications for CO2-EOR should also allow for the safe, reliable, and economical transport of CO2 (Godec, 2011). However, a consensus on the CO2 stream composition for pipeline transport appears to be lacking. The new ISO standard on Transportation of CO2 (ISO, 2016) gives no recommendation due to lack of published data by stating that “The most up to date

CSLF Offshore CO2-EOR Task Force Page 14 of 80 Version: Final 08 November 2017 research should be consulted during pipeline design”. However, some example CO2 stream compositions are given by De Visser et al. (2008), indicating that typical compositions are around 95-96% CO2 with hydrocarbon gas fractions around 2-5%. 2.1.3 Facilities for offshore CO2-EOR In a CO2-EOR operation floodable hydrocarbons (mainly oil), CO2 and brine are produced to surface at production well(s). The elements involved in a typical offshore CO2-EOR are indicated in Figure 2.2 (Goodyear et al., 2011). Flue gas from onshore sources (anthropogenic or natural) is compressed for transport. In the case of Figure 2.2 transport is by pipeline but it could also be transported by ship. With a ship solution the onshore compressor station would be replaced by a conditioning unit (which may also include a compressor). The CO2 arrives at a central processing facility (CPF), where it may be boosted to obtain injection pressure. For safety reasons the CPF is located close to the injection point, here illustrated as a separate wellhead platform (WHP). After sweeping the oil reservoir, back produced CO2 along with oil, brine, and hydrocarbon gas are routed back to the CPF, oil is separated for export, brine treated and disposed and the recovered CO2 mixed with imported CO2, compressed and re-injected. The amount of back produced CO2 increases with time and need for imported CO2 decreases over time.

Figure 2.2. Schematic diagram of offshore CO2-EOR project facilities. Based on an illustration by Goodyear et al. (2011),

2.2 Differences onshore vs. offshore CO2-EOR The production mechanisms are principally the same in onshore and offshore CO2-EOR settings, and future CO2-EOR operations offshore will mimic and utilise technologies known from the more matured on-shore business, in order to increase recoverable resources from the reservoir. However, offshore implementation poses additional challenges that include: • Onshore CO2-EOR has been conducted for several decades and is a mature technology, whereas

large-scale offshore CO2-EOR has been on-going for about five years only (Lula project, Chapter 3 below).

• Offshore operations are conducted from a platform, or via subsea facilities tied back to a platform, creating both technical and financial hurdles.

• Well patterns differ significantly between onshore and offshore projects. Offshore wells tend to be horizontal and onshore wells vertical. This usually implies a higher well density onshore than offshore and may require special considerations offshore, as discussed by, amongst others, Goodyear et al. (2011) and Stuart and Haszeldine (2014)

CSLF Offshore CO2-EOR Task Force Page 15 of 80 Version: Final 08 November 2017 • The investments (CAPEX) required for the modification of existing platforms, wells, and other

installations will be higher offshore than onshore, and the lost revenue during the modification process can be a very significant factor. However, new fields can be designed for the requirements of CO2-EOR cost effectively.

• Operational costs (OPEX) and maintenance are more costly offshore than onshore. • Offshore fields have often achieved higher recovery (prior to potential start of CO2-EOR) due to

the higher investment in well technology (e.g., horizontal wells) and reservoir management (e.g., use for time-lapse seismic). There may thus be less to gain from CO2-EOR as compared with onshore fields where only waterflood from vertical wells has been applied prior to CO2-EOR.

• In a CO2-EOR operation offshore, CO2 will be delivered by ship or offshore pipeline, both creating additional costs compared to the onshore solution. The CO2 may be injected directly into the wells, or temporarily stored (in floating storage vessels), enabling a choice of injection strategies.

• There are differences in the reservoir management capability, foremost due to larger well spacing offshore and the constraints of operating from a platform.

Despite these additional challenges for offshore CO2-EOR, there may also be some upsides for the offshore setting, such as: • Offshore leases will generally be owned by single licensing authorities, making offshore CO2-

EOR projects less complex to plan and execute. • Larger field sizes offshore may correspond to significant potential for higher additional production

from CO2-EOR.

2.3 History and status of offshore CO2-EOR Significant experience exists in onshore CO2 injection for EOR. There has been extensive offshore exploration and production of hydrocarbons since the 1960s in many basins throughout the world, however, the use of CO2-EOR offshore is very limited so far. CSLF (2015) gives an overview of the history and status of offshore CO2

-EOR, which is summarized below. The cases for which CO2 has been considered to enhance offshore hydrocarbon production include: 1. In Malaysia (Sarawak), the enormous Petronas K5 Project and other prospects in the southern

South China Sea propose to produce natural gas from fields with up to 70% carbon dioxide. The concept being pursued is to use the CO2 to boost production in depleting nearby offshore oilfields.

2. In Vietnam, a small-scale pilot test was conducted at the Rang Dong Oilfield, located 135 km off the coast of Vung Tau, in 2011. In the project, 111 tonnes (t) of CO2 were injected through an existing production well, followed by a four-day oil recovery test with the same well two days later. The test was successful and an extended inter-well pilot test is under planning as a next step (Ueada, 2013).

3. Offshore Norway, several technical feasibility studies for CO2-EOR have been conducted, for example at the giant Gullfaks field (sandstone; Augustsson, 2005), the Heidrun and Draugen feilds (sandstone; Carbon Capture Journal, 2007) and the Ekofisk field (chalk; Hustad and Austell, 2004). These studies demonstrated the technical feasibility of large-scale CO2 injection for EOR offshore, but have not progressed past the feasibility stage. More recently, Holt et al. (2009), Pershad et al. (2012, 2014), NPD5 (2014), Energy Research Partnership (2015), SCCS6 (2015), Welkenhuysen et al. (2015, 2017), IEAGHG7 (2016) and Lindeberg et al. (2017) have studied the general potential and economics of CO2-EOR in the North Sea. In the UK offshore sector at least three projects were considered for CO2-EOR (Malone et al., 2014). However, no projects have progressed past the feasibility stage mainly due to economic factors, but also due to the lack of sufficient volumes of CO2. In order to enable large-scale CO2-EOR in the offshore sector, it is

5 NPD = Norwegian Petroleum Directorate 6 SCCS = Scottish Carbon Capture and Storage 7 IEAGHG = IEA GreenHouse Gas R&D Programme

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clear that initiatives to initiate CO2 capture and supply infrastructure are needed (Markussen et al., 2002).

4. In the Gulf of Mexico, five CO2-EOR pilots were carried out in Louisiana’s shallow near-shore and bay waters in the 1980s. These were Quarantine Bay, Timbalier Bay, Bay St. Elaine Field, Weeks Island Field and Paradis Field. In all pilots the CO2 was delivered to the injection site by barges where the CO2 was injected followed by either nitrogen or field gas in a gravity stable strategy. All pilots were considered successful (Malone et al., 2014).

5. Other offshore investigations for CO2-EOR have been performed for Abu Dhabi (Persian Gulf) and the South China Sea (SCS; Pearl River Mouth Basin; Huizhou 21-1 Field) (Malone et al., 2014). In general, the SCS opportunities are similar in technical aspects and original recovery percentages to the North Sea Basin, Gulf of Mexico, and Brazil, although the field sizes for SCS are somewhat smaller. SCS has favourable light oil compositions (low density and viscosity), relatively high porosity and permeability, and shallow water depth (CSLF, 2015).

2.4 Global technical potential for CO2-EOR incremental oil and CO2 storage A range of methods are presently used to estimate potential for EOR and CO2 storage. Direct comparisons of various publications are therefore difficult. The summary below gives a global overview based on the IEAGHG (2009) report where the same approach was used for all assessed basins. The estimates for some of the regions in IEAGHG (2009) have been updated but not necessarily with the same assessment methods. These later estimates are quoted without consideration as to the quality of the methods. If the cited reference indicates whether the estimates are technically or economically feasible, this is indicated in the summary. For consistency, we start with the global overview from IEAGHG (2009) and revert to more recent publications later in this section. IEAGHG (2009) used formulas to estimate a CO2-EOR recovery efficiency factor (EOR%) in percent of original oil in place (OOIP). Sandstone and carbonate reservoirs were considered separately and the formulas were derived by regression analysis using Advanced Resources Institute’s (ARI) EOR performance and reservoir data for US domestic oil reservoirs, involving API of the reservoir oil and the reservoir depth. The average EOR% for all basins considered in IEAGHG (2009) was found to be 21%. The potential for CO2 stored was estimated in a similar way. According to IEAGHG (2009) the technically recoverable CO2-EOR oil from fields in that assessment is 95.000 million barrels of oil (15.2 GSm3), with a potential for storage of 29.2 Gt CO2, giving a ratio of tonnes CO2/barrels of oil of 0.307. The largest potential is indicated to be found in the Rub Al Khali basin in the United Arab Emirates (UAE), with a potential for stored CO2 of 8.8 Gt and technical recovery of 28,000 million barrels of oil, followed by the Maracaibo Basin, Venezuela (4.5 Gt CO2 and 14,300 million barrels of oil), and the North Sea (4 Gt CO2 and 14,400 million barrels of oil). Note, however, that the North Sea estimate was based on 14 sandstone fields in the UK sector of the North Sea Graben Basin and did not include fields in the Norwegian sector. The Niger delta, Nigeria, was estimated to have the potential to store 3.1 Gt CO2 and to produce an additional 10,400 million barrels of oil. The estimates in IEAGHG (2009) for the US Gulf of Mexico (GoM) included only oil fields offshore the state of Louisiana. According to Vidas et al. (2012), this is where the majority of potential CO2-EOR fields are located. Vidas et al. (2012) estimated the CO2 storage potential from EOR to be 1.5 Gt CO2, close to the estimate of IEAGHG (2009). However, a map in ISO (2017; draft only, to be published) indicates that the potential for CO2 storage in EOR fields for GoM is as much as 14.2 Gt CO2.

CSLF Offshore CO2-EOR Task Force Page 17 of 80 Version: Final 08 November 2017 2.5 Regional updates of global technical potential 2.5.1 USA Malone et al. (2014) used a reservoir model (CO2-PROPHET) to estimate the potential additional oil recovery and CO2 storage from CO2-EOR in the Gulf of Mexico (GoM). The average EOR% was found to 18%, fairly close to the average in IEAGHG (2009). Using what was termed “current” CO2-EOR technology, Malone et al. (2014) estimated the technical potential for incremental oil production and CO2 storage to 23,500 million barrels of oil (3760 Sm3) and 12.64 Gt CO2, which compares to 4, 600 million barrels and 1.6 Gt CO2 in Figure 2.3. Malone et al. (2014) assessed the potential for CO2-EOR for the GoM offshore oil fields using “current CO2-EOR technology” and “next generation CO2-EOR technology”. The latter is defined to consist of four “major” technological improvements over current CO2-EOR technology:

• Improved reservoir conformance • Advanced CO2 flood design • Enhanced mobility control and injectivity, and • Increased volumes of efficiently used CO2.

The results are shown in Table 2.1. Table 2.1. US Gulf of Mexico technical oil recovery potential and associated CO2 storage potential, current and “next generation” technologies Current technology “Next generation “ technology Total technical viable oil recovery (millions of barrels)

23,500 53,900

Total CO2 demand/storage capacity (Gt) 12.64 15.1 2.5.2 North Sea In the North Sea, field gas is used on a large scale for enhanced recovery, with total volumes of gas of the order of 35 Gm3/yr (Cavanagh and Ringrose, 2014). However, there are no fields that use CO2 for EOR. One of the key challenges for CO2-EOR in the North Sea is that existing gas-based recovery methods offer economically and technically attractive solutions, reducing the potential benefits of CO2 –EOR, especially if additional facility conversion costs are taken into account.

Pershad et al. (2013) estimated the theoretical incremental oil production using CO2-EOR in the North Sea assuming it will be 10% of OOIP. Using this approach on 19 fields in the UK sector, nine in the Norwegian sector, and two in the Danish sector Pershad et al. (2013) estimated the potential for incremental oil production in barrels and CO2 storage in tonnes. Their results were updated by IEAGHG (2016) with incremental oil production for 12 fields in the Norwegian sector, including eight from Pershad et al. (2013) but given in Sm3 (for the UK sector they used the same 19 fields as Pershad et al. (2012), but with volumes in barrels). Table 2.2 summarises the results using the following assumptions:

1. In the UK sector all numbers are from Pershad et al. (2013) 2. In the Norwegian sector incremental oil production is from IEAGHG (2016) + one field

(Tordis) from Pershad et al. (2013) 3. Conversion factors 1 barrel = 0.16 Sm3 4. In the Norwegian sector a CO2/oil ratio = 0.25 tonnes/barrel excluding Statfjord and 0.27

including Statfjord as the average of numbers from Element Pershad et al. (2012).

CSLF Offshore CO2-EOR Task Force Page 18 of 80 Version: Final 08 November 2017 Table 2.2. Potential incremental oil production and CO2 stored from applying CO2-EOR in the North Sea (Combined data from Pershad et al., 2012, and IEAGHG, 2016). Conversion used: 1 barrel = 0,16 Sm3, CO2/oil ratio = 0.25 tonnes/barrel excluding Statfjord and 0.27 including Statfjord in the Norwegian sector

Sector Incremental oil production, from CO2-EOR, million Sm3

CO2 stored during EOR (Mt CO2)

UK (all numbers from Pershad et al. (2012)

From 403* to 496 From 852* to 1031

Norway (oil production from IEAGHG (2016) + Tordis field from Pershad et al. (2013) and stored CO2 using factors as given in caption)

From 577** to 679 From 1082** to 1273

Denmark (all numbers from Pershad et al. (2013)

62 109

TOTAL From 1042*** to 1237 From 2043*** to 2413

*Excluding Brent and Miller, which are known to be unsuited for or have significant challenges with CO2-EOR ** Excluding Statfjord, which is known to be unsuited for or have significant challenges with CO2-EOR *** Excluding Brent, Miller and Statfjord Thus the incremental oil production, from CO2-EOR and the CO2 stored during EOR in the North Sea according to Table 2.2 (Pershad et al., 2012) is half of what IEAGHG (2009) estimated (Figure 2.3). This is probably due to the assumption in Pershad et al. (2013) that the incremental oil is 10% of OOIP, whereas IEAGHG (2009) and Malone et al. (2014) used derived values of 21% and 18%, respectively. In a recent study by Karimaie et al. (2016) simulations using a realistic model of a North Sea oil reservoir were used to assess the performance of CO2 injection for oil recovery compared to a base case water injection. This study demonstrated the importance of the well design with a range in incremental oil from close to zero (for vertical well) and up to 8% (for a horizontal well). 2.5.3 Other basins and revised global potential Figure 2.3 shows basins for which the potential for incremental oil production and CO2 storage have been assessed by IEAGHG (2009), Malone et al. (2014) and ISO (2017; draft only, to be published). ISO (2017; draft only, to be published) included numbers offshore California, Jeanne d’Arc, Bohai Bay, Pearl River Mouth and Beibu Gulf and Malone et al. (2014) assessed all fields in the Gulf of Mexico. Table 2.3 shows the potential for incremental oil production and CO2 storage for all assessed basins. If numbers Table 2.3, i.e. including the numbers from ISO (2017; draft only, to be published) and Malone et al. (2014) are added, the total global potential for CO2 stored amounts to 41.2 Gt CO2. With the same ratio of technically recoverable oil to injected CO2 in the basins where incremental oil has not been estimated as for those where it has been estimated, the potential should be an extra 117 100 million barrels.

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Figure 2.3. Basins for which the potential for incremental oil production and CO2 storage have been

assessed, see Table 2.3

Table 2.3. Potential incremental oil production and CO2 permanently stored in the basins shown in Figure 2.3.

*IEAGHG (2009) ** Malone et al. (2014) *** ISO (2017; draft only, to be published)

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2.6 Economics of offshore CO2-EOR Several factors will play together to decide the profitability of offshore CO2-EOR projects. Some are global and/or regional in scale, some project and site specific. Table 2.4 lists some of the factors and they will all influence the cash flow of the project. Table 2.4. Some key input parameters to CO2-EOR profitability studies and their relevant scales Oil price Global CO2 emission cost Global/

Regional CO2 availability, price, incl. transport Regional

local or project specific Reservoir characteristics (incl. permeability, depth, API)

Site specific

Start of CO2-EOR operation Project specific Project discount rate Project specific Lost production during rebuild and delayed decommissioning cost

Project specific

CAPEX, (incl. modifications, wells, recycling of CO2) Project specific OPEX (incl. separation and compression of CO2) Project specific Regulatory issues, monitoring, decommissioning, closure* and liability

Project specific

* Closure is used as a period that extends beyond the close down of the project or end of oil production (termination). Some further comments to these factors are worth mentioning here: 1. Availability of CO2. There are few, if any, developed sources of CO2 close to the offshore fields

amenable to CO2-EOR. Holt et al. (2009), Kemp and Kasim (2013), Malone et al. (2014) and Lindeberg et al. (2017) all assume that an infrastructure that collects CO2 from several sources and transports it to a number of oil fields is in place. Building an infrastructure will require huge up-front investments and the coordination of several stakeholders. A one-on-one source to CO2-EOR field is likely to be more expensive per tonne CO2 than a network, and have low flexibility with respect to reduced need for fresh CO2 and temporary stops in the CO2 production.

2. Price of CO2 delivered at the fields for EOR. This will include transportation costs, either as cost for building a one-on-one pipeline or tariff costs in a network. In addition comes the price the oil field operator must pay to the CO2 supplier. This will often be subject to negotiations between seller and buyer and could be influenced by CO2 prices in a trading scheme.

3. Timing of the EOR operation. The effect of CO2-EOR will be reduced as the field gets more mature and at some point the benefit will be reduced. A UK study has shown the importance of “window of opportunity” (Energy Research Partnership, 2015). A slow development of CCS will delay opportunities for offshore CO2-EOR.

4. High investment costs. Break-through and recycling of CO2 will require significant modifications and additional equipment on the platforms to separate CO2 from the produced oil and gas and also to make existing well and pipes resistant to CO2 corrosion. CAPEX may come down if technologies are developed that reduce the need for modifications and new equipment, for example better mobility control or sub-surface separation system. Use of existing pipelines may also be a way to keep investment costs down.

5. Additional operational costs, OPEX, will result from the need to separate and recompress the recycled CO2. New technologies are likely to reduce also the OPEX.

6. Reservoir characteristics are usually well known for mature oil fields but there will still be uncertainties around reservoir performance and the potential for additional oil yield.

CSLF Offshore CO2-EOR Task Force Page 21 of 80 Version: Final 08 November 2017 7. Loss of production while modifying will represent an addition to high up-front costs. The shorter

time needed for the modifications the lower will the production loss be. The value of the production loss is also dependent on the required rate of return.

8. Uncertainties around regulations. Although CO2 for offshore EOR is considered a commodity under the London Protocol (see Chapter 6) it is not clear what requirements different jurisdictions will place on monitoring the CO2 in the underground, both during and particularly after closure and if the field transfers into a CO2 storage field.

9. Uncertainties around the revenues, which are the oil price and the cost of CO2 emissions. Low oil prices and high CO2 cost for the operators will prevent offshore CO2-EOR unless new business models and/or changed tax regimes are implemented to de-risk investments.

10. Assumptions on the rate of return (ROR) on the investments or the discount rate used. This varies at least between 7% (Lindeberg et al., 2017) and 20% (Malone et al., 2014). The choice or requirement will have a significant impact on the net present value (NPV) and the profitability of a CO2-EOR project.

A number of studies have been performed on the economics of offshore CO2-EOR, mainly in the North Sea and Gulf of Mexico (Holt et al., 2009; Kemp and Kasim, 2013; Lindeberg et al., 2017; Welkenhuysen et al., 2015, 2017; Pershad et al., 2012, 2014; Vidas et al., 2012; Malone et al., 2014). Different assumptions regarding key parameters, as listed in Table 2.4, make it difficult to systemise and/or compare results from the studies. However, a typical cash flow will show large expenses and no real income the first few years, hereafter many years with net oil revenues and expenses, mainly in terms of OPEX and tax, as illustrated in the artificial example in Figure 2.4 (based on examples in Welkenhuysen at al., 2015; and IEAGHG, 2016). In reality, there will be more factors to include, such as deferred commissioning, and the CO2 may even become an income rather than an expense.

Figure 2.4. Possible cash flow in an offshore CO2-EOR project. All numbers are fictitious but the presentation form is based on examples in Welkenhyusen et al. (2015) and IEAGHG (2016). In reality there will be more factors to include, like deferred commissioning. Malone et al. (2014) made certain assumptions regarding cost input to an economic model. They used a ROR of 20% and CO2 injection was terminated when NPV for a field become negative. This resulted in a significant reduction in viable oil recovery, as illustrated in Figure 2.5 and by comparing Tables 2.1 and 2.5. “Next generation” technology improved the viable recovery by a factor of 18 for the low oil price and 13 in the high oil price scenario.

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Figure 2.5. Gulf of Mexico oil recovery potential with current as well as “next generation” technology

(After Malone et al., 2014) IEAGHG (2016) used a different economic model, different assumptions regarding CAPEX and OPEX than Malone et al. (2014) and a ROR of 12% to estimate the economics of CO2-EOR in the North Sea. One of the key messages from IEAGHG (2016) was that

“Investment in CO2-EOR is highly constrained by the volatility of the price of oil. For EOR projects to remain profitable over their operational life the cost of supplied CO2 supplied needs to fluctuate. One example from this study, based on the North Sea, shows that the cost of CO2 could be ~35 €/tonne if the price of oil reached US$150/bbl but it would need to drop to ~2 €/tonne if the price of oil fell to US$50/bbl.“

Table 2.5. US Gulf of Mexico economic oil recovery and associated CO2 storage potential, current and “next generation” technologies Current technology “Next generation “ technology Total economic viable oil recovery (millions of barrels)

810*/2,820** 14,920*/38,060**

Total CO2 demand/storage capacity (Gt) 0.3*/1.14** 3.9*/10.7** * Oil price $90/barrel; CO2 price $50/t ** Oil price $135/barrel; CO2 price $70/t

Welkenhuysen et al. (2015, 2017) used a techno-economic simulator (PSS IV) to assess the viability of CO2-EOR in the North Sea that included technological, policy-related, economic and geological uncertainties using Monte-Carlo calculations and a discount rate of 10%. For the Claymore field the conclusions were

“In general, CO2-EOR projects, especially when joined with CGS (CO2 geological storage), can be profitable at low oil prices. Oil price is, however, not the only determining factor. With oil prices below 40-50 €/bbl, a fairly high CO2 revenue is necessary to enable EOR. The CO2 revenue has only a minor influence on the EOR phase itself, but when followed by CGS, a sufficiently high CO2 revenue can result in an almost risk-free investment. At a CO2 revenue of 17€/t, a CGS phase after oil production has ceased becomes economically interesting.”

Welkenhuysen et al. (2015, 2017) also found that that geological uncertainty is an important factor for determining the economic threshold level of an EOR project, and a proper assessment of the real uncertainties can make the difference between profit and loss.

CSLF Offshore CO2-EOR Task Force Page 23 of 80 Version: Final 08 November 2017 3 Insights from LULA project – the World’s first Offshore CO2- EOR project

3.1 Background Lula supergiant field was discovered in 2006, in the area known as Santos Basin Pre-Salt Cluster (SBPSC), southeast Brazil. It is located in deep waters (2200 m), approximately 230 km from the coast (Figure 3.1) and occupies about 1523 km2. Reserves are estimated in 5-8 billion barrels. It is developed by a joint venture composed by Petrobras (65%; Operator), BG E&P Brasil/Shell (25%) and Petrogal Brasil (10%).

Figure 3.1- Location of the Lula Filed (red cross) The origin of Lula´s main reservoirs is related to the tectonic process of Gondwana separation, 160 million years ago, giving place to the South American and African continents. The rift phase created the conditions for the deposition of terrestrial and lacustrine sediments on the space between the two continents. As the separation continued, seawater began to fill that gap, creating a low energy and high salinity environment that was favourable to the growth of special bacterial colonia, such as stromatolites. The secretion of these microorganisms, together with the precipitation of carbonate salts, created nucleous to form carbonate rocks, known as aptian microbialites, where the oil in the pre-salt was discovered. Later on, due to a severe climate change on earth, the huge amounts of salt once dissolved in the seawater of this low energy environment precipitated, generating a 2000 m-thick salt layer that became a perfect seal for the hydrocarbon that migrated into the microbialites. The oil has a good quality (28-30 API) and contains a significant amount of associated gas (gas oil ration, GOR, 200-300 m3/m3). The CO2 content in this associated gas is around 11%. The main challenges for Lula field development were mapped in the very beginning:

• Ultradeep waters. • Heterogeneous carbonate reservoirs. • Presence of contaminants in the associated gas, mainly CO2. • Thick salt layer & very deep reservoirs. Besides the drilling difficulties, these characteristics

also imposed additional seismic imaging complexities

This unique combination of technical and logistic challenges created the opportunity for the development of new solutions and technologies. Since the early stages of Lula field development, studies were conducted to evaluate options to achieve a high ultimate economical recovery. EOR issues were addressed from the very beginning of its life cycle. A screening study was performed and several methods were considered. As there were many limitations for offshore EOR in terms of logistics and plants for fluid injections, chemical processes

CSLF Offshore CO2-EOR Task Force Page 24 of 80 Version: Final 08 November 2017 were considered unfeasible. Hence, offshore EOR for Lula would have to take advantage of the only two somehow abundant resources available: seawater and the produced or imported gas. Lula scenario is particularly suited for miscible gas methods. The relatively low reservoir temperatures (60 to 70oC) and the high original reservoir pressure allowed forecasting an efficient miscible displacement process of the oil by enriched CO2 streams or even by hydrocarbon gas (HC). Preliminary numerical simulation results indicated that a substantial incremental recovery could be attained by CO2 or CO2/HC EOR in secondary or tertiary modes. Considering CO2 injection as a potential recovery method for Lula benefits from the aforementioned high GOR and CO2 concentration present as contaminant in the reservoir fluids, as well as from the strategic decision not to vent CO2 to the atmosphere. This last point was perhaps the most important driver, as it somehow dictated the whole field development conception. As the available CO2 volume may not be enough for a full field application, an option is to select a specific region of the reservoir to be developed with CO2-EOR or to re-inject all the produced gas (HC plus CO2), which could be done in the whole reservoir extent. Water-Alternating-Gas (WAG), as a way to control the adverse gas mobility, could be an effective option to maximize oil recovery potential. To comply with the decision of not venting the CO2, a solution based on the purification of the produced gas and reinjection of the CO2-rich stream either in discharge wells or Water-Alternating-Gas (WAG) injectors was adopted. In fact, the facilities were designed with the flexibility to inject an enriched CO2 stream or mixtures of CO2 and hydrocarbon gas. In the case of injecting a CO2-enriched stream, WAG acts more as a reservoir management strategy than as an EOR mechanism, due, as previously mentioned, to the relatively low global amount of CO2 available. Other important drivers for field development were also established: • Phased development, dynamic data acquisition and actions to add robustness/flexibility to the

production system and manage uncertainties. Phased development concept aimed at risk mitigation, optimization of production systems and also expenditure versus revenue balancing, coupling information acquisition with cash flow acceleration.

• Multi-well production pilots. The early operation of pilot projects provided valuable information not just for conventional waterflood recovery, but also for future EOR by WAG injection.

• Comprehensive analysis of the existing uncertainties, such as: reservoir characterization, early water and gas breakthroughs, bypassed oil saturation, flow assurance in deep water flow lines, CaCO3 scale possibility in production wells.

• Definitive systems incorporating the knowledge acquired through the previous phases and prioritizing the standardization of wells and production systems.

• CO2-EOR planned in advance. As offshore projects need to be planned well in advance, due to the lack of room in the platforms and prohibitive costs for future expansions, the pioneer application of EOR methods needs to be considered from the conceptual stage of the development.

Following this strategy, Lula field development was subdivided in three phases, as described below: • Phase 1: Information acquisition.

Drilling of appraisal wells, reservoir coring, well logging, fluid sampling and laboratory tests, high resolution seismic acquisition and interpretation, cased hole well tests, evaluation of different well geometries, test of different stimulation techniques and analysis of flow assurance issues. In this stage, early production development projects were designed and implemented: Two

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Extended Well Tests (EWT) and one pilot test.

• Phase 2: Definitive development, mostly applying conventional solutions (2012-2017). Will comprise the deployment of one additional chartered floating production storage and offloading (FPSO) for production pilot Lula Nordeste (first oil in 2013) and the expansion of Lula pilot to evaluate the performance of waterflood, gas flood, and WAG. The gas can be a hydrocarbon gas, from the producing reservoir, or CO2 originally contained in the associated gas, stripped in the FPSO processing plant.

• Phase 3: Definitive development, implementing non-conventional solutions in large scale. In this phase the intention is to deploy non-conventional solutions, in a larger scale, aiming at cost reduction and production/recovery optimization. The main consequences of this strategy to the field development will be briefly described in the following sections.

3.2 Reservoir Characterization Proper static and dynamic characterization was a primary driver, not just because of the CO2/HC gas reinjection, but also due to the expected reservoir complexity. A comprehensive appraisal program was established in order to build the necessary framework for a complete definition of the development plan. It comprised, among other techniques, well drilling, core extraction, special core analysis, and well logging. Special attention was dedicated to dynamic modelling by means of transient well testing and extended well tests (EWT). In the mid of 2010, Lula field started producing from its first EWT. A production pilot project was initiated in Lula field by the deployment of a production system with a total of 9 wells (6 producers, 1 gas injector, and 2 WAG injectors). The main objective was testing the performance of different recovery methods. Dynamic appraisal proved essential to assess reservoir connectivity, evaluate stimulation methods, support reservoir characterization studies, and define aspects related to flow in subsea lines. New methods of seismic characterization of reservoirs were implemented, including high resolution seismic imaging and 4D seismic to monitor fluid motion and WAG injection. Fluids characterization also received much attention, both in terms of their reservoir (PVT) and flow assurance properties. An extensive program of downhole fluid sampling and laboratory experiments was established aiming at the identification of critical flow assurance aspects, such as wax, gelation, hydrates, asphaltenes and inorganic scaling. Besides evaluating the risks in the lab, some mitigation actions were taken, such as: adequate thermal insulation of risers and pipelines, flexibility in platforms to displace oil in flowlines by diesel during shutdowns, and implementation of downhole chemical injection systems (e.g.: scale & asphaltene inhibitors, H2S scavenger). Interwell gas and water multitracer injections and monitoring were performed. Perfluorocarbons and fluorobenzoates were, respectively, used. Being able to monitor the bottom hole pressure and the use

CSLF Offshore CO2-EOR Task Force Page 26 of 80 Version: Final 08 November 2017 of chemical tracers in the injected fluids may provide important information to match the production history and calibrate simulation models. Regarding specific tests for WAG injection, a broad laboratory characterization programme was launched to determine oil swelling, minimum miscibility pressures (slim tube and rising bubble), multiphase flow in porous medium phenomena particular of WAG floods, geomechanics, and rock-fluid interactions. Reservoir studies comparing waterflood, considered as the reference case, with the application of gas-based EOR, CO2 injection, and WAG were done by numerical simulation and laboratory tests. Equation of state (EOS)-based compositional simulation was adopted in all the cases in order to properly represent the fluids phase behaviour. All surveys were supported by Value of Information studies (VOI), to balance the costs and time demanded by the characterization techniques with the alternative of providing flexibility to the development plan and production facilities. Some benefits of this extensive characterization programme were:

• Identification of vertical communication, permeability barriers and faults. • Determination of saline aquifer actuation. • Determination of the oil compositional variation in the field, allowing adjustments of

production units’ gas processing capacities. • Optimization of well locations, redefinition of perforation intervals, and selective

injection/production strategy based on reservoir characteristics and behaviour. It´s important to stress that well reallocations were only possible due to the flexibility provided to subsea layouts.

• Optimization of FPSOs´ locations due to revised geological and flow models calibrated with dynamic data.

• Conclusion on the absence of significant flow assurance issues due to wax, asphaltene, or severe inorganic scale.

• Guidance to well material selection. • Confirmation of a very good performance of CO2 separation process in the FPSO, using

membrane technology. • Confirmation of good water injectivity indexes.

3.3 Robust & Flexible Development Strategy Even if adopting an aggressive strategy for data collection, it is normal that a high degree of uncertainty about the dynamic behaviour persists, not only by the huge dimension of the field, but also because of the complexity of the rock-fluid system. In addition, many properties regarding sweep efficiency, communication between regions and performance of dynamic mechanisms will be only disclosed during the full-field operation, when corrective procedures are more difficult to be implemented. So, it is a wise decision to build a recovery strategy that will be profitable in different scenarios (robustness), even not being the best one for the most likely situation, and provide the project the necessary contingencies and resources to adapt the initial strategy if the operation reveals a behaviour different from the most likely case (flexibility). Much of the reasoning behind this strategy is also associated to implementing EOR by WAG in the field. The complexity of implementing an offshore EOR project increases significantly as we move to ultradeep waters. As the investments are normally huge, more appraisal and data acquisition would be

CSLF Offshore CO2-EOR Task Force Page 27 of 80 Version: Final 08 November 2017 needed to reduce uncertainties and mitigate associated risks before sanctioning the project. However, due to high costs, information needs are usually balanced with the acceptance of a higher degree of risk or with an increased project flexibility. This context makes it extremely challenging to consider EOR application in this kind of venture. Usually, EOR methods require additional installation capabilities that can be prohibitive in an offshore facility, if they´re not planned very well in advance. Besides, in early stages of development, every reservoir properties description presents several uncertainties. This is particularly true for the petrophysical properties distribution, even more critical in carbonate reservoirs, which usually present higher degree of heterogeneity than sandstones. Some examples of how this robustness/flexibility strategy can be implemented are: • Conversion of producers to injectors in case of compartimentalization • Connection of additional wells • Choice of injected fluid (gas, water or WAG) • Adoption of selective injection by intelligent completion

3.4 Materials A consequence of CO2 presence in the produced fluids was the necessity of a careful definition of the materials to be used in wells, flowlines, risers and in the processing plant itself. High pressures coupled to variable CO2 contents make the use of carbon steel in wells, risers, and topside pipings nearly impossible. This issue is being tackled through use of Corrosion Resistant Alloys (CRA) and plastic-covered pipes. The combination of carbon steel and corrosion inhibitors in this case is not recommended, since it would be necessary to have products with extremely high efficiency and availability. In response, an extensive laboratory study was launched in Petrobras R&D Center aiming to test different materials (metallic and elastomeric) able to withstand the high pressures and aggressive environment. A qualification program for flexible risers and subsea flow lines was also performed, in cooperation with the industry.

3.5 Intelligent Completion To improve the reservoir management, intelligent completion was deployed whenever considered beneficial. Several factors may affect the decision to adopt or not adopt intelligent completion for each well, therefore, it is not always recommended to use this configuration. One of the aspects to consider is geological: to be effective, it is desirable to have vertical isolation between zones in the reservoir. This type of completion can be an effective alternative to mitigate the risk of preferential flow and early breakthrough of injected fluids in the reservoir. The successful use of this feature, together with the flexibility to be able to inject either water or gas, in the injection wells, plus the capability to alternate the gas injection through different wells, will be providential to confirm the additional oil recovery expected by EOR implementation in the field. Intelligent completion valves have been used for several purposes, including controlling gas production, performing well tests, splitting commingled injection or production and proactively managing water/gas breakthroughs.

CSLF Offshore CO2-EOR Task Force Page 28 of 80 Version: Final 08 November 2017 First intelligent dual zones completion installations have been successful in pre-salt area, with no compromise to the project timeline or to the system performance. Considerable amount of improvements have been made on system design and installations procedures.

3.6 Production Units/Topside Facilities Floating Production Storage and Offloading (FPSO) units were chosen as the best alternative to develop Lula field, mainly due to crude oil storage capability, not requiring the construction of long length oil pipelines, and also because of other characteristics that allow a short-term completion with economic advantages in an ultradeep offshore environment. The topside processing plant design had to deal with uncertainties in the reservoir fluid compositions and production profiles in order to guarantee an adequate production capacity and also the proper performance within the established design cases. The units will be able to inject either desulphated seawater or the produced gas. Simulation studies highlighted the importance of large capacity gas processing plants, considering that gas capacity could limit oil processing. The technology chosen for CO2 separation was permeation through membranes, once it was the only process identified that could be able to handle a wide range of CO2 concentrations throughout the production life. As membranes are sensitive to heavy hydrocarbon condensates and aromatics, the FPSOs were also designed with a dew point control unit to remove heavy hydrocarbons upstream the membranes. At the time of the conceptual design, there were uncertainties related to the miscibility of the gas to be injected into the reservoir and its thermodynamic behaviour. In order to allow the evaluation of gas injection with both high and low levels of CO2, the first topside facilities were designed with a CO2 membrane system that provided two streams: a treated gas with low CO2 content (5% v/v) and a stream with very high CO2 content (up to 90% v/v).

3.7 Lula WAG pilot Launching an EOR miscible process in a deep offshore carbonate reservoir was a major challenge. Some specificities of carbonate environment should be considered and some risks mitigated. To accomplish this task, a first pilot has been launched in 2011 (so-called Lula-pilot) and a second one in 2013 (Lula-NE). One of the main objectives of Lula Pilot in terms of CO2-EOR was the evaluation of some operational issues, such as: • Early breakthrough in production wells • Reduced injectivity (mainly water injectivity loss after gas cycles) • Corrosion due to carbonic acid • Scale deposition • Asphaltene precipitation • Wax deposition • Hydrate formation upon WAG cycling Additional information expected were:

• WAG performance

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• Performance and benefits of horizontal drilling • Improved understanding of Lula reservoir connectivity due to additional wells and more

pressure tests • Extended evaluation of gas processing plant and CO2 removal system

Lula pilot was designed to allow WAG injection either by injecting produced gas (WAG-HC) or CO2 (WAG-CO2) or a mix of HC gas and CO2. A total of nine wells were drilled, being six producers, one gas injector, and two WAG injectors. The injection started in April 2011 (FPSO Cidade de Angra dos Reis), injecting around 1 million m^3/d. The gas was mainly HC with some CO2 content. From September 2011 on, the gas exportation system was started and since then part of the produced gas was separated from the CO2 and exported to shore. The injection well started to inject mainly CO2, with concentrations higher than 80% and injection rates around 350 km^3/d. It was the first time a CO2 rich stream was injected in an ultradeep water well, equipped with subsea completion, to improve oil recovery. Since all wells have downhole pressure gauges, the pressure is being monitored. Tracer (PFCs) monitoring on gas injection has been conducted since June 2011. No major operational or reservoir problems have been detected so far. No gas or water injectivity losses upon cycling have been observed. No flow assurance issues, like hydrates, asphaltene or wax precipitation or severe inorganic scaling were seen. Injected perfluorocarbon gas tracers were easily injected and detected and are actively contributing to revise the geomodel. Lula-NE pilot was conceived to test some new concepts for the production development in the Pre-Salt area. In terms of subsea gathering system, an innovative concept was deployed, combining flexible flowlines lying on sea floor, with rigid steel catenary risers (SCR) supported by a buoy positioned 250 m below sea level. The drainage plan considered eight oil producers, some of them with intelligent completion, one gas/CO2 injection well, and five WAG injectors (two subsea WAG manifolds were also installed). A balanced approach between data acquisition and facilities flexibility made it possible to face the many reservoir and production uncertainties. The chartered FPSO Cidade de Paraty started production in June 2013, with an oil capacity of 120,000 bpd, and a gas plant able to process up to 5 million m3/d of gas with 35% content of CO2. Despite all the challenges, the project was delivered on time, with production plateau attained in September 2014. Lula pilots´ results are being essential to calibrate the simulation studies and select the best strategy to maximize the oil recovery and project´s profitability. These outcomes will provide the basis for adopting the optimal strategy for field development in definitive systems. All the detailed planning and step-by-step achievements are paving the way for a consistent deep water EOR application.

4. Approaches for enabling offshore CO2-EOR Several studies have demonstrated that developing CO2-EOR on a large offshore oilfield in the late-life development stage has many significant hurdles (ref section 2.2), which can be summarized in terms of:

a. The large investment costs associated with conversion and adaption of offshore platform facilities;

b. The lack of infrastructure to supply and handle sufficient volumes of CO2 to achieve a viable CO2-EOR project;

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c. Competition with other more attractive oilfield development options, such as gas injection.

In order to stimulate incremental growth of new offshore CO2-EOR projects, various options have been proposed, including:

• Using smart operational solutions for reducing project CAPEX and OPEX • Using late-life oilfield infrastructure • Using isolated oilfield satellite projects for dedicated CO2-EOR projects • Focusing on CO2-EOR for Residual oil zone reservoirs • Improved modelling tools

These options are briefly reviewed below.

4.1 Smart solutions for offshore CO2-EOR operations: It may be possible to reduce these investment costs for new CO2-EOR projects by developing “smart solutions” for offshore CO2-EOR, such as by minimizing the need for conversion of surface facilities and optimizing the gas/CO2 recycling system (Goodyear et al. 2011). For example, in the case of a CO2 WAG development scheme the CO2/water ratio can be adjusted to match the gas processing limitations. Martinez (1999) and Goodyear et al. (2011) also propose using CO2 as an artificial lift gas in oil production wells in order to exploit the availability of CO2 for field operations and at the same time reduce the overall project CAPEX.

4.2 Using late-life oilfield infrastructure In certain cases, relatively minor modifications could be made to late-life, generally smaller, offshore field developments where some CO2 handling capabilities are already in place. The K12-B gas field in the Dutch sector of the North Sea illustrates this potential. For most of the field life (since 1987) the field has been producing natural gas with a relatively high CO2 content. Because CO2 handling facilities were already in place, it was relatively cost-effective to turn the project into a CO2 injection project as part of an R&D pilot project (Kreft et al. 2006). Although this project is not an EOR project it has been used to test storage and enhanced gas recovery concepts, and illustrated the potential for further use of offshore sour-gas field infrastructure for CO2-EOR.

4.3 Using isolated oilfield satellite projects for dedicated CO2-EOR projects There is considerable experience now with sub-sea satellite field developments tied back to a main offshore oilfield project. One example from the Norwegian offshore sector is the Norne field, (Steffensen & Karstad, 1996) where satellite fields have been developed using subsea tie-backs to the main field developed using a FPSO (Figure 4.1). Using this concept the field development group has been able to apply effective and advanced reservoir management methods (Osdal & Alsos, 2010) to optimize both the main field and the satellite field developments. This example illustrates the potential for using an enhanced recovery technique such as CO2 EOR on an isolated satellite field without incurring the larger conversion costs associated with a full field project, and offers a basis for identifying future opportunities for offshore CO2 EOR pilot projects.

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Figure 4.1. Illustration of the subsea satellite fields Alve, Stær and Svale developed by tie-back to the main Norne field (photo courtesy of Statoil ASA)

4.4 Focusing on CO2-EOR for Residual oil zone reservoirs offshore Residual oil zones located below oil/water contacts of many oil reservoirs have been identified as a significant new resource that could be realized using CO2-EOR (e.g., Melzer et al. 2006; Harouaka et al. 2013) especially in the onshore Permian Basin of the mid-USA. A similar potential is found offshore (e.g., Stewart et al. 2014) and although even more challenging than the corresponding onshore resources, offshore ROZ reservoirs could be attractive as a combined CO2 storage resource with an associated oil recovery benefit. Studies on CO2-EOR potential in Residual oil zone reservoirs offshore are currently in the early screening stages.

4.5 CO2-EOR Reservoir Modelling, Simulation and Optimization Issues Reservoir mathematical modelling and simulation is a broadly used tool in the oil industry. Examples of common decisions nowadays taken by oil companies with the help of numerical simulation are, among others: • Decision of type, number, and location of producer and injection wells. • Prediction of production curves (volumes of produced oil, gas, water, CO2, versus time). • Demand for water/gas/CO2 for injection. • Number of production units (platforms). • Size of topside treating facilities (e.g.: water/gas/oil treatment, water/gas overboarding,

compression/pumping, reinjection, etc.). The conscious choice to use mathematical simulations to make these prominent decisions is due to the fact that it is impractical to test all those variables at field scale in a timely and effective manner, particularly for the offshore development. Conventionally, a long chain of scientific disciplines and professionals were, and are, involved to perform this task with the best techniques available. As

CSLF Offshore CO2-EOR Task Force Page 32 of 80 Version: Final 08 November 2017 mentioned elsewhere in this report, economics and overall uncertainties involving offshore CO2 EOR is very important, directly impacting the feasibility of most of the projects. In this context, properly modelling and simulating the process at field scale, from the reservoir-rock point of view, becomes an issue that still needs to be overcome. This happens because CO2-EOR is more complex than conventional recovery techniques. In other words, a greater diversity of physical phenomena needs to be characterized and represented in mathematical models/simulators in order to adequately describe and predict the behaviour of the process. Some examples of particular issues related to CO2-EOR are: • Phase behaviour. All thermodynamics and mass transfer phenomena involved in gas/CO2 injection

in oilfields impact the overall efficiency of the process. Equations of State and compositional fluid models are usually necessary to represent, for example, the amount of each phase and of CO2 in different phases in each part of the field. Phase property variations particularly with temperature variations is more important to model in CO2 injection compared to conventional hydrocarbon gas injection.

• Reaction with reservoir rock. CO2 in the presence of water generates carbonic acid, that is known to react with carbonate cements or carbonate rocks, dissolving it at different grades, possibly impacting the flow (e.g.: fracture and channel generation/plugging, permeability/porosity change) and the production (e.g.: scaling).

• Multiphase-flow in porous media phenomena. Especially when sophisticated injection modes are used, like Water-Alternating-Gas (WAG), multiphase flow in porous media phenomena may arise that can significantly impact how water, gas, and oil flow in the reservoir rock and are produced. Examples are three-phase relative permeability and relative permeability/capillary pressure hysteresis.

• Oil Instability. Solvents like CO2 may, in certain circumstances, destabilize some oil components, like asphaltenes. It can also impact the flow properties of the reservoir rock.

The central problem is that this complexity is not easily incorporated in commercial or even proprietary simulators. Moreover, upon implementation of these models, simulation time increases considerably, especially in big fields like those usually developed in offshore environment. Demanding and time-consuming simulation runs would require simplifications of the models, so that reservoir studies and optimizations can be accomplished within the timeframe of commercial development. But this action can have tremendous impacts on the overall development plan and economic forecasts, including CO2 demand, storage, treatment, and reinjection. So in order to guarantee better and more predictive offshore CO2-EOR projects it is highly recommended that the involved actors invest in proper characterization, modelling and simulation R&D, as well as in adequate computational hardware and new generation software that can accomplish the task of better representing the relevant phenomenological aspects of the process in increasingly bigger and more complex fields.

4.6 Application of numerical reservoir simulation in CO2-EOR In conventional hydrocarbon production, the decision on injection type, injection location, rate of injection, and injection duration is mainly reached using numerical reservoir simulation. Results obtained from such simulation studies make the basis for development of the injection strategy. While at least for mature fields existing experience can largely be used to decide on producers.

CSLF Offshore CO2-EOR Task Force Page 33 of 80 Version: Final 08 November 2017 Decision on injection strategy in CO2 EOR projects follows the same principle. Reservoir simulation results are needed to rank various scenarios based on recovery and cost estimates associated to each development plan. Behaviour of injected phase in the reservoir in terms of local, vertical and areal sweep efficiencies and residual oil saturation behind the injection front dictate the ultimate recovery. In offshore development, due to much lower well density compared to land operations, application of mobility control techniques is needed to increase the sweep efficiency. Consequently, the injection of pure CO2 as the sole injection strategy is highly unlikely. CO2 Water-Alternating-Gas (CO2 WAG), CO2 Simultaneous-Water-And-Gas (CO2 SWAG) or CO2 foam injection techniques should be studied to increase the recovery. This is especially important regarding the high cost associated with offshore CO2-EOR. The following table shows the result of a simulation study on a generic North Sea reservoir. Various injection strategies are studied for this reservoir for a development plan based on single injector and a single producer (Karimaie et al., 2016). An interesting observation in this study is the effectiveness of common water flooding outcompeting CO2 injection. The reason is poor sweep efficiency of injected CO2 due to segregation in the reservoir. The recovery is maximized by increasing sweep efficiency either through the use of sophisticated well design or application of CO2 mobility control techniques. Table 4.1. Comparison of oil recovery factor using various injection techniques in an off-shore reservoir.

Case EOR volume, ∆∆MSm3

∆ RF, %

Water injection 0.00 0.00 Continuous CO2 injection, horizontal well 1.30 8.44 Continuous CO2 injection, vertical well -0.32 -0.5 Water-flooding followed by CO2 injection 0.36 3.23 Water-flooding followed by WAG injection 0.22 2.66 Water above gas SWAG injection 1.01 6.86 SWAG co-injection 0.66 4.91

5. EMERGING TECHNICAL SOLUTIONS FOR OFFSHORE CO2-EOR AND STORAGE

5.1 Introduction There are no fundamental differences in onshore and offshore CO2-EOR. Reservoir and well conditions are different, but theoretically there will be the same requirements to treatment and separation onshore and offshore. There are, however, special challenges related to offshore treatment of well streams from an EOR flood. Existing offshore facilities generally have very limited space and weight reserves and the materials utilized in existing processing systems are generally not suitable for streams with a high CO2 content. Production delays due to installation of facilities will have considerable negative impact on the economy of CO2 injection project. Several studies have concluded that to avoid retrofitting major parts of an existing processing train the best solution is to remove most of the CO2 before the production fluid enters the processing system for further treatment. Studies are underway to address this issue by designing and manufacturing compact CO2 separation systems that can be installed on seabed or on production platforms that would handle processing of the produced CO2. A robust design is needed for such separation facilities, especially if

CSLF Offshore CO2-EOR Task Force Page 34 of 80 Version: Final 08 November 2017 they are designed for installation on the seabed. The exact requirement for CO2 content would be facility dependent. Variations in material quality of existing equipment, amount of gas and CO2 content from fields not using CO2-EOR, etc. will influence the requirements. A wide range of fluid compositions are expected during the lifetime of a CO2-EOR project from pure hydrocarbons to increasingly higher CO2 concentrations. Production wellhead conditions are variable making design of a robust compression system challenging. In this chapter some options are presented: • Adding a CO2 processing module to separate CO2 for reinjection. • Using CO2 rich gas together with oxy-fuel technology to generate power and to re-inject the flue

gas, which is mainly CO2 and water. • Improved mobility control using CO2 foam. The development of compact equipment that can be used in a CO2 processing module may enable the use of CO2-EOR. Use of compact equipment may make it feasible to install on facilities with limited space and weight reserves. For some fields a CO2 processing module can be placed on an external structure. Alternative external structures include jacket, jack-up rig, FPSO, or subsea modules. A new CO2 processing module could also contain equipment for treating and boosting produced water for reinjection. This would free up capacity in the existing produced water treatment system which is usually a bottleneck on mature installations. As an alternative to CO2 separation, developments are ongoing to enable use of the CO2 rich natural gas directly as fuel in power turbines. The technology is further described in chapter 5.4.2. There is limited public literature available that have studied the impact of bringing CO2-EOR offshore. However, some studies have analyzed the impact both on the well separation train, gas injection system, safety issues, material concerns and other related topics arising from handling well streams from a CO2-flooded reservoir. Not all of these aspects are referred to here, but the most important topics have been considered. A CO2-EOR phase will typically have a duration limited to a few years. After the blow down phase, reservoirs may be used for permanent storage. Reuse of CO2 processing equipment should be considered, either at another field or for injection of CO2 for permanent storage.

5.2 Topside solutions 5.2.1 Goodyear study Goodyear et al. (2011) refer to the modified well streams that typically will be caused by the CO2 flooding, characterized by e.g.: high water cuts and high CO2 concentrations, up to 90 vol %, in the gas phase. Especially the gas treatment facility, which includes gas dehydration (TEG contactors) and NGL recovery, can be very challenging. The weight of the complete treatment modules has been estimated to be between 6,000 and 16,000 tons. This drives the need for very efficient and compact solutions for the gas treatment equipment. Goodyear et al. (2011) explain that the need for gas dehydration is driven by constraints in the downstream pipeline material. Further, there are various options for treating the recycled gas with respect to the degree of removal of hydrocarbons. Consequently, the recycled gas will alter the composition compared to the pure CO2 used from external sources. This change in composition may have an impact on the performance of the EOR flooding efficiency since various impurities may affect the minimum miscible pressure (MMP). Goodyear et al. (2011) also mention that offshore CO2 concept selections have concluded that recovery of methane with current technology is not an attractive option. This is due to the high

CSLF Offshore CO2-EOR Task Force Page 35 of 80 Version: Final 08 November 2017 demand for extractive distillation and corresponding high CAPEX. New technology concepts based on cryogenic principles and membrane separation are said to provide solutions for more favorable offshore CO2-EOR projects. 5.2.2 Salim study Salim et al. (2012) have studied a variety of implications of bringing CO2-EOR offshore and using existing topsides facilities for this kind of operation. The areas affected are illustrated in Figure 5.1 below.

Figure 5.1. Areas that are affected on topsides facilities by introducing offshore CO2-EOR. Based on

an illustration by Salim et al. (2012) The concept used in Salim et al. (2012) is based on a typical topsides facility in the North Sea. The study concluded that there is a need to install a completely new CO2-EOR module with a bridged link to the host platform. This arrangement was chosen due to the impact of the corrosive nature of CO2 to the existing facilities. The new EOR module would then communicate with the host platform by pumping the liquids in pipes between the units. The flow diagram of the EOR module is shown in Figure 5.2 below.

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Figure 5.2. Schematic diagram of processing facilities on a new topsides EOR module. Based on an illustration by Salim et al. (2012).

As shown in the flow diagram, no recovery of NGL’s or hydrocarbon gas is taken into account in this arrangement. However, a strong attention is made to the conditions for preparing drying of the CO2

rich gas stream and analysis of contactor conditions for this operation is made. Water content in the dried gas is specified to about 105 ppmv and is regarded to be low enough for “dry” operation of downstream HP compressor and pump. Limited details of process conditions in the intermediate stages are given, but it is said that the final HP compressor lifts the pressure from about 40 bars to 145 whilst the CO2 injection pump increases the pressure further to 240 bars. The external CO2 supply is assumed to be introduced from a ship via a buoy and delivered at the EOR module at 10 bars and 4°C. 5.2.3 Energy Institute assessment EI (Energy Institute; 2013) has also made an assessment of the implications of treating a well stream from a CO2 flooded oil reservoir, emphasizing the complexity and costs for retrofitting existing facilities. Hence, they are proposing various options for the treatment. The options include a complete treatment process including recovery of hydrocarbon gases (option 1) and a simpler version, involving only liquids separation and reinjection of the complete gas phase (option 2). The options are illustrated in the same Figure 5.3 below.

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Figure 5.3. A proposed schematic of two various options for topsides treatment of well stream from

a CO2 flood from EI (2013), reprinted with permission from the Energy Institutes. The well stream composition is not mentioned, but is assumed to be comparable to well stream data as given in the sections above. From the flow diagram, it can be seen that a new HP separator (component 0) is introduced to the general arrangement in addition to LP CO2/water separator (component 4). The blue dashed line indicates the battery limit for new components for option 1, which comprises a solution for recovery of hydrocarbon gases. Accordingly, option 1 does not include stream B (routing of outlet from H2S scavenger to HP compressor and HP compressor (component 11). The need for a mole sieve (component 7) upstream the membrane is not explained. The recovered HC gas is exported with CO2 content in the range 15 volume-%. The permeate gas, or CO2 rich stream leaves the membrane separation at low pressure and with a HC gas content in the range 2 – 3%. It is likely that two separation stages are needed to reach this quality, but this is not mentioned. A compressor with high compression ratio is needed to increase the pressure for this stream to 125 bars as indicated. It is stated that the membrane separator could be replaced by an amine system. Option 2, marked by the green dashed line, involves recycling of all the HC gas components including the CO2. 5.2.4 Studies on the Norwegian Continental Shelf (NCS) Aker Solutions have previously done several studies related to CO2-EOR concepts in the North Sea. Some of these studies are classified as confidential and cannot be referred to in great detail in this report, but some general aspects can be mentioned. Two main studies referred to are (masked names and details):

CSLF Offshore CO2-EOR Task Force Page 38 of 80 Version: Final 08 November 2017 • NCSA • NCSB The concepts of these studies vary quite much. The NCSA project is based on capturing CO2 from an onshore power plant and to pump the gas in a pipeline to the offshore facilities. The gas would be further pumped into the various injectors from the offshore satellites. The main modifications to the facilities were limited to injection arrangements for the gas pumps and injection manifolds. The removal of CO2 is planned to take place at an onshore power plant, so no treatment facilities have been included in this scope. The CO2 being degassed from the various separation stages poses a significant increase in gas load on the equipment. The equipment is said to have sufficient capacity to handle the increased gas rates, but will require replacement of steel/cladding to withstand the corrosive nature of the gas. A major issue will be the handling and use of the CO2 rich gas from degassing steps. Calculations show that the CO2 content eventually would become higher than the flammable level and hence cold flaring is needed. The handling of the CO2 rich gas streams in topsides facilities for such CO2-EOR projects are mentioned in other papers as well as a critical issue that must be studied in more detail. The NCSB was based on a concept to capture CO2 on an onshore power plant and to use the gas for flooding the reservoirs in question. Various cases were specified for treating the gas at two offshore facilities. The most comprehensive scenario was based on a gas treatment system that would leave the export gas with a CO2 content of 10 mole-%. The interfaces with existing logistics and new building blocks are shown in Figure 5.4 and the modifications needed for this concept are illustrated in Figure 5.5.

Figure 5.4. Interfaces between existing infrastructure and new building blocks (Courtesy Aker Solutions).

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Figure 5.5. Flow diagram showing modifications to and new equipment for the case C4. (Courtesy Aker Solutions)

Figure 5.5 shows the need for new equipment (marked in red) to meet the design basis of the export gas quality to allow max 10 mole-% CO2. The discharge pressure of the enriched CO2 gas shall be 200 barg at the topsides. No specification to CO2 purity in the CO2 enriched gas is provided. It is mentioned that a gas cooling and pumping system can replace the last stage compressor (K-4) to obtain the advantage of transforming the 65 bar CO2 (at the outlet of K-3) to dense phase and gain the corresponding liquid head in the injection system. Some major topics to the selected process arrangement are: • CO2 flashing from dissolved gas in water. • Impact on flare system by gas with high CO2 concentrations. • Type of CO2 removal process (Module X-1). For the gas treatment options, both amine-based and membrane separation systems were evaluated. For amine processes, the system based on a physical solvent (MORPHYSORB) was preferred over a conventional activated amine system. Further, the physical amine system was chosen as the base case CO2 removal system over the membrane system. This was despite the considerable size and weight difference favouring the membrane system. The reason for the process selection was due to the considerable more detailed in-house knowledge about the amine system compared to the membrane; however, the membrane system is referred to as a promising alternative separation method.

CSLF Offshore CO2-EOR Task Force Page 40 of 80 Version: Final 08 November 2017 5.3 Subsea solutions Subsurface studies need to be carried out to determine the range of the design parameters for a separation system. Depending on the injection strategy, such as pure CO2 injection, CO2 Water-Alternating-Gas (CO2 WAG), or CO2 Simultaneous-Water-And-Gas (CO2 SWAG), different incremental oil volumes are produced and production well effluents can vary considerably (Karimaie et al., 2016). A subsea well treatment system could provide an attractive basis for economically feasible offshore CO2-EOR gas separation system. Such concepts would represent a feasible solution for increased offshore oil production in combination with CO2 sequestration as considerable CO2 volumes are required in a typical offshore CO2-EOR project. The critical system elements are:

• Reservoir management of injection strategy seems to have first order effect on economy of the whole concept.

• Robust compressor design to handle wide range of design parameters with minimum maintenance.

• Retrievable system components for inspection and maintenance. • Production-well design modifications to handle flow assurance problems associated with CO2

injection with minimum maintenance. • Possibility to redirect production from the wells that experience unexpected CO2

breakthrough. 5.3.1 Subsea CO2 processing In the literature, subsea technology for offshore CO2-EOR deployment has rarely been described. A recent study by Eggen and Nøkleby (2015) indicates that a concept for subsea processing of the well stream resulting from a CO2 flooded oil reservoir could represent an attractive alternative compared to the topsides processing concept. A subsea separation system would be designed to ensure that the oil and gas received at the existing processing facilities contains a limited amount of CO2, reducing or removing the need for retrofitting for a corrosive environment. A subsea concept would also reduce the need for space and weight topsides, although space for some utilities will be needed (supply of power, MEG/methanol, etc.) unless they are supplied from shore or another facility. Subsea systems are modularized to enable easier installation and retrieval operations. Size and weight of modules is a key parameter depending on the available vessels planned to be used for installation and retrieval operations. Compact equipment is preferred to minimize module size and weight in order to open up for more flexibility with regard to vessel selection. Several subsea processing projects have been installed and are in operation for various applications. No systems have yet been installed for subsea CO2 handling. A processing concept for CO2-EOR will depend on the specific requirements for each field and facility. The main functions for a proposed CO2-EOR processing concept are illustrated in Figure 5.6. Liquid and gas is separated, the liquid is taken into an oil/water separator and the water is re-injected to the reservoir. To achieve the required water quality for reinjection the oil stream will still contain a considerable amount of water, but the removal of water will free significant capacity in the produced water treatment system on the existing facility. Facilities operating in late life often have bottlenecks in the produced water treatment system. Additional steps can be introduced if needed, e.g., further degassing of the oil/water stream at lower pressure to remove more CO2.

CSLF Offshore CO2-EOR Task Force Page 41 of 80 Version: Final 08 November 2017 The gas is directed to a separator, separating the CO2 from HC gas before the CO2 is compressed and re-injected. Depending on the gas compression requirements more than one stage may be needed. In such cases interstage cooling and demisting may be required. Cooling at the compressor discharge may be used to get the CO2 into dense phase. The HC gas with the remaining CO2 is sent to the processing facility.

Figure 5.6. Main functions of a typical processing concept for CO2-EOR. (Courtesy Aker Solutions)

There is high number of potential configurations for CO2-EOR processing. Alternative concepts include compressing the mixed CO2 and HC gas before separation. Additional processing steps may be added to improve the separation, but a subsea solution should be designed to be robust and reliable. There have been several subsea processing projects installed in the last decade. Although technology qualification will be required for a subsea CO2 processing system, several elements can be considered partially or fully qualified. Material selection for equipment will need to be reviewed for CO2 processing applications. The core technology for gas separation of CO2 and HC gas must be qualified for subsea use. Membranes as described in the next chapter may be a well suited technology for subsea applications. Available subsea processing building blocks: • Gas/liquid separators: Several gas/liquid separators have been installed subsea including

scrubbers. For a CO2 processing concept, new and available compact options should be evaluated. These options include a compact cyclonic gas liquid separator like the GLCC or similar. The GLCC is the result of a JIP led by the University of Tulsa. Some qualification will be needed, but there is a lot of test data available through the JIP.

• Liquid/liquid separators and de-oiling equipment: De-oiling hydro cyclones have been qualified for subsea use. Cyclonic bulk de-oilers would likely require no or limited qualification.

• Coolers: Passive subsea coolers are qualified and installed as part of Statoil’s Åsgard subsea compression project (no temperature control). Active coolers with temperature control will need further qualification to verify the relevant heat transfer coefficient to apply to the design in active mode.

Gas/liquid separator

Oil/water separator

Water for reinjection

Oil/water to processing

facility

HC gas with remaining CO2

CO2/HC gas separator

CO2 for reinjectionCooler

Well stream

CSLF Offshore CO2-EOR Task Force Page 42 of 80 Version: Final 08 November 2017 • Compressor: A subsea compressor system for HC gas is qualified, installed, and in operation as

part of the Åsgard subsea compression project. A tandem compressor for HC gas is under development as part of the same project. The tandem compressor is two compressors connected to one motor, enabling a higher compression ratio if run in a serial configuration. Further qualification verifications will be needed in order for the tandem compressor to be fit for CO2 application.

• Pumps: Multiphase and single phase pumps are qualified technology for subsea use. However, the needed duty and impeller/diffuser selection are limited and would need to be evaluated from case to case.

• Subsea de-sanding equipment: Cyclonic de-sanders are considered qualified technology for subsea use.

• Control system: The control system in general is available for subsea use. However, a technology assessment for the exact configuration and instrument selection should be performed.

• Power system: Several power system solutions have been qualified for subsea use and are available.

5.4 Novel technology enabling CO2-EOR From the descriptions in the sections above, it is seen as mandatory that considerably more compact separation methods are qualified for more favourable concepts for offshore CO2-EOR. This will provide substantially less impact on existing offshore facilities and enable subsea solutions. 5.4.1 CO2 separation In this chapter known and emerging technologies for separating CO2 from other gas is described.

CO2 separation with sorbents Absorption denotes a process where a molecule or atom is dissolved in or permeates the bulk phase of a gas, liquid, or solid material. Adsorption, on the other hand, is the adhesion of molecules to a surface. This can be either a physical or chemical process. For CO2 separation sorbents can be in liquid or solid states. The sorbent can be regenerated and reused, typically by changing the temperature or pressure. The most widely used process for CO2 separation and capture from acid gas containing streams is the chemical absorption process utilizing liquid amine solutions. Aqueous solution of monoethanolamide (MEA) or diethanolamine (DEA) is commonly used in the wet chemical absorption and low-pressure stripping of CO2. In this process, the CO2 reacts with the liquid amine solution to form a carbamate species. Upon heating, the carbamate species decomposes to release the absorbed CO2 and regenerate the amine solution. The amine process is in use offshore at Sleipner. This process is not currently considered adaptable for application in a subsea environment due to complexity. A novel amine adduct (Ayasse et al., 2016) has been synthesized providing a thin layer of cross-linked imine/polyol inside the pores of highly-porous silica particles. A packed bed of adduct is very active for absorbing acid gases, such as CO2 and H2S, from gas streams. The saturated bed can be stripped of acid gases at 90-130ºC and at a pressure substantially above the absorption pressure using only a dry gas. For natural gas above 1070 psi (~74 bar), the CO2 is recovered directly as a liquid, eliminating CO2 compression costs for CO2 disposal and providing an economical alternative technology for commercializing high-pressure gas containing elevated levels of CO2. For adsorption processes the surface area is a key parameter. Typical materials are activated carbon, zeolites, silica and more recently material-organic frameworks (MOF). CO2 adsorption and selectivity can be improved by chemical modification on the surface of solids material possessing high surface area as described in Yu et al. (2012).

CSLF Offshore CO2-EOR Task Force Page 43 of 80 Version: Final 08 November 2017 Supersonic CO2 separation Supersonic expansion can be a viable strategy for capturing CO2 from a well fluid gas phase with high pressure. The core technology is a Laval nozzle equipped with liquid separation in the throat of the nozzle. When temperature and pressure is reduced as fluid velocity is increased liquid will condense if operated within the fluid phase envelope. The Laval nozzle is used to accelerate a pressurised gas passing through it to a supersonic speed. The thermal energy is converted into kinetic energy of the flow, and the flow goes through a sonic point at the critical point where the nozzle cross section narrows to its minimum. At that point, the flow speed reaches the sound velocity. The cross section increases again after the critical point, and the gas is further accelerated to supersonic speeds. The principal is shown in Figure 5.7.

Figure 5.7. Supersonic nozzle with liquid separation. (From Netušil and Ditl, 2012, reproduced under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited)

The expansion of natural gas makes it possible to cool the gas down to temperatures sufficient for condensation. Liquid separation is achieved by centrifugal force field is created by flow swirling in the chamber of the supersonic nozzle. A typical process concept (Imaev et al., 2014) utilizing the 3S separator is shown in Figure 5.8. Necessary pre-treatment to get dry gas is not shown in the figure. Dry inlet gas, containing large amounts of CO2, is cooled in a heat-exchanger, and after the preliminary expansion, it is fed to a rectification column. In the rectification column, a fractionating of inlet mixture occurs. Condensate, generally containing liquid CO2, is sampled in the bottom of the column; condensate, containing ethane, methane, and CO2, is sampled at the top of the column. Gas from the column is delivered to the inlet of the 3S-separator, to be cooled in the supersonic nozzle, and the carbon dioxide remaining in gas, is condensed. Two-phase flow is directed from 3S separator to the conventional gas-liquid separator. Separated liquid, containing CO2, is pumped to the column as a reflux liquid. HC gas from the separator is mixed with processed HC gas from a 3S-separator, cooled in the heat-exchangers block, and finally fed to consumers. Condensate from the bottom of the column is throttled, heated in heat-exchangers block, and directed to the compressor for injection.

CSLF Offshore CO2-EOR Task Force Page 44 of 80 Version: Final 08 November 2017

Figure 5.8. Basic system for supersonic CO2 separation. (From Imaev et al., 2014)

CO2 separation with membrane Membrane is an alternative to the use of sorbents for CO2 removal and has been in commercial use for decades. Traditional membranes are made from cellulose acetate, polyimides, or perfluoropolymers (Scholes et al. 2012). Operationally, membranes are simpler than an absorption system with regeneration facility, but this is partly offset by the requirements for pre-treatment that traditional membrane systems have. A pre-treatment system will typically contain coalescing filter, particle filter, and heater, but may also include glycol dehydration, absorbent guard bed, and refrigeration (Baker and Lokhandwala, 2008). Developments in membrane materials that would allow for less pre-treatment of the gas, without significantly impacting the membrane efficiency or lifetime, may be key to enable compact offshore CO2 separation systems. PoroGen has developed a novel hollow fiber membrane technology based on poly ether ether ketone (PEEK) which is highly resistant to chemical deterioration and may be used with limited pre-treatment.

Membrane contactor A membrane contactor is a combination of the amine process and membrane separation process. In a membrane contactor, the phases are separated by a membrane and it allows mass transfer between liquid and gas phases without direct contact between the phases. For removal of CO2 from natural gas the liquid phase will be an absorbent e.g.: MEA, DEA, or MDEA (Methyl diethanolamine). In contrast with a membrane separation process there is a low pressure drop across the membrane. The driving force for mass transfer in the membrane contactor is the difference in partial pressure. CO2 permeates through the membrane and reacts with the solvent. Methane does not react and have low solubility in the solvent. The amine solution is then sent through a desorber to regenerate the amine. Developments in membrane technology have identified membranes that are resistant to the amine solvents used and tests have shown removal of over 90% CO2 in one separation stage (Makkuni et al., 2013; Li et al., 2015). Chan et al., (2014) have also performed testing showing removal of 89% or more of the CO2 in one separation stage, the membrane material used is not mentioned. 5.4.2 Oxy-fuel power generation Oxy-fuel combustion is the process of burning carbonaceous fuel using pure oxygen instead of air as the primary oxidant. Oxy-fuel combustion produces approximately 75% less flue gas than air fueled

CSLF Offshore CO2-EOR Task Force Page 45 of 80 Version: Final 08 November 2017 combustion and produces exhaust consisting primarily of CO2 and H2O. Since the nitrogen component of air is not heated, fuel consumption is reduced, and higher flame temperatures are possible8. The oxy-fuel combustion process will normally require a high degree of exhaust gas recirculation to lower and control the combustion flame temperature. Hence, by reducing the recirculation, the process can tolerate high amounts of CO2 and other contaminants in the feed gas. This feature makes this solution especially well-suited for: • Enhanced gas recovery (EGR) and EOR – it can take all the back-produced CO2 in with the feed

gas thus eliminating the need for additional CO2 separation. • CO2 rich gas fields – it could enable economic developments by producing electricity. The output of the liquid CO2 and water can be injected for permanent storage or utilized for enhanced gas recovery (EGR) or EOR before being permanently stored. The unit can be applied to provide local green power to offshore installations (individually or regionally) and thus replacing topside power generation that currently accounts for significant CO2 emissions. Any excess power could be sold to the grid onshore for added value. TriGen Energy has developed this technology for onshore and topsides use. Aker Solutions is developing a technology suitable for subsea use, Figure 5.9. The subsea solution being developed operates at a high process design pressure, which enables direct liquefaction of the flue gas with moderate cooling. The liquefied exhaust gas (CO2 and water) can then be pumped directly into geological formations for utility or storage with no costly post processing required, which makes this a cost-effective alternative for zero emission power generation. By locating the unit subsea, close to production and injection wells, and with ample access to 4ºC seawater, the following benefits are achieved: • The robust oxy-fuel combustion process eliminates the need for pre-processing of the feed gas. • The high pressure, naturally provided at the wellhead, combined with the necessary cooling

provided by the cold sea water, eliminates the need for costly post-processing of the flue gas for re-injection.

• The short distances to production and injection wells save much on costly piping infrastructure.

8 https://en.wikipedia.org/wiki/Oxy-fuel_combustion_process

CSLF Offshore CO2-EOR Task Force Page 46 of 80 Version: Final 08 November 2017

Figure 5.9. Illustration of subsea zero emission offshore power generation concept (Courtesy Aker Solutions)

5.5 Novel well technology 5.5.1 SWAG – Water Above Gas Recently there has been an increasing interest in simultaneous water-alternating-gas (SWAG) in oil recovery operations using CO2 as the lesser dense phase. This method involves the simultaneous injection of water at the top of the reservoir formation and injecting CO2 at the bottom of the formation. An injection technique in which gas and water are injected into reservoirs simultaneously can be beneficial. Gas is injected at the bottom of reservoir while water is being injected at the top. This technique makes advantages of the difference in water and gas densities to increase the hydrocarbon recovery. In primary recovery methods, oil is displaced toward production wells by the natural reservoir energy. Sources of natural reservoir energy are fluid and rock expansion, solution gas drive, gravity drainage, and the influx of water from saline aquifers.

CSLF Offshore CO2-EOR Task Force Page 47 of 80 Version: Final 08 November 2017 The difference in water and CO2 densities will provide a sweeping mechanism in which water tends to sweep hydrocarbons downward and the gas tends to sweep the hydrocarbons upward. It is expected that the two displacement mechanisms will work on establishing a flood front, which will increase the sweep efficiency and thus the oil recovery. In order to achieve actual SWAG with water and gas being injected at different elevations in the reservoir through single well, separate flow conduits will be required for the two phases. This can be achieved either through a dual completion solution, or by utilizing the annulus for injection of water. A dual completion will have serious flow limitation due to the available space for two tubings within the space of a casing. Using a single well for the combined injection of both water and CO2 is now made possible with qualification of increased size of flow path through the X-mas tree via the crossover connection to the annulus side of the X-mas tree. Injection of water through the annulus utilizes the existing flow conduit that is the annulus, without impacting the size of the injection tubing. A possible implementation is shown in Figure 5.10.

Figure 5.10. XMT and downhole schematic, SWAG water injection through annulus. (Courtesy Aker Solutions)

The well will, however, have to be recompleted in order to perforate at a suitable location and install an annulus isolation valve. Since the annulus is typically not used to transport significant amounts of fluids, the annulus access through a typical XMT is limited in size, and a special XMT will be required in order to achieve the desired water flow rates. Normally, gas for artificial lift is injected on the annulus side of the X-mas tree through a two inch flow path. The EnQuest Kraken development in the UK sector of the North Sea utilizes the annulus to transport power fluid to a downhole hydraulic submersible pump. This has required a modified tree design to make possible transport of much higher rate of a denser fluid to the annulus side of the X-

CSLF Offshore CO2-EOR Task Force Page 48 of 80 Version: Final 08 November 2017 mas tree. A five-inch flow conduit through the annulus side has been qualified for the supply of high rate of water as power fluid to the downhole hydraulic pump. SWAG with water injection through the annulus could possibly pose challenges related to corrosion and integrity monitoring, however, given the relatively short duration of a CO2 flooding phase these topics will be less critical than for a conventional injection well. 5.5.2 WAG – alternating water gas injection A subsea CO2 processing station located near to the production and injection area can facilitate comingling of produced water and CO2 for injection into a single well. A WAG (Water Alternating Gas) injection system utilised one well for injection of water for a duration of time follow by gas injection for another duration of time. When water and gas are supplied from topsides the fluid is cold when arrived to a subsea well and hydrate formation will occur if hydrocarbon gas or CO2 is mixed with water. A subsea WAG system would therefore require purging with a neutral fluid when shifting medium to be injected. A fluid such as MEG or methanol at high pressure would be required as a barrier fluid between the supply of water and gas such that any leakage across a valve is from the barrier fluid to the water or gas. The produced well fluid with CO2 and water has natural high temperature which makes comingling of CO2 and water and combined fluid injection into a subterranean reservoir possible when production and injection is physically near.

5.6 Mobility Control for CO2-EOR CO2 mobility control is a very important issue in offshore CO2-EOR projects. Due to large well spacing in offshore situation, injection sweep efficiency should increase considerably compared to onshore applications. If CO2 is allowed to segregate inside the reservoir, substantial parts of the reservoir would remain un-swept reducing the volume of incremental oil significantly. While common techniques such as CO2 WAG or SWAG can still be used, studies have been carried out to develop new generation injection techniques to increase oil production beyond the conventional CO2 injection and, at the same time, eliminating problems related to water injections such as water-shielding (Nazarian et al., 2014). These techniques make use of increased miscibility of oil and injected CO2 at lower temperatures by conditioning the reservoir temperature around the injection well and in the path between injectors and producers. Modification of injection composition is another method suggested to achieve control over CO2 front. Composition of the injected mixture is modified at cycles to create gas-like and liquid-like behaviour at injections point. This resembles a WAG injection but unwanted effects such as relative permeability hysteresis are avoided. The simulation studies indicate that these methods can be more affordable and effective than traditional methods such as CO2 WAG or carbonated water injection in situations where pressure build up can be an issue (CCS), water resources are scarce, or water shielding is cause of concern during CO2-EOR floods in water-wet reservoirs. These methods work by reducing the magnitude of gravitational forces through an increase in the density and viscosity of the injected phase. For CO2-EOR, in addition to property modifications, compositional effects (i.e., component exchange between the injected blend and in-situ hydrocarbon) also play an important role. For CO2-EOR, the costs associated with injection of modified mixtures of CO2 are more affordable and economy of the project is more manageable. For a properly designed injection, it is possible to produce back the injected hydrocarbons that are used to make up the CO2 mixture blend.

CSLF Offshore CO2-EOR Task Force Page 49 of 80 Version: Final 08 November 2017 The CO2 storage capacity is strongly limited by the unstable displacement of water and oil since CO2

at reservoir conditions is very mobile and has very low viscosity. These conditions cause early CO2 breakthrough. Viscous fingering, gravity override and flow in high permeability pathways reduce the volumetric sweep and the effectiveness of CO2 injection processes. Foam is a potential remedy for this problem. Application of foam, by adding surfactants to the CO2, can give CO2 a more favourable mobility ratio relative to oil and water. This will improve oil recovery and the net CO2 storage potential; as also mobile water will be displaced, providing more storage volume for CO2. This reduces needs for handling and re-injection of produced CO2. Thus, CO2-foam EOR reduces operational cost, increases the commercial value of CO2, and provides improved oil production revenue for the industry and enables CCUS. The microscopic sweep during CO2 injection is potentially very high as result of miscibility between oil and CO2, diffusion, and oil swelling. The volumetric sweep efficiency, however, is generally low because of the high CO2 mobility and low density. This causes fingering, gravity segregation, and early breakthrough in the production well, resulting in the need to recycle large quantities of CO2. This is especially challenging in fractured reservoirs, defined here as dual porosity systems with bulk oil located in low permeability matrix surrounded by a high permeable fracture network, where the contribution from viscous forces is limited. Here, the main production mechanism is gravity drainage, with the additional benefit of diffusion and volume expansion of oil, especially near or at miscible conditions (van Golf-Racht, 1982). Laboratory experiments indicate that miscible displacement/drainage aided by diffusion in fractured reservoirs can be an efficient production mechanism (Firoozabadi, 1994), however, it requires close fracture spacing for the rate of diffusion to significantly contribute to oil recovery (Firoozabadi, 1994; Thompson and Mungan, 1969; Trivedi and Babadagli, 2008). In most fractured reservoirs gas-oil gravity drainage is a slow process, with early breakthrough of injected gas and poor CO2 utilization (see e.g.: (Grigg and Schechter, 1997; Jonas et al., 1990). The poor macroscopic sweep efficiency associated with the large mobility of the injected CO2 may be improved with CO2-foam to produce a more favourable mobility ratio to increase sweep, and thereby improve oil recovery (Talebian et al., 2013). Foam effectively increases the viscosity of the gas phase by mixing gas and surfactant solution, creating a discontinuous gas phase separated by thin water films (lamella) stabilized by the surfactant. While there have been several successful foam pilots (see e.g.; (Blaker et al., 2002; Li et al., 2009; Mukherjee et al., 2014; Sanders et al., 2012; Yu et al., 2008), historically very few foam pilots in fractured reservoirs have been performed, and those few have largely been deemed unsuccessful (Enick et al., 2012; Smith, 1988). This has been attributed to the lack of foam generation mechanisms in fractures, namely snap-off, film division and leave-behind. Recent research, however, confirms in-situ foam generation in single fractures (Buchgraber et al., 2012; Kovscek et al., 1995), leading to increased sweep (Yan et al., 2006) and flow diversion within a rough-walled carbonate fracture network during co-injection of surfactant and gas (Fernø et al., 2014). Hence, the reported unsuccessful foam pilots in fractured reservoirs may be related to operational issues or lack of optimized, field-specific surfactants (Castanier and Hanssen, 1995; Prieditis and Paulett, 1992), rather than lack of foam generation mechanisms in fractured reservoirs. With the development of better surfactants (Buchanan, 1998; Cui et al., 2014; Elhag et al., 2014; Ryoo et al., 2003), the injection of foam in naturally fractured reservoirs is increasingly recognized as a potential EOR technique in fractured reservoirs (Farajzadeh et al., 2012; Haugen et al., 2012; Lopera Castro et al., 2009; Panahi, 2004; Pancharoen et al., 2012; Zuta and Fjelde, 2010). For a comprehensive literature review of CO2 mobility control, including foam, please see (Enick et al., 2012). CO2 foam injection can be an important tertiary oil recovery process for mature water flooded fields worldwide. Norway has e.g., more than 23 mature water flooded reservoirs of significant size that after water flooding will have approximately 2,400 million Sm3 residual oil (Grimstad et al. 2012). According to a 2010 US White Paper on CO2 EOR (DOE/NETL-2010/1417, April 2010, ARC 2010), US import of foreign oil may be reduced by 30% if a "next generation CO2 EOR technology" based on

CSLF Offshore CO2-EOR Task Force Page 50 of 80 Version: Final 08 November 2017 mobility control can be achieved, providing 137 billion barrels of additional oil from on-shore oil fields in the US. A successful tertiary CO2 EOR project provides synergy between the need for increased energy production and the reduction in emission of anthropogenic CO2 by storage in sedimentary rocks. There is a need for new knowledge and improved tools to design and predict foam flooding as mobility control and improved sweep in secondary and tertiary EOR in laboratory testing, field pilots, and optimize full field implementation. Field specific properties such as oil composition, brine salinity, temperature and pressure, and reservoir lithology will require carefully adapted surfactant formulation for each case. A roadmap to successful field implementation using foams for mobility control needs to be developed and tested in onshore field pilots, in both clastic and carbonate reservoirs, before offshore operations are launched. Low cost, high stability, and environmentally acceptable surfactants for CO2 foam EOR field implementation needs to be developed and this is most cost efficient in onshore operations. Recent research has developed formulations for CO2 foam mobility control in both sandstone and carbonate formations (cf. US DOE projects DE-FE0005902 and DE-FE0006823). An important finding of this research is that one formulation does not fit all reservoirs. A distinction must be made between sandstone and carbonate/chalk lithologies due to different adsorption characteristics. Anionic surfactants are preferred for sandstones as the anionic surfactants are repelled by the negatively charged sites of the grain surfaces. In high temperature, high salinity, carbonate formations have required application of a switchable-cationic ethoxylated amine surfactant to form a highly viscous CO2 foam (Cui et al., 2014; Elhag et al., 2014). In addition, CO2-soluable surfactants may be injected with the CO2 (Chen et. al. 2012, McLendon et. al. 2012) to assure that the surfactant goes where the CO2 goes rather than only following the water. This can be useful both for EOR and saline aquifer storage. Foam injection for gas mobility control and improved sweep efficiency in heterogeneous reservoirs has recently been targeted as a key research area for EOR (Haugen et al., 2012, Pancharoen et al., 2012, Bertin et al., 1999, Farajzadeh et al., 2012, Haugen et al., 2014, Fernø et al.. 2014, Haugen et al., 2012, Brattekås et al., 2013, Gauteplass et al., 2013, Eide et al., 2013, Fernø et al., 2012, Haugen et al., 2010. Ersland et al., 2010). Current fundamental knowledge of the physics of foam behavior in heterogeneous rocks is inadequate to satisfactorily describe and predict fluid flow and thus oil recovery. Existing models can describe foam behaviour in oil-free systems (Vassenden and Holt 2000). A general characteristic of many surfactant systems is that the foam is unstable in the presence of oil at even low saturations. It is unclear how residual oil after CO2 flooding will affect foam stability in flooded regions of typical NCS oil reservoirs. Successful implementation of CO2 Foam EOR requires that surfactant systems that generates foam and lowers mobility in the absence of oil, while selectively not foaming in the presence of residual oil and identify surfactant systems that form stable foam also in the presence of CO2 residual oil. Thus, these surfactants may be used for selective mobility control in regions without oil or with CO2 residual oil, while allowing CO2 to flow efficiently and produce oil in regions where the oil saturation is higher. Direct observations on pore scale and in-situ imaging of foam propagation and oil saturation at core- and block scale at reservoir conditions have been reported in the literature and map the mechanisms involved. The behaviour of foam for varying oil saturations is difficult to characterize and model. Research for improving the modelling of foam in heterogeneous systems with and without oil present is needed. A novel technique for CO2 imaging has recently been reported, where, for the first time, medical Positron Emission Tomography (PET) explicitly depict CO2 flow in porous rocks. A better fundamental understanding of CO2 foam behaviour in sediments analogue to those found in reservoir formations will allow industry to better design processes for a number of fields.

CSLF Offshore CO2-EOR Task Force Page 51 of 80 Version: Final 08 November 2017 Some important requirements for successful offshore CO2 Foam EOR developments have been identified as follows: - Complete value chain of operations needs to be included covering capture, transport, and storage. - CO2 needs to be captured near field site or transport infrastructure available. - Synergy is needed with ongoing onshore CO2 Foam EOR pilots in Texas, where 80% of all CO2

EOR projects are performed: • Provides 30 years’ experience in CO2 EOR. • Cost associated with onshore field tests are only a fraction of the costs for offshore field

tests, thus offshore technology development needs to be linked with onshore CO2 Foam EOR innovations.

• Short inter-well distances in onshore oil fields yield faster results and less expensive testing environment for offshore challenges.

- Foam and mobility control has significant potential for a “quantum leap” within EOR. - International collaborations are needed, both because of high cost and complexity. - Up-scaling is the major challenge in obtaining reliable predictive models of oil recovery in CCUS;

this may be achieved by step-wise up-scaling from lab to onshore operations and finally to offshore pilots.

- CO2 Foam EOR mobility control may establish next generation CO2-EOR flooding providing potentially less than 10% residual oil in swept zones.

5.7 Conclusions Significant and promising technologies for reducing the cost of separating CO2 from production fluids in CO2-EOR operations are under development and, to some degree, testing. Compact sub-sea equipment for CO2 processing and mobility control using CO2 foam appear to have large potential when it comes to reducing CAPEX and OPEX for CO2-EOR projects.

6. CO2 SUPPLY CHAIN ISSUES Offshore CO2-EOR with CO2 sources onshore will require a certain degree of flexibility: • In general, CO2-EOR projects will have a shorter lifetime than the emitting sources, which will be

power and industry plants. • The amount of CO2 available from one source may be too small to meet the demands of one or

more CO2-EOR projects. Thus, an optimal solution for offshore CO2-EOR may require an infrastructure, or network, that connects sources and CO2-EOR fields. CO2 infrastructure for offshore CO2-EOR will generally consist of capture from sources, individually or in clusters, transport by pipeline or ship to a collection hub9 and distribution to the individual CO2-EOR fields. This section will deal with the transport part and collection hub, including conditioning of the CO2 and injection approaches. Hubs are common in the natural gas distribution industry, both in North America and Europe. Here, pipeline networks interconnect in order to bring together gas from many different production fields, or to distribute gas to dispersed markets. Hubs for CO2-EOR also exist onshore in the United States, in the CO2 pipeline distribution industry. Two examples are the Denver City and McCamey Hubs (GCCSI, 2016a)10. Much of the CO2 transported through the US pipeline system is used in EOR operations.

6.1 Considerations when choosing Transport Methods As is discussed below, the technology for transportation is available and in use. This applies 9 Here a hub is a facility that collects captured CO2 from several sources 10 GCCSI = Global CCS Institute

CSLF Offshore CO2-EOR Task Force Page 52 of 80 Version: Final 08 November 2017 both to pipelines and ships, although the former is limited to one offshore CO2 pipeline and the latter to small ships.

Offshore CO2-EOR projects will be site and situation specific. Many considerations must be made when planning and designing infrastructure for offshore CO2-EOR. Economics will be a main driver on the choice of CO2 transport technology options. Factors to consider include (not necessarily in order of priority): • Number of fields to be served. • Demand and supply of CO2 and capacity utilisation. • Impacts of intermittent supply and injection of CO2. • Economy of scale . • Location of fields relative to sources, i.e,. distances for transport. • Lifetime of EOR project and need for flexibility. • Flexibility of transport method. • Need for new wells (wells are not a topic for this chapter). • Possibilities to re-use existing infrastructure, particularly pipelines. • Reservoir requirements for CO2 conditioning before injection with respect to e.g.:

o Need for compression of the CO2. o CO2 quality and characteristics; acceptable combinations of pressure, temperature, and

(maximum) flow rates ([p, T, q]) at the wellhead (avoid freezing, hydrate formation, and fracturing of the reservoir).

o Need for additional processing of CO2 rich gas to remove impurities. The injection approach for CO2 into the reservoir will depend on the transport method from source or hub to the injection well. The options include: • Direct from the ship via buoy. • Offloading to an offshore intermediate storage, floating or fixed. • Offloading to onshore intermediate store and pipelines/ships to offshore CO2-EOR fields.

6.2 Status and challenges - Pipelines Pipelines are the most common method of transporting the large quantities of CO2 involved in CCS projects. GCCSI (2015, 2016b) and ZEP (2017) give the status of CO2 transport by pipeline, including international R&D activities. Since that publication, ISO has issued an international standard with focus on what is distinct to CO2 pipelines relative to other pipelines (ISO, 2016). There is, however, very limited experience with CO2 pipelines through heavily populated areas, and the 153km pipeline at Snøhvit is the only offshore CO2 pipeline. The technology for CO2 pipelines is well established and CO2 transportation infrastructure continues to be commissioned and built, but RD&D can still contribute to optimizing the systems, thereby increasing operational reliability and reducing costs (GCCSI, 2015). This applies, in particular, to understanding the impacts of impurities and validating predictive models for CO2 pipeline design. Where it is feasible, reuse of existing pipelines could be a very cost-effective transportation solution, although the viability of such pipelines to transport CO2 may be uncertain. Examples of locations with existing pipeline networks are the Scottish and Norwegian sides of the North Sea as well as the US Gulf coast. The use of existing pipeline networks requires a suitable CO2-EOR ‘end field’ to be located close to the offshore pipeline location. Planned supply chains for CO2-EOR should perform inspection of existing lines with the objective to decide to what extent they can be reused, e.g.: with construction of new risers and ‘J tubes’ that will connect the pipelines to the ‘end fields’. The workload associated with this could be an order-of-magnitude less than would be involved with a new pipeline, at least in the Scottish North Sea (Element Energy Limited, 2013).

CSLF Offshore CO2-EOR Task Force Page 53 of 80 Version: Final 08 November 2017 Compression will most likely be needed if pipelines are re-used to transport CO2. Alternatives include: • Booster platform for re-use. • Extra compression power on existing platform to be used for injection. • Onshore compression. Sub-sea compression near the well (see Ch. 4) has the potential to become a cost-efficient alternative to the above. If new, purpose-built CO2 pipelines are constructed they may be able to operate at sufficient pressure that re-compression at the field is not required before injection into the reservoir.

6.3 Status and challenges – Ship transport Ship transport can be an alternative to pipelines where CO2 from several medium-sized (near) coastal emissions sources need to be transported to a common injection site or to a collection hub for further transport in a trunk pipeline to offshore storage. Transport of food quality CO2 by ships and barges already takes place on a small scale (1,000 – 2,000 m3) in Europe. The CO2 is transported as a liquid at 15 – 18 bar and – 22 to -28oC but for larger volumes 6-8 bar and around -50oC may be better (Skagestad et al., 2014). Some design work has been started by major carriers, such as Mærsk Tankers (undated), Vermeulen (2011) and Chiyoda (2011, 2012). A feasibility study (MPE, 2016)11 for implementation of a full-scale industrial CCS project in Norway concluded that ship transport is not a technical barrier for realization of the full-scale. This is in agreement with a major Dutch study (CATO, 2016), a Scottish literature study (Brownsort, 2015) and the Antony Veder study (Vermeulen, 2011). The studies considered ships in the range of 5 kt to 50 kt CO2 capacity. The MPE study also included 45 bar and + 10oC in addition to the above two conditions. Transporting CO2 as a liquid in ships requires liquefaction facilities before loading. The technology for this exists. However, in the cases of low-medium pressures and temperatures the CO2 will require conditioning before injection into the reservoir. Offloading to onshore or floating intermediate storage sites will not require conditioning of CO2 on the transport ship. The process equipment for compression, heat exchange, and injection will be located on or at the intermediate storage site, which would not be included in the transport interface, and is part of the storage sub-project. The transport ships will contain the necessary equipment (e.g.: pumps) to transfer the CO2 to the intermediate storage site. There is little relevant experience from this type of offloading system for floating intermediate storage, whereas the technology is available for onshore intermediate storage.

In the case of direct injection from ship to well, it is anticipated that this will take place a buoy. Single point moorings and transfer technologies are available27 but may need adapting for handling CO2. In this case, conditioning, pressurisation and heating of the CO2 will need to take place on the ship. This will require significant energy in the cases of low pressure, even if sea water is used as heat source. The extensive experience with offloading buoys in the North Sea does not cover the higher frequency connection and disconnection that would be needed for direct injection from transport ships. This issue is in need of further engineering for optimisation (Vermeulen, 2011; Brownsort, 2015). One consideration for this option is a possible requirement for CO2-EOR of continuous or semi-continuous supply of CO2, which may require a buffer storage not offered by direct injection from ships. No major issues with ship transport, loading, and off-loading of the CO2 have been revealed in the reviewed studies. However, as pointed out by Brownsort (2015) there is little coverage of offshore

11 MPE = Norwegian Ministry for Petroleum and Energy

CSLF Offshore CO2-EOR Task Force Page 54 of 80 Version: Final 08 November 2017 CO2-EOR in the literature, it being included under general CO2 storage. There may be requirements to the CO2 supply chain specific to CO2-EOR that have not been addressed or fully considered in the literature. Further needs for technology development of ship transport is linked to optimization and qualification of the first systems for large-scale projects. Offshore loading/unloading operations on the Norwegian continental shelf are done either via tandem from the stern of a ship-shaped FPSO, or via a subsea flowline and loading/mooring buoy where the shuttle tanker can connect. Both technologies could be applicable in a CO2 for EOR project, where injection could occur either directly from a shuttle tanker with onboard injection pumps, or via a dedicated storage and injection tanker. In the latter case, the storage tanker would be permanently moored at the field, with sufficient storage capacity to allow continuous injection and injection pumps. Shuttle tankers would arrive at the field and offload to the storage and injection vessel, typically using a bow to stern loading system as indicated in Figure 6.1.

Figure 6.1. Bow to stern loading from shuttle tanker to storage and injection vessel. Possible buoy solution indicated. (Courtesy Aker Solutions)

In the case where injection occurs directly from the shuttle tanker, the shuttle tanker would arrive at the field and connect directly to the offloading buoy as shown in Figure 6.2.

Figure 6.2 Shuttle tanker connecting directly to offloading buoy. (Courtesy Aker Solutions)

CSLF Offshore CO2-EOR Task Force Page 55 of 80 Version: Final 08 November 2017 Although the loading and offloading systems described are well known and in use, further qualification may be needed. Parameters to be considered include a large number of load cycles at relatively challenging pressure and temperature conditions compared to a typical dead oil loading case and material requirements for handling CO2.

6.4 Initiating new offshore transport systems CO2-EOR on a profitable scale will likely require a constant and stable supply of CO2 over some decades and a flexible infrastructure system for transporting the CO2 to several oil fields. For this to happen, different industries, sectors, and authorities will have to work together and coordinate activities. The activities will include CO2 capture at regional clusters of power and industrial plants, transportation of the CO2 to hubs and the individual receiving fields and injection. Preliminary studies of the feasibility of such systems have already started in some regions, most notably the Gulf of Mexico and the North Sea. As there are time windows for profitable opportunities oil and gas authorities should work with other parts of the governments and the industries to create business models and start coordinated planning immediately. Most gaps, risks, and challenges connected to offshore CO2-EOR are commercial and political in nature. Some thinking on business models have started that include the separation of CO2 capture at the sources from the transport and storage parts (Esposito et al., 2011; MPE, 2016; Pöyry, Tesside Collective, 2017 and Banks et al., 2017). In these models a split of costs and risk between the government and the industry players have been explored, e.g.: that governments take a certain responsibility to develop transport and storage networks. For a pilot project, one viable alternative could be to place suitable pressure vessels on the deck of an outdated shuttle tanker, which would be a low CAPEX alternative suitable for verification of injection concepts. However, as the market develops, there is no doubt that the availability of suitable vessels for CO2 transport will improve. Still, it seems unavoidable that custom built vessels will be required for early commercial projects.

6.5 Case studies There are presently no operating examples of networks or infrastructure where CO2 is captured from more than one source, collected, and transported to an offshore oil field for CO2-EOR. Below follow some examples of studies that have been undertaken. 6.5.1 UK case studies In the UK several analyses have been conducted to investigate the potential for CO2-EOR in oil fields in the UK sector of the North Sea (Reid, 2015, SCCS, 2015). It is envisaged that CO2-EOR, if carefully navigated, can accelerate the emergence of a system for capturing and transporting CO2 for storing beneath the sea bed, Figure 6.3. The potential for incremental oil production has been estimated to above 3,000 million barrels with an associated storage of more than 1,430 million tonnes of CO2 for all fields on the UK continental shelf. The potential of fields in the Central North Sea (CNS), will be more than half of this. The fields in the CNS can possibly be served by some re-purposing of exiting offshore pipelines and the industrial infrastructure at St. Fergus.

CSLF Offshore CO2-EOR Task Force Page 56 of 80 Version: Final 08 November 2017

Figure 6.3. Conceptual vision of CO2 storage beneath the North Sea, linked to emission sources with capture. Reproduced by permission of SCCS (2015). The insert (from A. Kemp, Global Energy Systems Conference, 2013) shows fields in the UK Central North Sea thath have been found particularly suitable technically and economically for CO2-EOR. 6.5.2 A Norwegian case – Gullfaks

In 2003-2004 Statoil undertook studies of CO2-EOR for the Gullfaks Field (MPE, 2010; Berger, et al., 2004, Elsam et al., 2003). It was assumed that 5 Mt CO2/year would be available for 10 years. This would give an increased oil production of 18.3 Sm3 relative to water injection, or 4.1% of oil in place. The concept was found to be technically feasible, but with the CO2 prices and credits as well as oil price at that time the economics were unfavourable for CO2-EOR. Several options for CO2 supply were evaluated. In none was a single geographical source sufficient for the needs of Gullfaks and scenarios with delivery of CO2 from two or more sources were developed. The base case (5 MT CO2/year) transported CO2 by pipeline from two sources in Denmark to Gullfaks, with a trunk line from Gullfaks to the gas terminal at Kårstø for the back-produced CO2 and a line from Kårstø to the trunk line for the recycled CO2 (see Figure 6.4 for locations). Other scenarios included ship transport as well, an example is shown in Figure 5.3 for a supply of 5.5 MT CO2/year.

CSLF Offshore CO2-EOR Task Force Page 57 of 80 Version: Final 08 November 2017

Figure 6.4. A network of sources and transportation means to supply Gullfaks with 5.5 MT CO2/year. Schematic figure based on Agustsson and Grinestad (2005), Berger et al. (2004) and Elsam et al., 2003

6.5.3 A Vietnam case – Rang Dong Field A joint Japan and Vietnam CO2-EOR pilot test was conducted on the Rang Dong Field offshore Vietnam in 2011 as a single-well Huff 'n' Puff following a preliminary study that indicated feasibility (Uchiyama et al., 2012; Ha et al., 2013; Kawahara, 2016). CO2 was injected into the well and the well was flowed after soaking. Operation was successfully completed without any operational trouble and HSE issues and the CO2 Huff’n’Puff Test provided following results: • CO2 Injectivityconfirm ed . • Oil Production Increase . • Water Cut Reduction. • Oil Property Changes by CO2 injection . • Oil Saturation Changes before / after CO2 injection. However, the feasibility study involving possible CO2 sources, a fertilizer plant and a CO2-rich gas field, with transportation by pipelines (Figure 6.5), showed that the cost was detrimental to the project and it was terminated. The main cost drivers were the pipelines and modifications on the platform for separating and re-injecting recycled CO2. EOR using hydrocarbon gas (HCG) has significantly better economy (US $100 mill vs. US $1 000 mill) despite lower EOR. The Japanese oil company JX concluded that CO2-EOR is technically applicable, but economically challenging for Rang Dong due to inconveniently located offshore project, but that they will continue development of CO2-EOR technology for maximizing oil production and reduction of CO2.

CSLF Offshore CO2-EOR Task Force Page 58 of 80 Version: Final 08 November 2017

Figure 6.5. Location of the Rang Dong Field relative to the CO2 sources. From (Kawahara and Hatakeyama, 2016)

6.6 Conclusions There are no technical barriers to building CO2 infrastructures that can supply CO2 to offshore EOR projects, although there is some need for optimisation and some systems will need to be qualified for the specific use. Gaps, risks, and challenges are commercial and political in nature and may include the cooperation of different industries across the CCS value-chain, the lack of project-on-project confidence, the completion of projects on cost and schedule, operational availability, flexibility, reliability, financing and political aspects, and last but not least, lack of business models for larger CCS systems. Some thinking on business models have started that include the separation of CO2

capture at the sources from the transport and storage parts (MPE, 2016; Pöyry and Tesside Collective, 2017).

7. MONITORING, VERIFICATION AND ACCOUNTING TOOLS FOR OFFSHORE CO2-EOR

In this chapter we review available work and best practices relevant to setting the goals of monitoring, verification, and accounting (MVA) applied to an offshore EOR project, focusing on the activities in the geologic environment including wells. No specific and detailed precedent tailored to this topic is available. Extensive work on MVA activities is focused on the other subsets of geological environments, which include diverse onshore settings and saline aquifers and depleted fields offshore (Table 7.1). Selected general citations are provided background to the current topic in Table 7.2, however because of the abundant publication available, no detailed review of the many options and approaches to designing a monitoring program and selecting monitoring tools is undertaken here.

CSLF Offshore CO2-EOR Task Force Page 59 of 80 Version: Final 08 November 2017 Table 7.1. Examples of MVA studies and projects for storage settings other than offshore EOR. Setting Operation

Onshore Offshore

Injection for storage in saline formations

Quest, IBPD, Gorgon and dozens of smaller fields

Sleipner, Sbøhvit, Tomakomai

Injection for storage in abandoned reservouir

Lacq/Rousse, Otway Phase 1 Goldeneye, Miller*

Injection for EOR/EGR Denver Unit, West Ranch, Cranfield, Bell Creek, Hasings, and others

* Goldeneye and Miller are feasibility studies

Table 7.2. General background on MVA (not specific to Offshore CO2 EOR settings) Reference Short name Key content IPCC (2005) IPCC Special report NETL (2012) NETL Best Practices

for MVA Related to US regional Sequestration partnership experience MVA tools and US-based case studies

Cooper (2009) CCP Technical Basis of CCS

Oilfield and CCS case studies oil industry expertise

Jenkins et al., (2015)

10 Years after IPCC update

Containment, conformance, and assurance monitoring, case studies

The extensive previous work on offshore monitoring has been focused on storage in saline formations or in hydrocarbon reservoirs without intent to produce was the topic of a previous CSLF report and a few key citations from that report are provided in Table 7.3. Monitoring of CO2 storage in association with CO2 EOR has also been recently been evaluated, however these projects have been focused on the by far most common setting for CO2 EOR in onshore fields (Table 7.4). Table 7.3. Resources on offshore monitoring Reference Short name Key content CSLF (2015) CSLF – Offshore Storage

review An overview of status of offshore storage, with a focus on the current dominate stings in saline and depleted fields. Chapter 7 of this report reviews monitoring technologies

IEAGHG (2015)

IEAGHG Offshore monitoring review

A review of monitoring experience and options, with details on successful deployments.

Chadwick and Eiken (2013)

Sleipner experience One of many papers on successful monitoring of 20 years of offshore CO2 storage in a saline formation associated with the Sleipner field in the North Sea. See additional papers cited in 5 and 6.

Hansen et al.,(2012)

Snøhvit experience Overview of experience with offshore saline CO2 storage in association with the Snøhvit gas field in the Barents Sea.

Tanaka et al. (2014)

Tomakomai experience Overview of planning offshore saline CO2 storage in a near shore setting in Japan.

CSLF Offshore CO2-EOR Task Force Page 60 of 80 Version: Final 08 November 2017 Table 7.4. Resources on CO2 EOR monitoring (with a focus on onshore settings) Reference Short name Location Key content Occidental (2015)

OXY MRV* plan

Denver Unit, Wasson field, Permian basin

Monitoring plan for a mature EOR operation

Eidan et al. (2015)

CSLF report on EOR-storage conversion

Various Review of components of EOR, including monitoring.

Hitchon (2012)

Weyburn-Midale BMP**

Western Canadian sedimentary basin, Saskatchewan

EOR project important in development of MVA practices

Wolaver et al., (2013)

Comparing greenfield to brown field

US EOR onshore cases Comparing monitoring options and best approaches in saline (greenfield) setting to reused settings (brownfield such as EOR)

Hill et al., (2013)

EOR as storage

US EOR onshore cases Overview of function of EOR as geologic storage including some monitoring options

Ren et al., (2011)

Monitoring CO2 EOR and storage

Chinese experience, Jilin oilfield, China

A monitoring plan for optimizing production and assuring storage during an EOR pilot

* MRV=Monitoring, Reporting and Verification ** BPM=Best Practice Manual

The task of this chapter is to intersect the available information on MVA applied to storage offshore saline and depleted reservoirs and onshore for EOR to consider the monitoring options suitable for offshore EOR. Under this topic we consider roles and expectations for MVA for offshore EOR, the differences between EOR and storage, and the differences between offshore and onshore MVA programs.

7.1 Roles and expectations of Monitoring, Verification and Assessment for Offshore CO2-EOR Four main categories of motivations are listed here as drivers of MVA: 1) EOR operational needs, 2) regulatory requirements related to subsurface operations and wells, 3) greenhouse gas accounting requirements, and 4) risk and liability management. These motivations can overlap or one motivation can be considered a subset of another depending on the definition of the project and the nature of the regulatory structure. MVA to meet EOR operational needs Various data are commonly collected to optimize oil recovery in current CO2 EOR operations (Lake, 1989; National Petroleum Council (NPC), 2011; Verm, 2015). In conventional operations where CO2 is purchased and is available only in limited amounts, minimizing the ratio of CO2 use per volume of oil recovered (known as utilization ratio) is important to project economics. Surveillance of the CO2 flood operation is commonly practiced to assure that the CO2 effectively contacts the oil and does not bypass oil and break through to production wells prematurely or excessively. In addition, managing the reservoir pressure to maintain conditions near or greater than minimum miscibility pressure are also used to increase recovery and decrease utilization ratio. Although operator-to-operator differences are large, monitoring strategies most commonly collected to meet operational needs at conventional onshore EOR fields are:

1) intermittent or continuous wellhead and bottom-hole pressure for some or all injectors and producers; and 2) volume (and associated density data) for CO2 injected and volumes of produced fluids.

CSLF Offshore CO2-EOR Task Force Page 61 of 80 Version: Final 08 November 2017 Produced fluids from each well are commonly sent to a test facility on a regular (typically monthly) schedule so that the ratios of oil, water, and gas can be assessed. Further chemical testing can be used to quantify methane and other hydrocarbon gasses from CO2 volumes. In addition, various types of oilfield surveillance such as injection and production profile logs, saturation logging using tools such as pulsed neutron, 3-D and 4D geophysical surveys, cross wells surveys, and tracer test programs have been widely used (Cooper, 2009). Although these tools are targeted to optimize CO2 utilization, they can provide much of the basis for effective surveillance and accounting of storage on the reservoir. An example of how an existing CO2 EOR monitoring program was accepted by the US Environmental Protection Agency (EPA) to document storage of anthropogenic CO2 for accounting under the greenhouse gas emission accounting rule is presented by the Monitoring, Reporting and Verification (MRV) plan of OXY (Occidental, 2015). Fluid flow models are often used to optimize CO2 utilization in CO2 EOR projects. However, because of the computation expense of simulation using a compositional model (one that represents the CO2-oil interactions), it is common to simulate only representative injection-production well patterns, and extrapolate these data across the field, rather than conducting a whole-field simulation (Occidental, 2015). It is not clear, at this time, how the optimization of CO2 utilization will be conducted in offshore settings. Current offshore operations differ from onshore operation in that well spacing may be larger and the use of horizontal well components more common. In addition, other business models could substantively change operations. For example, in a future situation, a main driver for a project might be as CO2 off-take, with EOR added as a less important cost recovery element. Alternatively, the increased cost and limitations of fluid handling in a platform or subsea installation might drive operational decisions away from current pattern flood models. Although no detailed plans are available for how to optimize an offshore CO2-EOR flood, the possibility that operations might be different from current onshore operations is considered in this section. Drilling and operational regulatory monitoring requirements Regulatory requirements for offshore CO2 EOR are described in Chapter 7 and may come from marine environmental protection regulations or from well drilling or hydrocarbon production laws applicable to the local jurisdictions. Most hydrocarbon regulation focuses on assurance of well integrity. The criteria of how much hydrocarbon recovery is required to qualify as hydrocarbon recovery could be a consideration under conditions where a major purpose of CO2 EOR is off-take from CO2 capture storage. Current onshore CO2 EOR pattern flood operations are designed with arrays of injectors and producers to form a pattern flood. Economic considerations such as the cost of CO2 and the cost of CO2 handling generally limit the amount of fluid injected, such that the reservoir pressure is maintained in the zone where CO2 and oil are as miscible as possible; however, neither the area nor magnitude of the area of elevated pressure is increased over the life of the project. In most cases the volumetric ratio of total fluids injected to total fluids withdrawn is near 1:1 (Occidental, 2015). MVA to meet greenhouse gas (GHG) accounting requirements Monitoring to document storage efficiency and qualify any CO2 leakage during or after the project operation may be a requirement triggered by the capture process. Under a GHG gas accounting requirement, many of the components of the monitoring program are similar to those detailed for all subsea GHG accounting (CSLF, 2015). For CO2 EOR, an additional component, accounting for CO2 that is produced with the hydrocarbons is needed. In typical project onshore, produced CO2 is commingled with new CO2 arriving at the site and re-injected, a process known as recycle. Efficiency of recycle is specific to the operation, however, available reports indicate that the efficiency is high. The recycling operation is one of the unknowns in

CSLF Offshore CO2-EOR Task Force Page 62 of 80 Version: Final 08 November 2017 design of future offshore EOR projects (Sections 4.3 – 4.4), and a process-specific accounting will be a requirement to complete the GHG accounting process. Several other monitoring needs and options are likely to be different for offshore EOR compared to onshore EOR and offshore EOR compared to offshore storage; these are described in following sections. Risk and liability management Risk management can be a major motivation for implementation of monitoring. Selection of an MVA strategy needs to be closely tied to specific site, in terms of site characteristics, operational condition, and local receptors should leakage occur. These parameters can be integrated in a risk assessment (DNV, 2012). Such a risk assessment is described in detail in the CSLF report on offshore storage (CSLF, 2015), which provides a risk assessment framework, and data on risk to biota and water column risks. Offshore CO2 EOR may have a different risk profile than offshore storage for several reasons: 1) presence of hydrocarbons and 2) active management of pressure can change risk. These differences are described in more detail in the following sections.

7.2 Differences between MVA for CO2-EOR and storage of CO2 A number of key differences in the risk profile are noted between CO2 EOR and CO2 storage (Table 7.5). These differences should trigger differences in the monitoring approach. Some differences result in a possibly lowered risk profile for CO2 EOR than for a similar saline site. Parameters that lower risk include 1) active management of the lateral extent of the CO2 plume and the area and magnitude of pressure elevation because of production; 2) better characterization of the injection zone because of operational data gained during production, such as porosity, permeability, connectivity, and boundary conditions in the reservoir; 3) already demonstrated effective trap and effective seal because of hydrocarbon trapping over geologic time, and 4) role of oil in trapping more CO2 because of CO2-oil miscibility than is trapped by dissolution in water. The applicability of this list of parameters, which was developed with reference to onshore EOR operations to offshore should be critically assessed when applied to offshore. For example, the management of area of CO2 and area and magnitude of pressure that is applied in an onshore pattern flood may not be as effective offshore if the well pattern or density does not exert the same degree of control. Onshore in a depleted field, the abundance of wells, including a large number of very old wells and previously plugged wells can create high risk and high cost to mitigate. This difference is likely to be decreased offshore, where wells are most commonly newer and fewer. Table 7.5. Comparing risks for CO2-EOR and storage of CO2 (Adapted from Hill et al., 2013) Risk Type Storage only (saline) EOR with incremental storage Surface conditions Greenfield (never used) Brownfield – already impacted

by past operations CO2 management Injection only Injection, production, recycle Pressure management Significant risk, can be managed

by water withdrawal Pressure management is goal of EOR

CO2 trapping Quality of seal is inferred Quality of seal is proven Solubility of CO2 in formation fluid

CO2 weakly soluble in brine CO2 highly soluble in oil

Subsurface information density Sparse information, few penetrations

Dense information from well penetrations and past operational history

Well failure Few wells may lead to low risk Abundant and older wells may increase risk *

Pore space access Requires new legal mechanisms Can be built on existing oil and gas precedent

CSLF Offshore CO2-EOR Task Force Page 63 of 80 Version: Final 08 November 2017 Revenue to offset capture cost No Yes Public acceptance Questionable Public more familiar with oil

production * Offshore wells may not be as old or as abundant as in onshore oil fields. Several conditions specific to depleted reservoir settings should be considered in design of an EOR monitoring program (Wolaver et al., 2013). The presence of a local hydrocarbon accumulation as well as past production create perturbations of the environment. Past production may have perturbed the sea floor, the target zone, and possibly shallower zones by pressure depletion, fluid extraction and possible fluid cross-contamination. In addition, methane as well as higher hydrocarbons may be abundant in the reservoir under flood as well as shallower zones. Hydrocarbon anomalies can be the result of geologic seepage, creating geochemical anomaly around the reservoir or as a result of past production activities (e.g.: spills or overboading of fluids). Care should be taken to identify characteristics that would indicated leakage from reservoir depth and separate this signal from anomalies already present in the system. A wide array of geochemical markers including stable and radiogenic isotopic tracers of carbon, oxygen strontium, major and minor elements in fluids, noble gasses, and hydrocarbon characteristics may be useful, but are likely to be site specific. The presence of methane can change the viability of detecting CO2 migration using seismic methods. Seismic velocity can be related to gas saturation at low saturations, but at increased gas saturation the change in seismic response decreases and any change created by introduction of more gas can be difficult to detect. Shallow methane zones or residual methane in the reservoir can therefore mask CO2 migration into the zone (Urosevic et al., 2011). This limitation should be dealt with through modelling likely response and allocation of optimized tools because seismic is seen as a high value approach to offshore MVA in general (CSLF, 2015). Depleted hydrocarbon reservoirs may have long-term histories different from saline storage sites. Saline storage sites are conceptualized as being filled to a designed end and then entering closure and post-closure phases which may require various MVA activities. Hydrocarbon reservoirs, however, will contain hydrocarbons at the end of EOR. It is possible that in the long term these post-EOR depleted fields can be produced by new technologies not currently foreseen. Such an evolution should be considered in the accounting and monitoring strategies developed. Time-lapse seismic methods have proven to be very valuable for the CO2 storage projects (saline aquifers) offshore Norway (e.g. Chadwik et al., 2010; Furre & Eiken, 2014) where strong contrasts in acoustic properties between the water and CO2 saturated portions of the reservoir allow excellent reservoir imaging. For CO2 EOR projects, where the acoustic property contrast between CO2 and hydrocarbon is much less, this level of success in time-lapse seismic imaging is likely to be significantly reduced. However, time-lapse imaging at the onshore CO2-EOR project at Weyburn Canada (White, 2013) has proven successful. Furthermore, with developments in differentiating pressure and saturation effects from time-lapse seismic datasets (Landrø, 2001) the potential for successful seismic monitoring of offshore CO2-EOR projects is significant.

7.3 Differences between MVA for onshore CO2-EOR and offshore CO2-EOR Because no prototype of a typical offshore EOR field is available, it is difficult to know what differences in the risk profile and therefore the monitoring strategy may be. The following issues are raised for consideration: Offshore CO2-EOR may be deployed with a stronger initial emphasis on greenhouse gas accounting. It is possible that high and constant rates of CO2 injection could be needed to achieve GHG goals. Onshore EOR traditionally minimizes the CO2 usage, by maintaining a 1:1 rate of the volume of all fluids injected and all fluid withdrawn. CO2 is augmented by injection of water (WAG process) and the amount of CO2 brought to the site may decrease over time because of increased CO2 recycling and

CSLF Offshore CO2-EOR Task Force Page 64 of 80 Version: Final 08 November 2017 increased water to gas ratio (tapered WAG). High rates of CO2 injection might elevate risk as compared to traditional onshore EOR by allowing CO2 and elevated pressure to migrate outside of the area of the field under control by production. In addition, widely spaced wells typical of offshore settings might create large areas of elevated pressure than is typical onshore. Onshore the traditional highest concern has been contamination of groundwater or surface water resources by brine that leaks from improperly completed wells. Offshore this concern can be lowered if release of brine to marine environments is acceptable. However, concern over leakage of hydrocarbons is of equal or perhaps even higher concern in marine environments than in onshore settings. In some conventional offshore production settings produced brine is disposed of to the ocean rather than being reinjected into the subsurface. In other jurisdictions brine disposal to the marine environment is restricted and geological disposal is preferred. It is not yet clear how the brine handling options in the offshore setting will affect the operations for offshore CO2-EOR projects. In addition, the environmental impacts of CO2 dissolved in the brine to be disposed of may result in precipitation of metals due increased rock-water-CO2 reaction. This issue should be considered (Carruthers, 2016). Offshore well construction, with deviated wells and multilaterals will have an impact on optimization of MVA tools deployed. Risk profiles of such wells may be different than onshore wells. For example the number of wells offshore are typically lower and the well construction is newer than onshore. Some completion risks are unique to offshore wells (CSLF, 2015) and these should be dealt with in the monitoring plan. Costs for well re-entry are typically significantly higher offshore than onshore, and this will have a strong impact on optimization of MVA.

7.4 Transition CO2-EOR to storage – impact on monitoring The monitoring issues for CO2-EOR projects wanting to transition from EOR to storage offshore will include (CSLF, 2013; Eidan et al., 2015): a. Assurance monitoring (where and how much CO2 is in the storage reservoir). b. Requirement for more environmental monitoring (sensors in, or sampling from, the sedimentary

succession above the reservoir, shallow potable-groundwater saline aquifers, soils and surface) over a larger Area of Review or Influence.

c. Baseline monitoring prior to start of CO2 injection. d. Monitoring after cessation of CO2 injection for various periods of time, depending on regulations

in the respective jurisdiction. These activities are feasible with known technology and can be net by operators, but they will have cost impacts.

7.5 Conclusions Offshore CO2-EOR is much less mature than onshore CO2-EOR and offshore storage of CO2, both of which have decades long histories, and will have different risk profiles. This will require special considerations when designing an MVA programme for offshore CO2-EOR. However, a range of monitoring technologies applied in the two other settings are applicable also to offshore CO2-EOR. This review has not identified any technical barriers for proper monitoring of offshore CO2-EOR fields.

CSLF Offshore CO2-EOR Task Force Page 65 of 80 Version: Final 08 November 2017 8. REGULATORY REQUIREMENTS FOR OFFSHORE CO2 UTILIZATION AND STORAGE

8.1 Introduction and scene-setting CO2-EOR offshore has yet to commence (except in Brazil) and therefore regulatory regimes have not been developed or tested. Regulatory regimes exist for CO2 storage offshore, and there are regulatory regimes for CO2-EOR onshore. This section will consider the regulatory issues for CO2-EOR offshore by reviewing work done around this topic. In terms of CO2 geological storage offshore there have been significant international developments because this activity was viewed as otherwise unregulated and in certain project configurations was actually prohibited (e.g.: London Protocol and OSPAR). This international work started from the legal view that storage of CO2 in the water column or sub-seabed may be dumping of waste in the marine environment. However, the international community determined that any use of CO2 in the sub-seabed was not dumping, not therefore prohibited, and not needing specific regulation. Ergo any CO2 used for EOR would not be covered by these CO2-storage specific regulations. Therefore, the default is that any CO2-EOR activity would come under any existing hydrocarbon production regulations, which would be jurisdiction specific. This would mean a regulatory environment based on CO2 as a commodity rather than a waste; wastes are typically more heavily regulated, so this would be beneficial for CO2-EOR. An example of this is the London Protocol’s prohibition on export of waste, which currently means that CO2 cannot be exported for storage (note that an amendment to change this is in place, but not in force due to a very slow rate of ratification). CO2 exported for use in CO2-EOR is not prohibited by this export prohibition. (Dixon 2009 and 2015). A full description of the international regulations for CO2 storage offshore are provided in the CSLF Report “Technical Barriers and R&D Opportunities for Offshore, Sub-Seabed Geologic Storage of Carbon Dioxide” CSLF (2015). The ISO TC265 is currently working on the topic of CO2-EOR and its Working Group 6 is drafting an international standard for CO2-EOR projects to be considered as storage. This is expected to be focused on onshore but similar principles will apply offshore. Note that this draft standard has yet to be approved or made public (ISO, 2017; draft only, to be published). The issues for CO2-EOR projects wanting to transition from EOR to storage offshore will be similar to those onshore. These issues include challenges over site characterization and risk assessment and monitoring baseline measurements (required in advance for storage projects but not necessarily undertaken in advance for CO2-EOR projects), pore space access/ownership/leasing (which may end at the end of EOR operations), and post-closure monitoring and liability issues (CCP4, 2016). If carbon credits are sought there will be a requirement to demonstrate storage and retention of CO2 from the atmosphere. Such regulatory requirements are in place in the EU and USA, and in the UNFCCC’s Clean Development Mechanism. Therefore, if a CO2-EOR project wishes to gain carbon credits, either during CO2-EOR or when it transitions to straight storage, it will have to demonstrate storage and retention of CO2 from the atmosphere by meeting the relevant regulatory requirements.

8.2 Examples of Specific National Regulatory Requirements 8.2.1 UK The Scottish Centre for CCS undertook a review of existing regulations and guidelines covering UK North Sea offshore and concluded that “it would seem possible that CO2-EOR activities would be regulated under existing laws and voluntary practices, with little or no amendments” (Carruthers, 2014).

CSLF Offshore CO2-EOR Task Force Page 66 of 80 Version: Final 08 November 2017 A broader report by the Scottish Centre for CCS considers broader legal aspects for CO2-EOR, and identified areas in the current UK and EU legislation that need to be addressed, although these were focussed on property rights and transboundary movement of CO2, more generic issues (SCCS, 2015). One issue identified is the international requirements (London Convention, OSPAR, EU) for the CO2 stream to be ‘overwhelmingly CO2’. For CO2-EOR the reinjected stream could be a wider mixture of fluids with the CO2-EOR. Such mixtures and the flexibility in ‘overwhelmingly’ should be investigated. 8.2.2 United States The U.S. offshore consists of submerged lands under the jurisdiction of the coastal States, as well as submerged lands that are under Federal jurisdiction, referred to as the Outer Continental Shelf (OCS). The OCS consists of 1.7 billion acres of submerged lands, subsoil, and seabed, lying between the seaward extent of the States’ submerged lands and the seaward extent of Federal jurisdiction. The U.S. Department of the Interior (DOI) authorizes and regulates the development of mineral resources (including oil and gas) and certain other energy and marine related uses on the OCS. Although oil and gas EOR operations occur on the OCS, none to-date have used CO2. The Presidential Interagency Task Force on Carbon Capture and Storage examined the existing U.S. regulatory framework and recommended (in 2010) the development of a comprehensive U.S. framework for leasing and regulating sub-seabed CO2 storage operations on the OCS that addresses the broad range of relevant issues and applies appropriate environmental protections. However, this comprehensive framework has yet to be established; therefore, the existing regulatory framework is shared across multiple Federal agencies, including DOI and the U.S. Environmental Protection Agency (EPA), and may have jurisdictional gaps, including the transition from CO2-EOR to sub-seabed geologic storage of CO2. The UIC Program defines multiple classes of injection wells, each with their own specific regulatory requirements. Oil and Gas operations using CO2 for EOR are regulated as Class II Oil and Gas Related Injection Wells, and if after EOR operations are terminated and the wells are converted to CO2 injection wells for geologic storage, the wells are regulated as Class VI Injection Wells used for Geologic Sequestration of CO2. In 2010, the EPA promulgated regulations for its newly established UIC Class VI wells, which include specific requirements for site selection, well design and construction, and monitoring, verification, and accounting (MVA) of injectate-CO2, and long-term monitoring even after CO2 injection has ceased. The EPA has also developed guidance to support the Class VI regulatory requirements12. Under these regulations (40 CFR § 144.19), operators of Class II wells are required to apply for Class VI permits when there is an increased risk to USDWs from Class VI compared to Class II operations. The EPA also published a memo (April 23, 2015) that discusses six key regulatory considerations when transitioning from Class II to Class VI wells. 8.2.3 Brazil Brazil is important in this context because it has the only operational offshore CO2-EOR project in the world. The state-owned oil company Petrobras operates the Lula oilfield offshore in the Santos Basin and injects CO2 into producing oil reservoirs. This is undertaken within existing petroleum legislation, and there is no CCS regulation in place in Brazil. No carbon credits are sought for this activity. 8.2.4 Gulf Cooperation Council Countries The IEAGHG report on economic barriers for CO2-EOR considers regulatory barriers to a small extent, and for Gulf Cooperation Council Countries it concludes that CO2-EOR activities are generally able to be regulated under legislation used to control oil and gas exploration and production. In all 12 Class VI – Wells used for Geologic Sequestration of CO2: https://www.epa.gov/uic/class-vi-wells-used-geologic-sequestration-co2

CSLF Offshore CO2-EOR Task Force Page 67 of 80 Version: Final 08 November 2017 GCC countries, state-owned enterprises dominate and have full concessions of all oil and gas production, and to a large extent, downstream refining and petrochemical sectors. State-owned operators are generally self-regulating. It is not expected that a lack of national regulation poses a key hurdle to the development of CO2-EOR projects in GCC countries. (Reference IEAGHG 2016).

8.3 Differences between regulatory frameworks for storage and EOR CO2-EOR is regulated by oil and gas or petroleum legislation, whereas CCS can be governed by a variety of regulations, depending on jurisdiction (CCS/GHG specific legislation; mining and mineral legislation; general environmental and impact assessment regulations). This also impacts on the competent authority. Two aspects of the different legislation are: - Presently, CO2-EOR projects are not required to undertake site analysis and evaluation to the

same extent as CCS projects with respect to capacity and integrity, as well as monitoring. CO2-EOR projects wishing to transition to CCS projects after cessation of oil production must bear this in mind.

- A CO2-EOR project ends when the oil production ceases and the field is abandoned according to oil field regulations. If seeking to transition to a CCS project, there may be issues around liability and CO2 ownership.

- Greenhouse gas emissions accounting requirements, including emissions connected to the recycling and injection processes and the potential for “leaked” CO2.

8.4 Regulations on transition of CO2-EOR to storage: What is lacking and recommendations how this may be achieved Regulations on transition from a CO2-EOR project to a CO2 storage (CCS) project were treated by CSLF (2013) and CCP (2016). Although mainly concerned with onshore CO2-EOR both studies concluded that “There are no specific technological barriers or challenges per se in transitioning and converting a pure CO2-EOR operation into CO2 storage operation. The main differences between the two types of operations stem from legal, regulatory and economic differences between the two.” This review has not disclosed anything that invalidates this statement from applying to offshore CO2-EOR vs. offshore CO2 storage. CCP (2016) examined regulations for CO2 storage, CO2-EOR and the transition between the two for the following jurisdictions: USA, the Canadian provinces Alberta, Saskatchewan and British Columbia, the European Union (EU), Australia and Brazil. It was found that EU is the only jurisdiction that has regulations for all three in place, as indicated in Table 8.1. Regulations for the transition from CO2-EOR to CO2 storage are the least developed. Table 8.1. Overview of regulatory status of selected countries/regions (after CCP, 2016)

Regulation for

USA Canada EU Australia Brazil Alberta Saskatchewan British

Columbia CO2-EOR In place In place In place Discussions

under way In place In place In place

Transition In development

Discussions under way

Discussions under way

No information

In place No information

Discussions under way

CCS In place In place In development

In development

In place In place Discussions under way

CSLF Offshore CO2-EOR Task Force Page 68 of 80 Version: Final 08 November 2017 In conclusion, there is need for a clarification of the legislation for the transition from CO2 -EOR to offshore CO2 storage (CSLF, 2013; CCP, 2016). Areas that require particular attention include: 1. Storage site evaluation and geological modelling; 2. Monitoring of the storage site, reporting, and verification; 3. Site closure conditions and post-closure stewardship and liability; 4. Conformance with national GHG inventory guidelines for CCS. Regulators, relevant legal authorities, and policy makers should work with the industry to address the issues and develop the needed legislation and guidelines. Work on standards has already been started by ISO (2017; draft only, to be published).

8.5 Conclusions In all regions considered here, it appears that CO2-EOR activities can be regulated under existing oil and gas regulation, and regulatory uncertainty is not assumed to constitute a barrier to the broader deployment of the technique. However, if the intention is for the CO2-EOR to demonstrate long-term storage, or is seeking an incentive such as carbon credits, additional CCS regulatory requirements will need to be met. These will meet the same challenges transitioning from CO2-EOR to CO2 storage onshore. In general, such transitional requirements do not exist, and the issues are now becoming well documented, see CCP4 (2016) for a comprehensive and up-to-date assessment. One issue identified if storage regulations are to be applied to CO2-EOR is the international requirements (London Convention, OSPAR, EU) for the CO2 stream to be ‘overwhelmingly CO2’. Such mixtures in CO2-EOR re-injected streams and the flexibility in ‘overwhelmingly’ should be investigated. In conclusion, it appears that offshore CO2-EOR activities can be regulated under existing oil and gas regulation, and regulatory uncertainty is not assumed to constitute a barrier to the broader deployment of the technique. However, if the intention is for the CO2-EOR to demonstrate long-term storage, or is seeking an incentive such as carbon credits, additional CCS regulatory requirements will need to be met.

9. SUMMARY OF BARRIERS FOR DEPLOYMENT OF OFFSHORE CO2-EOR There are few, if any, technical barriers to offshore CO2-EOR. However, there are significant barriers related to policy and infrastructure development including: 1. Access to sufficient and timely supply of CO2. There are few, if any, developed sources of CO2

close to the offshore fields amenable to CO2-EOR. Building an infrastructure will require huge up-front investments and the coordination of several stakeholders. A one-on-one source to CO2-EOR field linkage is likely to be more expensive per tonne CO2 than a network, and to have low flexibility with respect to reduced need for fresh CO2 and temporary stops in the CO2 production.

2. Lack of business models for offshore CO2-EOR. Establishing offshore CO2 networks will create many interdependencies and commercial risks concerning both economics and liabilities. Risk- and cost-sharing will be needed.

3. Timing of the EOR operation. The effect of CO2-EOR will be reduced as the field gets more mature and at some point the benefit will be insufficient. A slow development of CCS will also delay opportunities for offshore CO2-EOR.

CSLF Offshore CO2-EOR Task Force Page 69 of 80 Version: Final 08 November 2017 4. High investment costs. Significant modifications and additional equipment on the platforms will

be needed to separate CO2 from the produced oil and gas and to make existing wells and pipes resistant to CO2 corrosion. Development of new technologies can reduce the need for modifications and new equipment, for example, better mobility control or sub-surface separation systems. Use of existing pipelines may also be a way to keep investment costs down.

5. Additional operational costs, OPEX, will result from the need to separate and recompress the recycled CO2. New technologies are also likely to reduce the OPEX.

6. Loss of production while modifying facilities represents an additional up-front cost. The value of the production loss is also dependent on the required rate of return.

7. Uncertainties around regulations exist but are not assumed to constitute a barrier if petroleuam regulations exist offshore. However, it is not clear what requirements different jurisdictions will place on monitoring the CO2 in the underground, both during and particularly after closure, and for the case where the field transfers into a CO2 storage project.

8. Uncertainties around the revenues, namely the oil price and the cost of CO2. Low oil prices and high CO2 cost for the operators will prevent offshore CO2-EOR unless new business models and/or changed tax regimes are implemented to de-risk investments.

9. Uncertainties around the price of CO2 the oil field operator must pay to the CO2 supplier, including the price of the CO2 itself and the transportation costs. The first will often be subject to negotiations between seller and buyer and could be influenced by CO2 prices in a trading scheme.

10. Reservoir characteristics are usually well known for mature oil fields but there will still be uncertainties around reservoir performance and the potential for yield of addition oil.

11. Monitoring. While not being a barrier there will be different considerations to make and regulations to follow when comparing offshore CO2-EOR/storage to onshore CO2-EOR/storage.

10. RECOMMENDATIONS FOR OVERCOMING BARRIERS FOR OFFSHORE CO2-EOR The main recommendation from this work is that governments and industry should work together to: 1. Increase the pace in deployment of CCS. This is a prerequisite for offshore CO2-EOR and needs

action at the highest political level. Slow deployment may lead to missed windows of opportunity for CO2-EOR.

2. Start planning regional hubs and transportation infrastructures for CO2. Building the networks will require significant up-front investments and the coordination of stakeholders, including industries, business sectors, and authorities that will have to work together. The activities will include CO2 capture at regional clusters of power and industrial plants, transportation of the CO2 to hubs and to the individual receiving fields, and injection management. Preliminary studies of the feasibility of such systems have already started in some regions, most notably the Gulf of Mexico and the North Sea. Such studies must be followed up.

3. Develop business models for offshore CO2-EOR. The literature has a few examples that provide some thoughts, but these need to be matured. The business models must include fiscal incentives, e.g.: in term of taxes or tax rebates.

4. Support RD&D to develop new technologies that will reduce the high investment and operational costs for CO2 separation, compression, and injection.

5. Continue to develop regulations specific to offshore CO2-EOR for jurisdictions that do not have these in place. These should include monitoring the CO2 in the underground, both during and particularly after closure and guidelines for when the field transfers into a CO2 storage site.

CSLF Offshore CO2-EOR Task Force Page 70 of 80 Version: Final 08 November 2017

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PIRT Documents

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MEETING SUMMARY Projects Interaction and Review Team (PIRT) Meeting

Abu Dhabi, United Arab Emirates 30 April 2017

Prepared by the CSLF Secretariat

LIST OF ATTENDEES

PIRT Active Members Australia: Andrew Barrett (Chair), Max Watson Canada: Eddy Chui, Mike Monea China: Ping Zhong, Yi-Ming Wei France: Didier Bonijoly Japan: Ryozo Tanaka Netherlands: Harry Schreurs Norway: Lars Ingolf Eide, Åse Slagtern (Technical Group Chair) Saudi Arabia: Ammar AlShehri South Africa: Tony Surridge, Landi Themba United Arab Emirates: Meshayel Omran AlAli, Fatma AlFalasi, Reshma Francy United Kingdom: Brian Allison United States: John Litynski IEAGHG: John Gale

Other CSLF Delegates Australia: Sarah Chapman Korea: Chong Kul Ryu, Chang-Keun Yi

CSLF Secretariat Richard Lynch, Stephanie Duran

Invited Speakers Dipak Sakaria, Abu Dhabi Carbon Capture Company, United Arab Emirates Grant Bromhal, National Energy Technology Laboratory, United States

Observers Canada: Simon O’Brien India: Shishir Tamotia Japan: Jiro Tanaka Kuwait: Harish Reddy United Arab Emirates: Taghreed AlKathiri United States: Sallie Greenberg, Frank Morton

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1. Welcome PIRT Chairman Andrew Barrett welcomed participants to the 27th meeting of the PIRT. Mr. Barrett stated that the two major items to be taken up at this meeting were review of three projects nominated for CSLF recognition and a report and an update on ongoing PIRT activities to engage CSLF recognized projects. Besides these, there would also be a review of the status of the 2017 CSLF Technology Roadmap (TRM) and a discussion on possible future activities for the CSLF Technical Group.

2. Introduction of Meeting Attendees PIRT meeting attendees introduced themselves. In all, thirteen CSLF delegations were represented at the meeting.

3. Adoption of Agenda The draft agenda for the meeting, which had been prepared by the CSLF Secretariat, was adopted without change.

4. Approval of Meeting Summary from Tokyo PIRT Meeting

The Meeting Summary from the October 2016 PIRT meeting in Tokyo was approved as final with no changes.

5. Report from CSLF Secretariat

Richard Lynch provided a two-part report from the Secretariat, which covered the status of CSLF-recognized projects and outcomes from the October 2016 PIRT meeting in Tokyo.

Concerning the portfolio of CSLF-recognized projects, Mr. Lynch stated that as of October 2016 there were 34 active projects and 17 completed projects spread out over five continents, though this would change based on outcomes from the current meeting. For the current meeting, three new projects had been proposed for CSLF recognition.

Mr. Lynch reported that there were four outcomes from the Tokyo meeting: • The PIRT recommended approval by the Technical Group for both the

Tomakomai CCS Demonstration Project and the NET Power 50 MWth Allam Cycle Demonstration Project.

• The PIRT approved a small revision to the CSLF Project Submission Form and will use the completed Form from the Tomakomai CCS Demonstration Project as a model for future project sponsors to use as an example of the kinds of project information being requested.

• The PIRT implemented a project engagement strategy: o CSLF-recognized projects will be contacted for updates on their progress

and accomplishments during years when there are CSLF Ministerial Meetings (i.e., every two years).

o The CSLF Secretariat will oversee this activity. o Information received from projects will be utilized for future TRM updates

and to prepare a summary document as an input to CSLF Ministerial Meetings.

• The 2017 TRM update is underway and on schedule for roll-out in time for the 2017 CSLF Ministerial Meeting. The structure of the new TRM will be slightly

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different than the 2013 TRM and will include information about recent developments in CCS, including COP21 outcomes, and new areas of interest such as CCS with industrial sources and bio-energy with CCS.

6. 2017 TRM Update

The TRM editor, Lars Ingolf Eide, stated that the TRM Working Group created in 2015 has been actively working on drafting the new TRM. The Working Group has been chaired by Australia with representation from Norway, Canada, South Africa, the United Kingdom, the United States, the IEAGHG, and the CSLF Secretariat. In addition, there have been contributions from several international experts on CCS. The overall approach was to refreshing the structure and content of the 2013 TRM as needed, in order to keep the overall level of effort to a manageable level.

Mr. Eide briefly described the main changes from the 2013 TRM: • New time horizons were being used for medium- and long-term recommendations

and targets (2025 and 2035 respectively, instead of the previous TRM’s target dates of 2030 and 2050).

• The “Background” chapter was revised to reflect COP21 targets, and quantitative targets which meet the IEA 2 ºC scenario were used for CO2 sequestration.

• A new section was included on non-technical measures such as regulations, and there is expanded discussion on CCS, CCU, and CCUS.

• The chapter on “Assessment of Present Situation” was shortened and merged into the “Technology Needs” chapter.

• There is less detail concerning specific technology types and fundamentals, and more emphasis on industrial and biomass CCS.

• There is a new separate section on sectors other than power, industry and biomass (though hydrogen production with CCS is the only topic so far).

• There is more emphasis on development of a “clusters and hubs” approach toward CCS, and also on ship transport of CO2.

• Recent CO2 storage projects and activities have been referenced, and description has been updated and expended about various aspects of CO2 utilization.

• There are identified actions to meet technology needs throughout the CCS chain. Mr. Eide stated that the main findings of the 2017 TRM are that CCUS works in power and industrial settings, but implementation of CCUS is well behind the trajectory of reaching the stated COP21 “less than 2 ºC temperature rise” goal. Additionally, CCUS is not possible without the right policy settings and the appropriate financial framework. There are several important recommendations made by the TRM:

• Based on the IEA 2 ºC scenario, governments and industry should work together to contribute to the COP21 targets by implementing sufficient large-scale projects in the power and industry sectors to: o Permanently store 0.5 gigatonnes (Gt) of CO2 per year by 2025 (or have

permanently captured and stored 2 GtCO2); and o Permanently store 2.7 GtCO2 per year by 2035 (or have permanently

captured and stored 20 GtCO2).

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• Governments and industry should work together to: o Develop supportive policy incentives and support for CCS on similar terms

as other low-carbon technologies; o Develop markets and business models for CCUS support; o Accelerate legal and regulatory frameworks for CCS; and o Develop strategic transportation and storage infrastructures using a cluster-

and-hub approach, in particular for industrial CCUS, including early identification and characterization of potential CO2 storage sites.

• Improve CCUS public outreach and education, supporting educators as well as community proponents of CCUS projects.

• Facilitate exchange of data from operating large-scale CCUS projects. • Support RD&D for novel and emerging technologies along the entire CCUS

chain, in order to drive down costs. • Map opportunities, conduct technology readiness assessments, and resolve main

barriers for the implementation of CCUS.

Mr. Eide concluded his presentations by briefly describing next steps. The mostly-final draft of the 2017 TRM has been sent to all CSLF delegations, with a firm deadline of July 1st for receiving comments. A finalized version will be completed and sent to the CSLF Secretariat by September 15th and a publication-ready version will then be prepared for publication and inclusion in Ministerial Meeting briefing documents.

7. Review and Approval of Project Proposed for CSLF-Recognition: Al Reyadah CCUS Project Dipak Sakaria, representing project sponsor Abu Dhabi Carbon Capture Company, gave a technically detailed presentation about the Al Reyadah project. This is an integrated commercial-scale project, located in Mussafah, Abu Dhabi, United Arab Emirates, which is capturing CO2 from the flue gas of an Emirates Steel production facility, and injecting the CO2 for enhanced oil recovery (EOR) in the Abu Dhabi National Oil Company’s nearby oil fields. The main objectives are to reduce the carbon footprint of the United Arab Emirates, implement EOR in subsurface oil reservoirs, and free up natural gas which would have been used for oil field pressure maintenance. The Al Reyadah Project includes capture, transport and injection of up to 800,000 tonnes per year of CO2 (processed at the required specifications and pressure) and is part of an overall master plan which could also create a CO2 network and hub for managing future CO2 supply and injection requirements in the United Arab Emirates.

Outcome: After a discussion which clarified some of the details about the project, there was unanimous consensus by the PIRT to recommend approval of the Al Reyadah CCUS Project by the Technical Group. Project nominators are the United Arab Emirates (lead), Australia, Canada, China, the Netherlands, Norway, Saudi Arabia, South Africa, the United Kingdom, and the United States.

8. Review and Approval of Project Proposed for CSLF-Recognition: Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact (CCSI/CCSI2) Grant Bromhal, representing project sponsor the U.S. National Energy Technology Laboratory (NETL), gave a technically detailed presentation about CCSI/CCSI2. This is a

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computational research initiative, with activities ongoing at NETL, four other National Laboratories, and five universities across the United States, with collaboration from other organizations outside the United States including industry partners. The overall objective is to develop and utilize an integrated suite of computational tools (the CCSI Toolset) in order to support and accelerate the development, scale-up and commercialization of CO2 capture technologies. The anticipated outcome is a significant reduction in the time that it takes to develop and scale-up new technologies in the energy sector. CCSI2 will apply the CCSI toolset, in partnership with industry, in the scale-up of new and innovative CO2 capture technologies. A major focus of CCSI2 will be on model validation using the large-scale pilot test information from projects around the world to help predict design and operational performance at all scales including commercial demonstrations. These activities will help maximize the learning that occurs at each scale during technology development.

Outcome: After a discussion which clarified some of the details about the project, there was consensus by the PIRT to recommend approval CCSI/CCSI2 by the Technical Group. Project nominators are the United States (lead), China, France, and Norway.

An additional outcome from discussion, in light of the “doesn’t fit the mold” nature of the project, was that the PIRT Chair and the CSLF Secretariat were asked to review the CSLF and PIRT Terms of Reference documents to clarify project qualifications for CSLF recognition and to present recommendations at the next PIRT meeting.

9. Review and Approval of Project Proposed for CSLF-Recognition: National Risk Assessment Partnership (NRAP) Grant Bromhal, representing project sponsor NETL, gave a technically detailed presentation about NRAP. This is a risk assessment initiative, with activities ongoing at NETL and four other National Laboratories across the United States, including collaboration with industry, regulatory organizations, and other types of stakeholders. The overall objective is development of defensible, science-based methodologies and tools for quantifying leakage and seismic risks for long-term CO2 geologic storage. The anticipated outcome is removal of key barriers to the business case for CO2 storage by providing the technical basis for quantifying long-term liability. To that end, NRAP has developed and released a series of computational tools (the NRAP toolset) that are being used by a diverse set of stakeholders around the world. The toolset is expected to help storage site operators design and apply monitoring and mitigation strategies, help regulators and their agents quantify risks and perform cost-benefit analyses for specific CCS projects, and provide a basis for financiers and regulators to invest in and approve CCS projects with greater confidence because costs long-term liability can be estimated more easily and with greater certainty.

Outcome: After a discussion which clarified some of the details about the project, there was consensus by the PIRT to recommend approval NRAP by the Technical Group. Project nominators are the United States (lead), Australia, China, and France.

10. Update on CSLF-recognized Projects Engagement Activities Mr. Eide gave a presentation that reviewed an ongoing CSLF initiative, begun at the June 2016 meeting in London, toward better interacting with CSLF-recognized projects. To that end, a new project status reporting form was developed which requests the following information:

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• Name of project • Brief non-technical description • Project status (Active? Ended? If ended, when and why? If still active, what are

the important factors for its continued progress and why?) • Overall timeline, emphasizing next six months • Description of sharable information that has been produced • Description of any interesting outcomes or gains in knowledge • Project’s main point-of-contact for CSLF

Mr. Eide stated that Technical Group delegates were asked to obtain this information, via the form, from all CSLF-recognized projects in their countries. In all, responses were received from 25 of the 35 active CSLF-recognized projects (as of the beginning of 2017) as well as two completed projects. There were several findings of general interest:

• Success factors for projects include secure funding, encouragement from owners, collaboration between stakeholders (e.g., industry, academia, and research organizations), and good communication with locals and other stakeholders.

• Factors leading to a project stopping include reaching specified targets or goals, and lack of sufficient funds to continue.

Mr. Eide also stated that the survey did not ask why a project sought CSLF recognition, or what benefits that project sponsors expect from CSLF recognition. After ensuing discussion, there was consensus that the survey form be amended to ask for this information. Project sponsors who were present at the meeting were queried as to the overall value of CSLF recognition and responses indicated that increased project visibility and opportunities to network with other project sponsors made it worth the effort to seek CSLF recognition. In particular, the opportunity to participate in CSLF workshops was seen to be a tangible benefit.

11. Open Discussion on Possible New Technical Group Activities The CSLF Technical Group Chair, Åse Slagtern, made a short presentation that summarized existing Technical Group activities and possible new ones in advance of a more detailed discussion during the next day’s full Technical Group Meeting. There are currently four active task forces besides the PIRT: Improved Pore Space Utilization (co-chaired by Australia and the United Kingdom), Bioenergy with CCS (chaired by the United States), Offshore CO2-EOR (chaired by Norway), and Industrial CCS (chaired by France). Ms. Slagtern stated that there are at least ten possible future actions, identified by a Technical Group working group back in 2015, but there had not yet been any consensus to form task forces around these possible actions.

Ensuing discussion led to a few new ideas. Max Watson proposed that previous Technical Group task force final reports be revisited to see if updates are warranted. In that regard, Harry Schreurs suggested that the Technical Group take another look at non-EOR applications might be worthwhile, as there are activities of that nature underway in several CSLF member countries. Ms. Slagtern stated that at the next day’s Technical Group meeting, she would recommend at a new working group be formed to review the findings of the 2015 working group and possibly suggest new actions.

12. General Discussion and New Business

There was no new business offered or further discussion on any topic.

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13. Adjourn

Mr. Barrett thanked the attendees for their interactive participation, expressed his appreciation to the host United Arab Emirates Ministry of Energy, and adjourned the meeting.

Summary of Meeting Outcomes • The PIRT has recommended approval by the Technical Group for the Al Reyadah

CCUS Project, the Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact, and the National Risk Assessment Partnership.

• The mostly-final draft of the 2017 TRM has been sent to all CSLF delegations, with a firm deadline of July 1st for receiving comments. A finalized version will be completed and sent to the CSLF Secretariat by September 15th and a publication-ready version will then be prepared for publication and inclusion in Ministerial Meeting briefing documents.

• The PIRT’s projects engagement initiative has produced useful information, but the CSLF still needs to ramp up its efforts in this area.

Actions

• The PIRT Chair and the CSLF Secretariat will review the CSLF and PIRT Terms of Reference documents to clarify project qualifications for CSLF recognition and to present recommendations at the next PIRT meeting.

• The CSLF Secretariat will revise the Project Engagement survey form to include questions asking why the project sought CSLF recognition, or what benefits that project sponsors expect from CSLF recognition.

PROJECTS INTERACTION AND REVIEW TEAM

Recommended Revisions to PIRT Terms of Reference

Background At the May 2017 CSLF Mid-Year Meeting in Abu Dhabi, the CSLF Policy Group requested that the CSLF Technical Group and the CSLF Communications Task Force review and update procedures for CSLF project recognition procedures. The issue was that project recognition is described in both the CSLF Terms of Reference and the PIRT Terms of Reference, and the language in these documents does not agree with each other.

In the months following the 2017 Mid-Year Meeting, a working group consisting of the Technical Group Chair and Vice Chairs, PIRT Chair, Communications Task Force Chair, and CSLF Secretariat extensively reviewed both Terms of Reference documents and recommended changes which fall into three categories: (a) updating project recognition procedures; (b) consistency with the CSLF Charter; and (c) other miscellaneous corrections and updates.

This paper, prepared by the CSLF Secretariat, is an annotated draft of the proposed revisions to the PIRT Terms of Reference, and incorporates changes recommended by the working group. Deletions are shown as strikethrough text and insertions are shown as underlined text. Annotations describing these proposed changes are shown in [[bracketed italicized text]]. Action Requested The PIRT is requested to review the annotated document.

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CSLF Projects Interaction and Review Team Background One of the main instruments to help the CSLF achieve its goals is through the recognition of CSLF projects. Learnings from CSLF-recognized projects are key elements to knowledge sharing which will ultimately assist in the acceleration of the deployment of carbon capture, utilization and storage (CCUS) technologies. It is therefore of major importance to have appropriate mechanisms within the CSLF for the recognition, assessment and dissemination of projects and their results for the benefit of the CSLF and its Members. To meet this need the CSLF has created an advisory body, the PIRT, which reports to the CSLF Technical Group. [[ The change from “CCS” to “CCUS” (in this section and in other sections below) is recommended to be consistent with the CSLF Charter, which uses that terminology. The change from “CSLF projects” to “CSLF-recognized projects” (in this section and in other sections below) is recommended to clarify that the PIRT will mainly be engaging projects that have gone through the CSLF project recognition process. ]] PIRT Functions The PIRT has the following functions:

• Assess projects proposed for recognition by the CSLF in accordance with the project selection criteria developed by the PIRT. Based on this assessment make recommendations to the Technical Group on whether a project should be accepted for recognition by the CSLF.

• Review the CSLF project portfolio of recognized projects and identify synergies, complementarities and gaps, providing feedback to the Technical Group

• Provide input for further revisions of the CSLF Technology Roadmap (TRM) and respond to the recommended priority actions identified in the TRM.

• Identify where it would be appropriate to have CSLF-recognized projects. • Foster enhanced international collaboration for CSLF-recognized projects. • Ensure a framework for periodically reporting to the Technical Group on the progress

within CSLF projects. • Organize periodic events to facilitate the exchange of experience and views on issues

of common interest among CSLF projects and provide feedback to the CSLF. • Manage technical knowledge sharing activities with other organizations and with

CSLF-recognized projects. • Perform other tasks which may be assigned to it by the CSLF Technical Group. • Provide input for further revisions of the CSLF Technology Roadmap (TRM) and

respond to the recommended priority actions identified in the TRM.

Proposed revisions

Terms of Reference

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[[ The change in the ordering of the bullets in this section is recommended to draw greater attention to the PIRT’s responsibility for the TRM. Previously, that bullet was less noticeable in the middle of the listing of PIRT functions.

Other changes in this section are recommended for greater clarity/consistency and to fix a grammatical error. ]] Membership of the PIRT The PIRT consists of:

• A core group of Active Members comprising Delegates to the Technical Group, or as nominated by a CSLF Member country. Active Members will be required to participate in the operation of the PIRT.

• An ad-hoc group of Stakeholders comprising representatives from CSLF recognized projects. (note: per Section 3.2 (e) of the CSLF Terms of Reference and Procedures, the Technical Group may designate resource persons)

The PIRT chair will rotate on an ad hoc basis and be approved by the Technical Group. Projects for CSLF Recognition All projects proposed for recognition by the CSLF shall be evaluated via a CSLF Project Submission Form. The CSLF Project Submission Form shall request from project sponsors the type and quantity of information that will allow the project to be adequately evaluated by the PIRT. The PIRT has the responsibility of keeping the Project Submission Form updated in terms of information being requested from project sponsors. Additionally:

• CCS Projects seeking CSLF recognition will be considered on their technical merit. • Projects for consideration proposed for CSLF recognition must contribute to the

overall CSLF goal to “accelerate the research, development, demonstration, and commercial deployment of improved cost-effective technologies for the separation and capture of carbon dioxide for its transport and long-term safe storage or utilization”.

o There is no restriction on project type to be recognized as long as the project meets the criteria listed below.

o Learnings from similar projects through time will demonstrate progress in CCUS.

• Proposals Projects proposed for CSLF recognition will must meet at least one of the following criteria.

o An integrated CCUS project with a capture, storage, and verification component and a transport mechanism for CO2.

o Demonstration at pilot- or commercial-scale of new or new applications of technologies in at least one part of the CCUS chain.

o Demonstration of safe geological storage of CO2 at pilot- or commercial-scale. o Demonstration of a toolkit which accelerates the demonstration and/or

deployment of CCUS. [[ The recommended addition of the preamble paragraph is a transfer of text from Section 4.1 of the CSLF Terms of Reference (first two sentences) and addition of a new (third) sentence which reflects the current practice of the PIRT in maintaining the Project Submission Form. This text more properly belongs in the PIRT Terms of Reference than in the CSLF Terms of Reference.

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The addition of the “toolkit” sub-bullet is recommended so that important “toolkit” projects such as the recently-recognized CCSI/CCSI2 and NRAP are not disqualified from consideration for CSLF recognition.

Other changes in this section are recommended for greater clarity/consistency. ]] Operation and Procedures of the PIRT

• The PIRT will establish its operational procedures. The PIRT will coordinate with the Technical Group on the agenda and timing of its meetings.

• The PIRT should meet as necessary, often before Technical Group meetings, and use electronic communications wherever possible.

• The TRM will provide guidance for the continuing work program of the PIRT.

Project Recognition • Completed Project proposals Submission Forms should shall be circulated to Active

Members by the CSLF Secretariat. • No later than ten days prior to PIRT meetings, Members are asked to submit a free-

text comment, either supporting or identifying issues for discussion on each any project nominated proposed for CSLF recognition.

• At PIRT meetings or via proxy through the PIRT Chair, individual country representatives will be required to comment on projects nominated proposed for CSLF recognition.

• Recommendations of the PIRT should be reached by consensus with one vote per member country only.

Information Update and Workshops • The PIRT shall define a process for interaction with CSLF-recognized projects

which includes and describes benefits of project recognition to the project sponsor as well as the CSLF. Project updates will be requested by the Secretariat annually engagement will be done by the PIRT every two years, or in years where there is a Ministerial Meeting; the PIRT will assist in ensuring information is sent to the Secretariat.

• The PIRT will assist in facilitating facilitate workshops based on technical themes as required.

• As required, the PIRT will draw on external relevant CCUS expertise. [[ The changes in the first bullet of this section are recommended to describe in greater detail how the PIRT will engage CSLF-recognized projects.

The change in the second bullet is recommended to reflect current practice that the PIRT is now assisting the meeting host in developing workshops at CSLF meetings. In recent times the meeting host has assumed prime responsibility for organizing these workshops. ]]

CSLF Background Documents

Prepared by CSLF Secretariat www.cslforum.org

CHARTER FOR THE CARBON SEQUESTRATION LEADERSHIP FORUM (CSLF):

A CARBON CAPTURE AND STORAGE TECHNOLOGY INITIATIVE

The undersigned national governmental entities (collectively the “Members”) set forth the following revised Terms of Reference for the Carbon Sequestration Leadership Forum (CSLF), a framework for international cooperation in research, development demonstration and commercialization for the separation, capture, transportation, utilization and storage of carbon dioxide. The CSLF seeks to realize the promise of carbon capture utilization and storage (CCUS) over the coming decades, ensuring it to be commercially competitive and environmentally safe.

1. Purpose of the CSLF

To accelerate the research, development, demonstration, and commercial deployment of improved cost-effective technologies for the separation and capture of carbon dioxide for its transport and long-term safe storage or utilization; to make these technologies broadly available internationally; and to identify and address wider issues relating to CCUS. This could include promoting the appropriate technical, political, economic and regulatory environments for the research, development, demonstration, and commercial deployment of such technology.

2. Function of the CSLF

The CSLF seeks to:

2.1 Identify key obstacles to achieving improved technological capacity;

2.2 Identify potential areas of multilateral collaborations on carbon separation, capture, utilization, transport and storage technologies;

2.3 Foster collaborative research, development, and demonstration (RD&D) projects reflecting Members’ priorities;

2.4 Identify potential issues relating to the treatment of intellectual property;

2.5 Establish guidelines for the collaborations and reporting of their results;

2.6 Assess regularly the progress of collaborative RD&D projects and make recommendations on the direction of such projects;

2.7 Establish and regularly assess an inventory of the potential RD&D needs and gaps;

2.8 Organize collaboration with the international stakeholder community, including industry, academia, financial institutions, government and non-government organizations; the CSLF is also intended to complement ongoing international cooperation;

2.9 Disseminate information and foster knowledge-sharing, in particular among members’ demonstration projects;

2.10 Build the capacity of Members;

2.11 Conduct such other activities to advance achievement of the CSLF’s purpose as the Members may determine;

Prepared by CSLF Secretariat www.cslforum.org

2.12 Consult with and consider the views and needs of stakeholders in the activities of the CSLF;

2.13 Initiate and support international efforts to explain the value of CCUS, and address issues of public acceptance, legal and market frameworks and promote broad-based adoption of CCUS; and

2.14 Support international efforts to promote RD&D and capacity building projects in developing countries.

3. Organization of the CSLF

3.1 A Policy Group and a Technical Group oversee the management of the CSLF. Unless otherwise determined by consensus of the Members, each Member will make up to two appointments to the Policy Group and up to two appointments to the Technical Group.

3.2 The CSLF operates in a transparent manner. CSLF meetings are open to stakeholders who register for the meeting.

3.3 The Policy Group governs the overall framework and policies of the CSLF, periodically reviews the program of collaborative projects, and provides direction to the Secretariat. The Group should meet at least once a year, at times and places to be determined by its appointed representatives. All decisions of the Group will be made by consensus of the Members.

3.4 The Technical Group reports to the Policy Group. The Technical Group meets as often as necessary to review the progress of collaborative projects, identify promising directions for the research, and make recommendations to the Policy Group on needed actions.

3.5 The CSLF meets at such times and places as determined by the Policy Group. The Technical Group and Task Forces will meet at times that they decide in coordination with the Secretariat.

3.6 The principal coordinator of the CSLF's communications and activities is the CSLF Secretariat. The Secretariat: (1) organizes the meetings of the CSLF and its sub-groups, (2) arranges special activities such as teleconferences and workshops, (3) receives and forwards new membership requests to the Policy Group, (4) coordinates communications with regard to CSLF activities and their status, (5) acts as a clearing house of information for the CSLF, (6) maintains procedures for key functions that are approved by the Policy Group, and (7) performs such other tasks as the Policy Group directs. The focus of the Secretariat is administrative. The Secretariat does not act on matters of substance except as specifically instructed by the Policy Group.

3.7 The Secretariat may, as required, use the services of personnel employed by the Members and made available to the Secretariat. Unless otherwise provided in writing, such personnel are remunerated by their respective employers and will remain subject to their employers' conditions of employment.

3.8 The U.S. Department of Energy acts as the CSLF Secretariat unless otherwise decided by consensus of the Members.

3.9 Each Member individually determines the nature of its participation in the CSLF activities.

4 Membership

4.1 This Charter, which is administrative in nature, does not create any legally binding obligations between or among its Members. Each Member should conduct the activities contemplated by this Charter in accordance with the laws under which it operates and the international instruments to which its government is a party.

4.2 The CSLF is open to other national governmental entities and its membership will be decided by the Policy Group.

Prepared by CSLF Secretariat www.cslforum.org

4.3 Technical and other experts from within and without CSLF Member organizations may participate in RD&D projects conducted under the auspices of the CSLF. These projects may be initiated either by the Policy Group or the Technical Group.

5 Funding

Unless otherwise determined by the Members, any costs arising from the activities contemplated by this Charter are to be borne by the Member that incurs them. Each Member's participation in CSLF activities is subject to the availability of funds, personnel and other resources.

6 Open Research and Intellectual Property

6.1 To the extent practicable, the RD&D fostered by the CSLF should be open and nonproprietary.

6.2 The protection and allocation of intellectual property, and the treatment of proprietary information, generated in RD&D collaborations under CSLF auspices should be defined by written implementing arrangements between the participants therein.

7. Commencement, Modification, Withdrawal, and Discontinuation

7.1 Commencement and Modification

7.1.1 Activities under this Charter may commence on June 25, 2003. The Members may, by unanimous consent, discontinue activities under this Charter by written arrangement at any time.

7.1.2 This Charter may be modified in writing at any time by unanimous consent of all Members.

7.2 Withdrawal and Discontinuation

A Member may withdraw from membership in the CSLF by giving 90 days advance written notice to the Secretariat.

8. Counterparts

This Charter may be signed in counterpart.

Table of Contents EXECUTIVE SUMMARY ........................................................................................................................................ 1

Key Findings ..................................................................................................................................................... 1

Priority Recommendations ............................................................................................................................. 2

1. INTRODUCTION ....................................................................................................................................... 5 1.1. Objective and audience .......................................................................................................................... 5

1.2. Background ............................................................................................................................................. 5

1.3. Terminology ............................................................................................................................................ 5

1.4. Major differences between 2013 and 2017 roadmaps ......................................................................... 6 2. THE IMPORTANCE OF DEPLOYING CCS .............................................................................................. 7

2.1. The need to reduce CO2 emissions....................................................................................................... 7

2.2. The importance of CCS, the industrial sector, and negative emissions ........................................... 7

2.3. The urgency to increase the pace in deploying CCS .......................................................................... 8

2.4. Nontechnical measures needed to accelerate the pace of CCS deployment ................................... 9

3. TECHNOLOGY NEEDS .......................................................................................................................... 12 3.1. Capture ..................................................................................................................................................... 12

3.1.1. Power ........................................................................................................................................................................................ 12 3.1.2. Industry .................................................................................................................................................................................... 12 3.1.3. Bio-CCS...................................................................................................................................................................................... 13 3.1.4. Hydrogen as a mechanism to decarbonize industries ......................................................................................... 14 3.1.5. Addressing technology needs ......................................................................................................................................... 15 3.1.6. Recommendations for CO2 capture .............................................................................................................................. 17

3.2. CO2 infrastructure ................................................................................................................................... 18

3.2.1. Transport ................................................................................................................................................................................. 18 3.2.2. Hubs and clusters ................................................................................................................................................................. 19 3.2.3. Recommendations for CO2 transport and infrastructure................................................................................... 21

3.3. Storage ..................................................................................................................................................... 21

3.3.1. Identified technology needs ............................................................................................................................................ 23 3.3.2. Recommendations for CO2 storage .............................................................................................................................. 24

3.4. CO2 utilization, including enhanced hydrocarbon recovery .............................................................. 26

3.4.1. Identified technology needs ............................................................................................................................................ 27 3.4.2. Recommendations for CO2 utilization......................................................................................................................... 28

4. SUMMARY .............................................................................................................................................. 29 5. PRIORITY ACTIONS RECOMMENDED FOR IMPLEMENTATION BY POLICYMAKERS .................. 30 6. FOLLOW-UP PLANS .............................................................................................................................. 31 7. ACKNOWLEDGEMENTS ....................................................................................................................... 32 ANNEX A. ABBREVIATIONS AND ACRONYMS ......................................................................................... 33 ANNEX B. SUMMARY OF TECHNICAL RECOMMENDATIONS ................................................................. 34 ANNEX C. REFERENCES .............................................................................................................................. 38

CSLF Technology Roadmap 2017 www.cslforum.org

Executive Summary The Carbon Sequestration Leadership Forum (CSLF) Technology Roadmap 2017 aims to provide recommendations to Ministers of the CSLF member countries on technology developments that are required for carbon capture and storage (CCS1) to fulfill the CSLF mission to facilitate the development and deployment of CCS technologies via collaborative efforts that address key technical, economic, and environmental obstacles.

With the release of this technology roadmap, the CSLF aspires to play an important role in reaching the targets set in the Paris Agreement by accelerating commercial deployment and to set key priorities for research, development, and demonstration (RD&D) of improved and cost-effective technologies for the separation and capture of carbon dioxide (CO2); its transport; and its long-term safe storage or utilization.

Key Findings

Analysis by the International Energy Agency Greenhouse Gas R&D Programme (IEAGHG 2017a) shows that if sufficiently strong incentives for a technology are established, the rate of build-out historically observed in industry analogues (power sector, oil and gas exploration and production, pipeline transport of natural gas, and ship transport of liquefied natural gas) has been comparable to the rates needed to achieve the 2°C Scenario (2DS) for CCS.2 Reaching the beyond 2°C Scenario (B2DS) target will be significantly more challenging. Substantial investment in new CCS facilities from both the public and the private sectors is essential to achieve the required build-out rates over the

1 In this Technology Roadmap carbon caprure, utilization and stoarge (CCUS) is consdiered as subset of CCS 2 The International Energy Agency, in Energy Technology Perspectives 2017 (IEA 2017a), explores the potential of

technologies to push emissions to a 2°C level, referred to as the 2°C Scenario (2DS), and below the level associated with a 2°C limit, referred to as the Beyond 2°C Scenario (B2DS). B2DS charts a trajectory for the energy sector resulting in a 50% chance of limiting the rise in temperature to 1.75°C.

Based on reviews of several status reports on CCS and technical papers, as well as comments and input from international experts, the main findings of this Technology Roadmap 2017 are as follows:

CCS has been proven to work and has been implemented in the power and industrial sectors.

The coming years are critical for large-scale deployment of CCS; therefore, a sense of urgency must be built to drive action.

Substantial, and perhaps unprecedented, investment in CCS and other low-carbon technologies is needed to achieve the targets of the Paris Agreement.

The main barriers to implementation are inadequate government investment and policy support/incentives, challenging project economics, and uncertainties and risk that stifle private sector investment.

Rapid deployment of CCS is critical in the industry and power sectors in both Organisation for Economic Co-operation and Development (OECD) and non-OECD countries, especially in those industries for which CCS is the most realistic path to decarbonization.

Negative CO2 emissions can be achieved by using a combination of biomass and CCS. Costs and implementation risks can be reduced by developing industrial clusters and CO2

transport and storage hubs. Members of the CSLF consider it critical that public-private partnerships facilitate material

and timely cost reductions and accelerated implementation of CCS.

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coming decades. Governments need to establish market incentives and a stable policy commitment and to provide leadership to build public support for actions such as the following:

A rapid increase of the demonstration of all the links in the CCS chain. Extensive support and efforts to build and operate new plants in power generation and industry. Facilitation of the exchange of data and experiences, particularly from existing large-scale

plants with CCS. Support for continued and comprehensive RD&D. Facilitation of industrial clusters and CO2 transport and storage hubs.

Priority Recommendations

CCS is a key technology to reduce CO2 emissions across various sectors of the economy while providing other societal benefits (energy security and access, air pollution reduction, grid stability, and jobs preservation and creation). Policy frameworks for CCS need to include equitable levels of consideration, recognition, and support for CCS on similar entry terms as other low-carbon technologies and reduce commercial risks. To support the deployment of CCS, it is critical to facilitate innovative business models for CCS by creating an enabling market environment. Fit-for-purpose and comprehensive legal and regulatory frameworks for CCS are needed on a regional scale (e.g., the London Protocol to provide for offshore cross-border movement of CO2). Strategic power and industrial CO2 capture hubs and clusters, with CO2 transportation and storage infrastructure, including early mapping matching sources to sinks and identification and characterization of potential storage sites, will also be needed. CCS stakeholder engagement remains critical to implementation and is aimed at building trust, addressing misconceptions, and supporting educators and community proponents of CCS projects, while improving the quality of communication.

Governments and industries must collaborate to ensure that CCS contributes its share to the Paris Agreement’s aim to keep the global temperature increase from anthropogenic CO2 emissions to 2°C or below by implementing sufficient large-scale projects in the power and industry sectors to achieve the following:1

Long-term isolation from the atmosphere of at least 400 megatonnes (Mt) CO2 per year by 2025 (or permanent capture and storage of in total 1,800 Mt CO2).

Long-term isolation from the atmosphere of at least 2,400 Mt CO2 per year by 2035 (or permanent capture and storage of in total 16,000 Mt CO2).

To this end, CSLF members recommend the following actions to the CSLF Ministers:

• Promote the value of CCS in achieving domestic energy goals and global climate goals. • Incentivize investments in CCS by developing and implementing policy frameworks. • Facilitate innovative business models for CCS projects. • Implement legal and regulatory frameworks for CCS. • Facilitate CCS infrastructure development. • Build trust and engage stakeholders through CCS public outreach and education. • Leverage existing large-scale projects to promote knowledge-exchange opportunities. • Drive costs down along the whole CCS chain through RD&D. • Accelerate CCS in developing countries by funding storage appraisals and technology

readiness assessments. • Facilitate implementation of CO2 utilization.

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RD&D for novel and emerging technologies is required along the whole CCS chain, as shown by the Mission Innovation workshop on Carbon Capture, Utilization, and Storage held in September 2017. The same holds for knowledge sharing. These efforts should be targeted to provide the exchange of design, construction, and operational data, lessons learned, and best practices from existing large-scale projects. The sharing of best practices continues to be of highest value and importance to driving CCS forward while bringing costs down. CO2 utilization can be facilitated by mapping opportunities; conducting technology readiness assessments; and resolving the main barriers for technologies, including life cycle assessments and CO2 and energy balances.

Governments have a critical role in accelerating the deployment of CCS.

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1. Introduction

1.1. Objective and audience The objective of the Carbon Sequestration Leadership Forum (CSLF) Technology Roadmap 2017 is to provide recommendations to Ministers of the CSLF member countries on technology developments that are required for carbon capture and storage (CCS) to fulfill the CSLF mission to facilitate the development and deployment of CCS technologies via collaborative efforts that address key technical, economic, and environmental obstacles.

The recommendations in this roadmap are directed to CSLF Ministers and their climate and energy policymakers. The CSLF Technical Group has proposed this roadmap for the CSLF Policy Group to consider as formal input into the 2017 communiqué of the biennial CSLF Ministerial meeting.

With the release of this technology roadmap, the CSLF aspires to play an important role in reaching the targets set in the Paris Agreement by accelerating commercial deployment and to set out key priorities for research, development, and demonstration (RD&D) of improved and cost-effective technologies for the separation and capture of carbon dioxide (CO2), its transport, and its long-term safe storage or utilization.

1.2. Background The International Energy Agency (2016a, b) and the Global Carbon Capture and Storage Institute (2015a, 2016a) state that CCS can significantly contribute to the achievement of Paris Agreement targets adopted at the 21st Conference of the Parties in December 2015: “Holding the increase in the global average temperature to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change” (UNFCCC 2015). The importance of CCS to mitigate the global economic cost of achieving a 2°C goal was highlighted by the Intergovernmental Panel on Climate Change (IPCC 2014), which found that achieving an atmospheric concentration of 450 parts per million (ppm) CO2 without CCS is more costly than for any other low-carbon technology, by an average of 138%. Further, only four of 11 models that included CCS as an optional mitigation measure could produce scenarios that successfully reached the targeted concentration of 450 ppm without CCS, emphasizing that CCS is an important low-carbon energy technology.

1.3. Terminology For the purpose of this document, the following definitions apply:

The term carbon capture and storage (CCS) is used when CO2 is captured from its source of production and transported to a geologic storage site for long-term isolation from the atmosphere.

The term carbon capture, utilization, and storage (CCUS) is used when all or part of the CO2 is used before all is being geologically stored for long-term isolation from the atmosphere . This may include instances in which CO2 is used to enhance the production of hydrocarbon resources (such as CO2-enhanced oil recovery) or in the formation of minerals or long-lived compounds from CO2, thereby permanently isolating the CO2 from entering the atmosphere.

Carbon capture and utilization (CCU) is used when the CO2 is stored only temporarily. This includes applications in which CO2 is reused or used only once while generating some additional benefit. Examples are urea and algal fuel formation or greenhouse utilization.

CCUS is a subset of CCS, and only the term CCS will be used in this document, except in section 3.4.

For a CO2-usage technology to qualify for reduction of CO2 emissions (e.g., in trading and credit schemes), it should be required that a net amount of CO2 is eventually securely and permanently prevented from re-entering the atmosphere. It is likely that CCUS and CCU will have limited contributions to the mitigation challenge, of the order of 4%–8% for CO2-enhanced oil recovery (CO2-EOR) and 1% for chemical conversion of CO2 (Mac Dowell et al. 2017). Therefore, CCU and particularly CCUS in the form of CO2-EOR may be seen as a means of securing financial support for

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the early deployment of CCS in the absence of sufficient carbon prices or other incentives to deploy CCS, thus helping accelerate technology deployment (Mac Dowell et al. 2017). For example, if CO2 from a slipstream of flue gas is used for utilization, this may contribute to reducing the cost of CO2

capture, thus acting as a driver for the development of capture projects and transport and storage infrastructure. CCU can contribute to reduced CO2 emissions if the CO2 replaces new, fresh hydrocarbons as a source for carbon. In such circumstances the total carbon footprint, including energy requirements for the conversion process, must be documented (e.g., through a full life cycle analysis).

If the goals of the Paris Agreement are to be met, the scale of deployment would require the greater parts of CO2 to be geologically stored, through CCS.

1.4. Major differences between 2013 and 2017 roadmaps The major change in the Technology Roadmap 2017 is new time horizons for medium- and long-term recommendations and targets: 2025 and 2035, compared with 2030 and 2050. The change emphasizes that the CSLF Technical Group recognizes a need for accelerated implementation of CCS.

Other changes are mainly found in section 3.1. and section 3.2. In the chapter on capture, explanations relating to technology types, which are described in referenced documents, have been kept to a minimum. There is a renewed emphasis on CCS applied to industrial processes, including hydrogen production and biomass, as well as on learnings from large-scale projects. The section on transport and infrastructure has been expanded, with an emphasis on the development of industrial clusters and storage hubs.

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2. The Importance of Deploying CCS

2.1. The need to reduce CO2 emissions In 2014 total energy-related direct global emissions of CO2 amounted to approximately 34,200 megatonnes (Mt), of which 8,300 Mt CO2/year were direct emissions from industry and 13,600 Mt CO2/year were direct emissions from the power sector (IEA 2017a).3

To reach the Paris Agreement’s 2°C target, the International Energy Agency (IEA) estimates that global CO2 emissions must be reduced to just below 9,000 Mt CO2/year by 2060, a reduction of more than 60% compared to 2014, and must fall to net zero by no later than 2100 (IEA 2017a). In the Beyond 2°C Scenario (B2DS), the power sector reaches net negative emissions after 2045, and the whole energy sector reaches net zero in 2060. In B2DS, CCS is critical in reducing emissions from the power and industrial sectors and delivering negative emissions when combined with bioenergy. Reaching the significantly more ambitious vision of the Paris Agreement 1.5°C target would require faster and deeper CO2 emissions reductions across both the energy supply and demand sectors.

2.2. The importance of CCS, the industrial sector, and negative emissions In the IEA 2°C Scenario (2DS), CCS will account for 14% of the accumulated reduction of CO2 emissions by 2060 and 32% of the reduction needed to go from 2DS to B2DS by 2060 (IEA 2017a). Major cuts must be made in all sectors in addition to the power sector. The industrial sector will have to capture and store 1,600 Mt CO2/year in the 2DS and 3,800 Mt CO2/year in the B2DS by 2060, yet the sector is still the largest contributor to accumulated CO2 emissions to 2060 and the major CO2 source in 2060. CCS is already happening in industries such as natural gas processing, fertilizer production, bioethanol production, hydrogen production, coal gasification, and iron and steel production (GCCSI 2016b). In addition, the demonstration of CO2 capture unit on a waste incineration plant has taken place in Japan (Toshiba 2016), and small-scale testing has taken place in Norway (City of Oslo 2016). In 2060, CCS is expected to make up 38% of total emissions reductions in industry between the Reference Technology Scenario (RTS) and B2DS, and somewhat less than half this amount between RTS and 2DS (IEA 2017a), showing that CCS will be a critical technology for many emissions-intensive industries.

There is a high likelihood that the 2DS and, in particular, the B2DS, cannot be achieved without the deployment of “negative emissions technologies” at scale (IPCC 2014; IEA 2017a). There are several technologies that have the potential to contribute to the reduction of atmospheric CO2 levels; each of these, however, brings its own uncertainties, challenges, and opportunities. Included among them are

3 Total greenhouse gas emissions were significantly higher, at approximately 49 gigatonnes CO2 equivalent in 2010 (IPCC 2014).

Emissions Reduction Scenarios

Energy Technology Perspectives 2017 (IEA 2017a) explores the potential of technologies to push emissions to a 2°C level, referred to as the 2°C Scenario (2DS), and below the level associated with a 2°C limit, referred to as the Beyond 2°C Scenario (B2DS). B2DS charts a trajectory for the energy sector resulting in a 50% chance of limiting the rise in temperature to 1.75°C.

The Reference Technology Scenario (RTS) takes into account today’s commitments by countries to limit emissions and improve energy efficiency, including the nationally determined contributions pledged under the Paris Agreement. By factoring in these commitments and recent trends, the RTS already represents a major shift from a historical “business as usual” approach with no meaningful climate policy response. The RTS requires significant changes in policy and technologies in the period to 2060 as well as substantial additional cuts in emissions thereafter. These efforts would result in an average temperature increase of 2.7°C by 2100, at which point temperatures are unlikely to have stabilized and would continue to rise.

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reforestation, afforestation (photosynthesis), direct air capture, and bioenergy coupled with CCS (i.e., CCS applied to the conversion of biomass into final energy products or chemicals). In the B2DS, almost 5,000 Mt CO2 are captured from bioenergy, resulting in negative emissions in 2060 (IEA 2017a).

2.3. The urgency to increase the pace in deploying CCS In 2012 the IEA expressed the view that “development and deployment of CCS is seriously off pace” (IEA 2012). Despite the fact that several large-scale CCS projects have come into operation since 2012 (see GCCSI 2015a, 2016a; IEA 2016b; and section 3) and that the IEA’s estimated contribution from CCS by 2050 is 14% of the accumulated global abatement needed by 2060, the IEA (2016a, 2017a) strongly calls for increased efforts in implementing CCS: “An evolution in the policy approach to deploying CCS, as well as an increase in public-sector commitment, will be needed to reach ambitious climate targets such as those behind the 2DS and B2DS. Deploying CCS at the pace and scale envisaged in the 2DS and the B2DS requires targeted support for the different elements of the CCS chain and responses to the commercial, financial and technical challenges. Governments can encourage the uptake of CCS and leverage private investment by recognizing and supporting CO2 transport and storage as common user infrastructure, critical to a low-carbon economy” (IEA 2017a).

The IEA is supported by the Global Carbon Capture and Storage Institute (GCCSI), which in its 2015 report on the global status of CCS (2015a) finds that “While CCS has made great progress this decade, it is abundantly clear that we must sharply accelerate its deployment.” Key findings of the 2015 report may be summarized as follows: CCS is vital to meet climate goals. Only CCS can reduce direct CO2 emissions from industry at scale. CCS has proved operational viability. CO2 storage capabilities are demonstrated. CO2 storage resources are significant. CCS costs will have to come down from 2016 levels. Excluding CCS will double the cost of mitigation.

Four international organizations have underlined the need for clear messages on CCS deployment to the CSLF ministers:

Plans submitted by Mission Innovation members show that 19 of its 23 members (including the European Commission) list CCS as a focus area for clean energy research and development (Mission Innovation 2017).4 A workshop organized by Mission Innovation identified priority research needs for CO2 capture, storage, and utilization (Mission Innovation 2018).

The World Resources Institute supported widespread implementation of CCS (WRI 2016). The Oil and Gas Climate Initiative announced one billion US dollars in funding for climate

investments over a 10-year period (OGCI 2016), of which a significant proportion of this fund will be available for CCS projects (CCSA 2016).

The Clean Energy Ministerial at its 8th meeting in Beijing, China, in June 2017 underlined the need for clear messages on CCS deployment (IEA 2017b).

The challenge can be illustrated by the fact that large-scale CCS projects in operation and or under construction in 2017 have a CO2 capture capacity of about 40 Mt CO2/year (GCCSI 2016a), whereas the required targets set by the IEA (2017a) for the 2DS and the B2DS are much higher (figure 2.1). The figure shows that the total captured and stored CO2 will have to reach approximately 1,800 Mt CO2 by 2025 and 16,000 Mt CO2 by 2035 for the 2DS to be delivered. For the B2DS, the 2025 target is 3,800 Mt CO2 and the 2035 target is almost 26,000 Mt CO2.

4 At the 21st Conference of the Parties, held in Paris, France, in December 2015, 20 countries plus the European Union joined Mission Innovation and pledged to double clean energy research and development funding in 5 years.

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Figure 2.1. CO2 captured and stored per year to achieve the 2°C Scenario (left panel) and Beyond 2°C Scenario (right panel), in 1,000 Mt CO2/year (after IEA 2017a).

Capturing and storing 420 Mt CO2/year by 2025 requires a considerable acceleration of deployment of CCS projects. In order for large-scale CCS deployment to take place, it is necessary to move from project-by-project thinking to systems thinking. Although the momentum for deploying CCS has slowed, and renewed national commitments and strengthened policy settings will be essential, it may still be possible to achieve the deployment needed. A review by the International Energy Agency Greenhouse Gas R&D Programme (IEAGHG 2017a) finds that the rate of build-out in industry analogues has been comparable to the rates now needed for CCS in the 2DS. The study shows that, if sufficiently strong incentives for a technology are established, industry has historically achieved the rapid build-out rates required for the projected scale of deployment. Although the analogues have limitations, the study shows that it may be technically feasible to realize the anticipated CCS build-out rates. However, substantial and perhaps unprecedented efforts from both the public and the private sectors will be required to deliver and maintain the anticipated CCS build-out rates over the coming decades. These efforts will include market incentives, stable policy commitment, government leadership, and public support. Achieving the B2DS will be significantly more challenging.

Thus, CCS will be needed in many sectors if the Paris Agreement targets are to be achieved, and more needs to be done to accelerate CCS at the pace needed to meet these ambitions. The CSLF Technical Group considers that some reasons for the slow implementation of CCS include the following:

The complexity of large integrated CCS projects. Insufficient financial support for commercial-scale deployment. A lack of business cases and models. High comparative costs under weak national levels of carbon constraints. Localized opposition stakeholder challenges, limited knowledge, and support of the technology.

2.4. Nontechnical measures needed to accelerate the pace of CCS deployment The CSLF mission clearly expresses a commitment to facilitate CCS as a tool to combat climate change. Technical as well as nontechnical measures are required to accelerate the deployment of CCS as a mitigation tool for global warming. Pure policy measures are not part of this technology roadmap, but there is not always a clear distinction between policy and technical measures. The combined policy/technical measures include but are not limited to the following:

Demonstrate the value proposition of CCS as a key technology to reduce CO2 emissions across various sectors of the economy while providing other societal benefits (energy security; access;

Scenario 2025 2030 2035 2040 2045 2050 2055 2060 2DS 0.42 1.16 2.41 3.79 5.01 5.43 5.83 6.65 B2DS 0.91 2.00 3.62 5.74 7.52 8.42 9.71 10.94

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and additional environmental benefits, such as air pollution reduction, grid stability, and jobs preservation and creation).

Develop policy frameworks that incentivize investment in CCS and reduce commercial risks. Identify and create markets that can support a business case for CCS investment. Implement fit-for-purpose legal and regulatory frameworks in key regions where CCS is required

to be developed, including frameworks to allow CO2 transport and storage across marine borders (the London Protocol for cross-border movement of CO2).

Develop strategic hubs, including mapping matching sources and sinks of CO2, transportation, and storage infrastructure.

Accelerate social engagement by enhancing CCS public outreach and education to build trust, reduce and tackle misconceptions, and support educators as well as community proponents of CCS projects (see also GCCSI 2016a).

The Carbon Capture and Storage Association has also identified other nontechnical steps to support the implementation of CCS (CCSA 2013). Although written for the United Kingdom, the steps have international relevance.

For bio-CCS, nontechnical issues that fall outside the scope of this technology roadmap include the following:

Greenhouse gas reporting frameworks and emissions pricing schemes do not account for negative emissions in several, if not most, jurisdictions.

There is a significant span in the estimates of the potential scale of bio-CCS, resulting from a limited understanding of the implications of, and interactions between, water and land use, food production, total energy use and greenhouse gas emissions, the climate system, and biodiversity and ecosystems.

Health and social implications, particularly in relation to other emissions and discharges, like particulate matter, may lead to increased negative impacts unless precautions are taken (Kemper 2015).

Stimulating bioenergy stakeholders to consider CCS in the sector, through targeted incentives and a nonpenalizing accounting methodology.

Since the CSLF Technology Roadmap 2013, there have been developments in the application of regulations in terms of projects applying for permits, and in reviews of regulation such as the European Union CCS Directive. Such activities are most useful to test the regulatory regimes. Storage permits have been successfully awarded to projects in the United States, Canada, Japan, the Netherlands, Norway, and the United Kingdom. The European Union CCS Directive was reviewed in 2014 and found fit for purpose, so no amendments were made.

A major development not covered in the CSLF Technology Roadmap 2013 was the adoption by the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) of CCS as an eligible project-level activity in the Clean Development Mechanism (CDM) under the Kyoto Protocol. In 2011 a set of rules specific to CCS were agreed on, to allow CCS projects located in developing countries to generate tradable carbon offsets for developed country Parties to use against their emissions reduction commitments under the Kyoto Protocol. It is widely anticipated that future mechanisms developed under the UNFCCC for developing countries will follow the principles established by these CCS CDM rules (modalities and procedures).

Despite these positive developments, there is still much work to do. Many countries that have expressed an interest in using CCS to reduce emissions have yet to develop regulatory frameworks, while in others, regulatory frameworks remain untested.

One opportunity, as highlighted in the United States, is the replacement of natural CO2 with CO2

captured from power or industrial plants to enhance oil production (CO2-EOR), resulting in net CO2 storage outcomes. Projects employing CO2-EOR, particularly in the United States, Canada, and the Middle East, are operating under existing hydrocarbon legal and regulatory regimes and not regimes specifically designed for CO2 storage. Should these projects wish to be recognized for storing CO2, transitional regulatory arrangements will need to be considered to require operators to address

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storage-focused performance objectives. The International Organization for Standardization (ISO) Technical Committee on CCS (TC 265), which was approved by the members in 2011 and started its work in 2012, is working on this issue.

Similarly, cross-border offshore projects remain an issue, unless the CO2 is used for enhanced oil recovery (EOR). This includes capturing CO2 in one jurisdiction and/or transporting and storing it in another. For those jurisdictions without suitable offshore storage options, this will be an important issue. The London Protocol has its cross-boundary amendment and guidance in place, but its application into force awaits the slow ratification of the export amendment.

Long-term liability continues to be highlighted as an issue of concern to many policymakers, regulators, investors, and project proponents. Some of the legal and regulatory models developed in the past 10 years have established liability rules and compensation mechanisms that address the entire life cycle of a CCS project, including the post-closure period. However, for these frameworks, it remains to be seen whether closure certificates (and the like) can be successfully obtained and owners’ liabilities practically limited (via transfers, indemnifications, and so on).

There is a considerable activity underway in the ISO that could support future development of regulations for the components of the CCS chain. ISO TC 265 has established six working groups, on capture, transport, storage, quantification and verification, cross-cutting issues, and CO2-EOR, with the intent to develop a range of standards. It published an international standard on CO2 transport in 2016, and it is expected to publish an international standard on CO2 geological storage in 2017 and an international standard on CO2-EOR in late 2018.5

5 More information on recent regulatory developments can be found in Dixon, McCoy, and Havercroft (2015).

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3. Technology Needs

3.1. Capture This chapter identifies technology needs for CO2 capture from point sources (for example > 0.1 Mt CO2/year) in the power and industrial sectors. It starts with a brief assessment of the present situation.6 An overview of large-scale CCS projects can be found in the GCCSI database (https://www.globalccsinstitute.com/projects/large-scale-ccs-projects). Below only a few are mentioned.

3.1.1. Power Some power projects have become operational, or are close to being operational, since the issue of the CSLF Technology Roadmap 2013, including Boundary Dam, Canada (post-combustion with absorption; a summary is provided in IEAGHG 2015a) and Petra Nova, United States (power and post-combustion capture with chemical absorption). Also, several demonstration capture plants have been operating for many years, including Plant Barry, United States (power and post-combustion with absorption); Boreyong, Korea (power and post-combustion with solvent absorption); Hadong, Korea (power and post-combustion with solid sorbent adsorption); and Huaneng Greengen, China (power with integrated gasification combined cycle pre-combustion capture). Dedicated test facilities for the capture of CO2 have been established in Australia, Canada, China, Norway, the United Kingdom, France, Spain, and the United States, for example. The scale of these is generally up to 20–30 megawatts (MW), or a capture capacity up to the of order of one hundred thousand tonnes of CO2/year. Most are based on post-combustion and oxy-combustion technologies.

3.1.2. Industry There are several industrial plants where CO2 is captured, in almost all as part of the commercial process (GCCSI 2016b). These are found in natural gas sweetening, refineries, fertilizer production, iron and steel production, and coal gasification. Several such plants have implemented CCS, including full-scale industry projects such as Quest (Shell Canada; hydrogen production, solvent-based absorption); the Air Products Port Arthur CCS project (hydrogen and CO2 production with pressure swing adsorption and vacuum swing adsorption, respectively); and the Emirates Steel Industry (United Arab Emirates; amine-based CO2 capture from the direct reduced iron process). In Japan, CCS on the Tomakomai refinery (GCCSI 2016d) and the first application of CO2 capture to waste incineration (Toshiba 2016) both started in spring 2016. There are also activities for the application of CCS in the petrochemical industry in China; a cement plant in Taiwan; and concept studies for cement, waste incineration, and fertilizer plants in Norway (MPE 2016; Svalestuen, Bekken, and Eide 2017).

Several studies and reports deal with capture technologies that may be applicable to various industries, their potential to reduce emissions, and the technological as well as other barriers to their implementation.7 Their key findings include the following:

Some currently available technologies, in particular amine solvents, are ready to be applied in early projects in several industries.

Oxy-combustion capture is an early-stage candidate in some industries, although there is limited operational experience.

6 For an extensive review of CO2 capture technologies in the power and industrial sectors, see for example the International Journal of Greenhouse Gas Control, Special Issue 40 (IJGCC 2015), GCCSI (2016c), ISO (2016a), and ZEP (2017a).

7 For example, UNIDO (2010), IEA and UNIDO (2011), ZEP (2013a, 2015, 2017a), ISO (2016a), DECC (2014, 2015), MPE (2016), GCCSI (2016c), IEAGHG (2013a) (iron and steel), IEAGHG (2013b) (cement), IEAGHG (2016a) (pulp and paper), IEAGHG (2017b, 2017c) (hydrogen production), and IEAGHG (2017d) (natural gas production).

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In industrial applications, other technologies might be favored when they allow for better integration with the existing process (e.g., direct calcination technology in cement plants).

Considerable knowledge and experience from the power sector’s development and implementation of CO2 capture technologies can be transferred to a range of industries.

A study performed for the former United Kingdom Department of Energy and Climate Change (DECC 2015) indicated that as much as 36.5% of industrial CO2 emissions in the United Kingdom may be reduced by directly employing CCS. More would be achieved through the use of CCS to decarbonize electricity and gas (e.g., via hydrogen) supplied to industry. In a roadmap towards zero emissions by 2050, the Norwegian process industries indicated that CCS can be responsible for 36% of the required cuts in CO2 emissions, relative to a reference case with robust industrial growth (Norsk Industri 2016).

There are, however, still technology challenges related to the implementation of CCS in energy-intensive industries:

High costs. Levels of uncertainty regarding investments. Environmental impacts as well as health and safety implications regarding waste products and

toxicity. Increased operational complexity and risks (integration, hidden costs of additional downtime,

alternative product supplies, and technology lock-in; these will be site-specific). New applications of existing technologies that are not yet proven at scale. Understanding the impact of different compositions of the feed and/or flue gases compared to

the power sector.

3.1.3. Bio-CCS Biomass absorbs CO2 from the atmosphere as it grows. Net removal of CO2 from the atmosphere, or negative emissions, may be achieved if the CO2 released during conversion of biomass to chemicals or energy products is captured and stored permanently in geological formations, here referred to as bio-CCS. The biomass must be grown in a sustainable manner. The importance of bio-CCS has been highlighted by the Intergovernmental Panel on Climate Change (IPCC 2014). There are currently a number of projects in operation that capture 0.1–0.3 Mt CO2/year, mainly from ethanol plants (Kemper 2015; Ensus 2016; CSLF 2017a). The Illinois Industrial Project, by Archer Daniels Midland Company in the United States, has from April 2017 captured 1 Mt CO2/year. At least three of the projects sell the CO2 for EOR, and one injects the CO2 into a deep saline formation. The others sell the CO2 for use in the greenhouse and food industries.

The scale of operational bio-CCS plants are orders of magnitude less than what will be needed for bio-CCS to become a major contributor to negative CO2 emissions. Estimates of the theoretical potential of bio-CCS to remove CO2 from the atmosphere show significant spread (for example, Kemper 2015; Williamson 2016). The scale will be limited by factors that include available biomass, competition with food production and other uses of land and water, and other end uses of biomass. Potential impacts on biodiversity and ecosystems have also been identified as issues.8

The CSLF (2017a) has provided an overview of bio-CCS, including technology options and pathways. The CO2 from fermentation in the abovementioned ethanol plants is nearly pure (containing a small amount of water) and does not require the separation technologies associated with power and heat generation, and with several industrial processes. For other bio-CCS plants, the CO2 capture technologies are in essence the same as for CCS on power, heat generation, and process industries. Thus, bio-CCS applications may allow for a relatively smooth integration into current energy systems.

8 Kemper (2015) gives a review of the benefits, impacts, and challenges related to bio-CCS; Mander et al. (2017) reflects on the role of bio-CCS in a whole system perspective; and Anderson and Peters (2016) gives a cautious note on the potential.

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Co-combustion of fossil fuels, biomass, and domestic waste is also a bioenergy approach to which CCS can be applied (waste often contains significant levels of biogenic material). Co-combustion can often achieve better conversion efficiencies, economies of scale, and insensitivity to biomass supply variations (e.g., seasonal).

There are, however, some technical challenges related to the biomass combustion/conversion process in general that can lead to increased corrosion, slagging, and fouling (Pourkashanian, Szuhanszki, and Finney 2016) for the capture process. These include, for example, dealing with the high moisture content, diversity, variability, and impurities of biomass. Research into the less mature options, like large-scale biomass gasification, should also be pursued. Other areas where research may be needed include the following:

Further advances in boiler and gasification technologies. Advanced technologies for drying biomass at the recovery site to minimize water transport costs

and heating inefficiencies. Improved understanding of the composition of biomass feedstock and the impacts of impurities,

in particular heavy metals, in the flue gas from biomass combustion on the CO2 capture and compression systems and the scope to remove these impurities from the biomass prior to thermal conversion (Gudka et al. 2016).

Finding the optimal size of capture and/or conversion installations for biomass conversion and combustion.

Investment and operational costs of bio-CCS systems. The impact of biomass, including co-firing with fossil fuels, and aspects such as recirculation of

CO2 and CO2 purification required in oxy-combustion systems. Identifying feedstocks that require limited processing. Ensuring compatibility with existing boiler and pollution control equipment. Reducing the cost of processing equipment costs and associated energy costs.

The specific processes adapted to every biomass source (vegetal, waste, and so on) and use (power and heat, paper, cement, and so on) require a considerable amount of research focusing on the heat integration of the capture unit, which is important for the overall efficiency and cost of capture.

Nontechnical issues with bio-CCS fall outside the scope of this technology roadmap. Some of these were described in section 2.4.

3.1.4. Hydrogen as a mechanism to decarbonize industries Presently, hydrogen is used extensively in industry, mainly in ammonia production and in oil refineries, where it is also used to remove sulfur and other impurities from crude oil and its products (GCCSI 2016b). Hydrogenation is also used in the food and petrochemical industries, among others. There are a few car manufacturers that offer cars running on hydrogen (Honda, n.d.; Hyundai, n.d.; Toyota, n.d.). Further, hydrogen has been assessed as a means to decarbonize cities (Northern Gas Networks 2016).

Globally, hydrogen production in 2017 depends heavily on processing fossil fuels, including natural gas, oil and coal, while at the same time producing CO2 as an unavoidable byproduct. Even if hydrogen is produced by electrolysis and renewable energy, it is likely that some hydrogen will still have to be produced from fossil fuels for sufficiency and stability of supply.

The European Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP) (2017b) investigated the potential of decarbonized hydrogen produced through CCS on natural gas and concluded that the process may decarbonize a number of industries. The cost of decarbonized hydrogen is currently lower than that of electrolysis-derived hydrogen from renewable energy. The technology required exists, and ZEP (2017b) provides an overview of available technologies, as well as of plants in operation. Voldsund, Jordal, and Anantharaman (2016), among others, gives more detailed technology descriptions.

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Thus, there are few, if any, technical barriers to CO2 capture associated with large-scale hydrogen production. However, continued research, development, and innovation for improved and emerging technologies for clean hydrogen production should be encouraged, including the following:

Process intensification: more compact, efficient, and economic solutions, such as membranes and technologies for catalytic reforming of the fuel and separation of hydrogen (H2) and CO2.

Process integration in the co-production of H2 and, for example: Electricity and heat production. In industrial processes where H2 or H2-enriched natural gas can replace fossil fuel-based

feedstock.

A limiting factor to large-scale deployment is that presently there is no large-scale CO2 transport and storage infrastructure in place. ZEP (2017b) also lists a number of nontechnical recommendations, such as identifying policies and support mechanisms, identifying local clusters for synergies, investigating the potential role of clean hydrogen in Europe, and encouraging collaborations.

3.1.5. Addressing technology needs It is important to separate between the capture system as a whole and its components, or the subsystem level. Innovation and improvements at the subsystems/components level from a very low Technology Readiness Level (TRL) can take place long after a complete system has arrived at TRL 9 (Adderley et al. 2016).

Costs for CO2 capture can be reduced through the following:

Applying experiences and learnings from successful as well as unsuccessful projects to support RD&D and further evolving existing CO2 capture technologies.

Supporting RD&D that brings out novel technologies at the subsystem/component level. Combinations between CCS and renewable energy (wind, solar, geothermal, hydropower, or

other renewables) to supply the energy for the capture process.

Learning from experience Cost reductions for CO2 capture are expected to come from knowledge transfer regarding planning, design, manufacturing, integration, operation, and scale-up. The knowledge gained can give important input to achieve reduced capital expenditures and operational expenditures and provide increased confidence for deployment.

Experiences from demonstration and commercial plants may be transferrable to other industries as well as to novel capture technology. Many capture technologies are relevant to a range of applications. A network for knowledge sharing among full-scale facilities (e.g., by expanding the existing International Test Centre Network)9 may help to increase understanding of the scale-up challenge. Such a network would explore knowledge gained and share data and experiences from existing full-scale plants in a systematic way. Knowledge sharing should include experience from the integration of CO2 capture systems in power or industrial plants, in heat integration, environmental campaigns (such as in solvent degradation), aerosol formation, environmental control systems (sulfur oxides, nitrogen oxides, and hydrogen sulfides), experience in part-load operations and daily cycling

9 The International Test Centre Network, established in 2013, has nine members from seven CSLF nations. It is a network that focuses on post-combustion using solvents. The CO2 Technology Centre Mongstad is the largest of the member facilities, whose capacity borders on pilot and demonstration. The other members are smaller but provide useful experience with second-generation post-combustion technologies.

Technology Readiness Level (TRL) describes the maturity of technology. TRL 1 spans concept studies and very basic technology research. TRL 9 usually describes a technology that is tested and qualified for deployment at industrial scale. For a review of TRL, see Carbon Sequestration Leadership Forum (2015).

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flexibility, and even manufacturing. It could also include experiences from the impacts of CO2 composition and impurities. It will benefit all parties if engineers and researchers are given access to the information. The data collected at the plants will be instrumental in validating and improving simulation tools that help increase understanding of the process and help reduce costs. Such a network has already been established for storage. The CO2 Storage Data Consortium is a new international network aimed at promoting data sharing from pioneering CO2 storage projects in order to accelerate innovation and deployment of CCS.

A barrier to achieving the open exchange of information, knowledge, and experience may be the ownership of intellectual property rights. Commercial entities need to make a return on what is a significant investment, and they may not want to give their intellectual property away. Confidentiality agreements may have to be considered. However, the capture and storage programs of the United States Department of Energy (DOE) are examples in which researchers and industry meet annually to share information about their project results.10 Also, the European Union-funded programme European Research Area Network Accelerating CCS Technology is encouraging the eight funded projects to actively collaborate where possible through knowledge-sharing workshops. Alternatively, knowledge sharing can be limited to non-proprietary and generic data, such as heat integration, heat exchangers, other support utilities, environmental issues, and flow and process simulations that the research and engineering communities can work on to bring costs down. Non-proprietary advanced solvent systems (e.g., the CO2 Separation and Recovery Project [TNO 2012]; Manzolini et al. 2015) may also see wider deployment. Material research and fabrication may also be considered.

Novel/emerging/innovative/transformative subsystem technologies Capture technologies are continuously in development, both with regard to improvements of currently available commercial technologies, which may be termed second or higher generations of these, as well as novel or emerging technologies. These are at very different stages of maturity, ranging from concepts or ideas through large pilots at 20–30 MW scale, or a capture capacity of up to a few hundred thousand tonnes of CO2/year. Reviews of such technologies, including discussions of maturity in terms of TRLs, can be found in a number of sources (Abanades et al. 2015; IEAGHG 2014; ZEP 2017a; CSLF 2015). Mission Innovation (2018) has identified some research needs for CO2 capture.

Further development of currently available and novel capture technologies, including radically new approaches, will benefit from the following:

Stronger modularization of the capture units, which will make them more adaptable to a range of applications, capture rates, and sizes.

Improvements in and more verification data for advanced computational tools. Advanced manufacturing techniques, such as 3-D printing, that have the potential to

revolutionize the synthesis and functionality of advanced technologies and materials in many different fields.

Exploring and exploiting the benefits of hybrid solutions; for example, solvents/sorbents in combinations with membranes.

Materials research, development, and testing. Solvents and sorbents with reduced regeneration energy (strong reductions in electricity output

penalty). Reduced degradation of solvents and sorbents. Reduced reaction time of solvents.

10 Respectively, the “CO2 Capture Technology Project Review Meeting” and the “Mastering the Subsurface Through Technology Innovation, Partnerships and Collaboration: Carbon Storage, Oil and Natural Gas Technologies Review Meeting.”

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Reduced environmental impacts of capture technologies (for amine-based technologies, significant improvements have been made regarding degradation and emissions).

Improved membranes for separation of CO2 in both high- and low-partial-pressure gas streams. Improved materials for looping processes. Air separation and combustion technologies. Parametric design to allow scaling from the large pilot scale to commercial applications. Optimized overall process, system integration, and process simplification.

Development of novel capture technologies benefits from international cooperation and researcher access to top-quality research facilities. A consortium of European RD&D facilities has been established towards this end—the European Carbon Dioxide Capture and Storage Laboratory Infrastructure consortium. However, its members are mainly at the laboratory scale, whereas one challenge is to bring technologies from concept to cost-effective demonstration. In particular, bringing new capture systems, of which new technologies may be part, across the valley of death from pilot to demonstration is expensive, as it requires large test facilities. There are few such facilities, and the existing ones are mainly for solvent-based absorption technologies. Progress will require international cooperation and burden sharing. Test facilities need to be increased both in numbers and in types of technologies. The facilities should be independent of technology vendor and technology neutral. The data collected at the test facilities will be instrumental in validating and improving simulation tools.

Performance and cost evaluations of CO2 capture technologies must be examined and interpreted with care. A common language and methodology, and transparency of methods and assumptions, is critical to the proper assessment of CCS performance and costs. Standardization is often lacking in CCS cost studies, although attempts have been made to overcome this (GCCSI 2013). ISO has issued an international standard on performance evaluation methods for post-combustion CO2

capture integrated with a power plant (2017). Over a longer time perspective, this could be followed by other standards once technologies have matured and have been implemented.

3.1.6. Recommendations for CO2 capture Towards 2020: Governments and industry should work together to:

Reduce the avoided carbon cost (or capture cost) in dollars per tonne of CO2 ($/tCO2) of currently available commercial CO2 capture technologies for power and industry by at least 30%, while at the same time minimizing environmental impacts.

Establish a network for knowledge sharing among full-scale facilities (e.g., by expanding the existing International Test Centre Network to share knowledge and experiences and increase understanding of the scale-up challenge).

Resolve issues mentioned in section 3.1.2 regarding industrial CO2 capture and bio-CCS and further develop technologies for applications and implementation in pilot plants and demonstrations.

Increase possibilities for testing at the large pilot and demonstration scale by facilitating planning and construction of more test facilities for technologies other than solvent-based technologies.

Fund and encourage RD&D activities for new and promising capture technologies. Increase activities on large-scale production of hydrogen with CCS, with the aim to develop this

as a serious option in the 2025–2030 time frame.

Towards 2025: Governments and industry should work together to:

Fund and facilitate cross-border RD&D cooperation to bring to demonstration CO2 capture technologies for power generation and industrial applications that have avoided cost in $/tCO2

(or capture cost) at least 40% below that of 2016 commercial technologies, while at the same time minimizing environmental impacts.

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Fund promising technology ideas to be tested and verified at pilot scale (1–10 MW range) and/or separating 0.01–0.1 Mt CO2/year.

Towards 2035: Governments and industry should work together to:

Encourage and facilitate cross-border RD&D cooperation to bring to demonstration CO2 capture technologies for power generation and industrial applications that capture 100% (or very close to 100%) of the CO2 and at the same time achieve 50% reduction of avoided carbon cost in $/tCO2 (or capture cost) compared to 2016 commercial technologies, while minimizing environmental impacts.

Gain experience in the integration of power plants with CCS into electricity grids that utilize renewable energy sources, seeking to develop optimal hybrid concepts with zero or negative emissions.

3.2. CO2 infrastructure Coping with the large volumes of CO2 to be collected from future power plants and industrial clusters,11 pursuant to the 2DS, will require a CO2 infrastructure, or network, comprising both transport and storage. The CO2 infrastructure will generally consist of capture from sources, individually or in clusters; transport to a collection hub;12 and common transport to a common geological storage reservoir. This section will deal with the transport part and collection hubs.

It is important to note that a barrier to the rollout of international infrastructure for offshore CCS is the London Protocol’s prohibition on the export of waste, which currently means that CO2 cannot be exported for storage across marine borders. While an amendment to change this is in place, it is not in force due to very slow ratification.

3.2.1. Transport CO2 is being transported daily by pipelines, trucks, trains, and ships in many parts of the world, although the last three in limited amounts. In certain cases, a combination of pipelines and ships is also an alternative. GCCSI (2016e) and ZEP (2017a) give overviews of transport of CO2 by pipelines and ships; the former also provides an overview of RD&D activities.

Pipelines are the most common method for transporting the large quantities of CO2 involved in CCS projects. In the United States, around 7,600 kilometers (km) of onshore pipelines transport approximately 68 Mt CO2/year (DOE NETL 2015; GCCSI 2016a). However, there is limited experience with CO2 pipelines through heavily populated areas, and the 153 km, eight-inch pipeline at Snøhvit is the only offshore CO2 pipeline. ISO has issued an international standard that, at an overall level, points out what is distinctive to CO2 pipelines relative to other pipelines (ISO 2016b).

Despite the extensive experience with CO2 pipelines, RD&D can still contribute to optimizing the systems, thereby increasing operational reliability and reducing costs. The additional RD&D work should include improved understanding and modeling of properties and the behavior of CO2 streams, validated flow assurance tools for CO2-rich mixtures, the impact of impurities on compression work and on pipeline materials (such as seals and valves) and corrosion, phase equilibria, and equations-of-state of complex CO2 mixtures, as well as possible repository requirements (Munkejord, Hammer, and Løvseth 2016). Other optimization needs include improved fracture control, leakage detection, improved capabilities to model releases from pipelines carrying dense-phase CO2 with impurities, and the identification and qualification of materials or material combinations that will reduce capital and/or operational costs. They also include effective and accepted safety measures for large supercritical

11 A cluster is a geographic concentration of emission sources. 12 A hub is a facility that collects captured CO2 from several sources of a collective size (e.g., > 10 kilotonnes CO2/year).

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pipelines, particularly in more populated areas, as has been experienced by the Barendrecht project in the Netherlands, (Feenstra, Mikunda, and Brunsting 2010). This is particularly important for clusters and plants with several units, as these will have much higher capacities than point-to-point projects. Another aspect is to look at integrating low-pressure pipeline networks with high-pressure pipeline systems. Public outreach and stakeholder dialogue and communication will be important.

There are currently no commonly agreed on specifications for the quality of the CO2 to be transported and injected, which leads to uncertainty regarding transport of CO2 containing impurities (ISO 2016b). As a strict CO2 specification gives little flexibility in a CO2 transport network and will add to the cost, it seems necessary that CO2 specifications will be identified and documented for each case.13

Ship transport can be an alternative to pipelines in a number of regions, especially in cases where CO2 from several medium-sized (near-) coastal emissions sources needs to be transported to a common injection site or to a collection hub for further transport in a trunk pipeline to offshore storage. Shipment of food-quality CO2 already takes place on a small scale (1,000–2,000 cubic meters per ship). The CO2 is transported as a liquid at 15–18 bar and –22°C to –28°C, but for larger volumes, 6–8 bar at around –50°C may be better (Skagestad et al. 2014). Major carriers, such as Maersk Tankers (Maritime Danmark 2009), Anthony Veder (Vermeulen 2011), and Chiyoda Corporation (2011, 2012) have initiated preliminary design. A feasibility study for implementation of a full-scale industrial CCS project in Norway concluded that ship transport of CO2 can be an enabler for realizing full-scale CCS in the country (MPE 2016; Økland 2016). This conclusion is supported by a major Dutch study (de Kler et al. 2016), a Scottish literature study (Brownsort 2015) and the study for Antony Veder (Vermeulen 2011). The studies considered ships in the range of 5,000–50,000 tonnes CO2 capacity. The Norwegian Ministry of Petroleum and Energy (MPE) study also included 45 bar and +10°C in addition to the two abovementioned conditions.

The Norwegian feasibility studies did not identify major issues with loading and offloading of the CO2. In the case of direct injection from ship to well, it is anticipated that this will take place from a buoy. Single point moorings and transfer technologies are available (e.g., Brownsort 2015). The extensive experience with offloading buoys in the North Sea does not cover the higher frequency of connection and disconnection that would be the case for direct injection of CO2 from ships. This option is therefore in need of further engineering for optimization. Other needs for technology development of ship transport are linked to optimization and qualification of the first systems for large-scale projects.

Roussanaly, Bunsvold, and Hognes (2014) and Kjärstad et al. (2016) have compared transport costs by pipelines and by ships to shed light on the optimal cost solution.

The transport of smaller volumes of industrial and food-grade CO2 has been successfully undertaken by truck and rail for more than 40 years. However, the cost of transportation by truck or train is relatively high per tonne of CO2 compared to pipelines, so truck and rail transport may have a limited role in CCS deployment, except for small-scale CCS opportunities or pilot projects (GCCSI 2016c). Roussanaly et al. (2017) show that train-based transport of CO2 may have site-specific cost benefits related to conditioning costs.

3.2.2. Hubs and clusters Planning CO2 infrastructure with hubs and clusters will have to consider the amount of collectible CO2, how transport (including seaborne and land transport) solutions might change for a growing cluster, the integration of different capture systems and CO2 compositions, the scale-up risks, solutions for intermediate storage, and the impact of CO2 impurities along the whole system. Storage sites are also important, and attention must be paid to long lead times for selection, characterization, and permitting, as these factors may be project limiting.

There are presently few CCS clusters and transport networks in operation. The IEA (IEAGHG 2015b) made an in-depth review of 12 cluster and hub locations (also referred to in GCCSI 2016e), of which

13 This is one of the conclusions of the project IMPACTS, which is funded by the European Union (IMPACTS 2016).

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three are in operation—the Denver City, Gulf Coast, and Rocky Mountain hubs—all in the United States. These are CO2-EOR systems where clusters of oilfields are fed by a network of pipelines. The other described systems are initiatives or plans for CO2 networks in Australia, Canada, Europe (the Netherlands and the United Kingdom), and the United Arab Emirates. Studies from initiatives such as Teesside (Tees Valley), United Kingdom, and the Rotterdam Capture and Storage Demonstration Project, Netherlands, can offer experience in the design of new systems, although they have not been deployed. The Alberta Carbon Trunk Line, Canada, is under construction. In Europe, several studies have identified CCS hubs or infrastructures.14

Building the infrastructure necessary to handle large volumes of CO2 requires that the industry moves on from the studies and projects mentioned above.

The United Kingdom CCS Cost Reduction Task Force (CCSA 2013) found that CO2 transport costs could be reduced by more than 50% with the deployment of large, efficiently utilized pipelines (5–10 million tonnes CO2 per year compared to 1–2 million tonnes per year), noting that even lower costs could be seen in the longer run if higher volumes of CO2 from multiple large capture plants are fed into an interconnected right-sized network. Transportation of CO2 represents a smaller part of the total costs for a CCS chain than capture and may have, relatively speaking, moderate impact on the total cost of a CCS chain, particularly for onshore pipelines (IEAGHG 2015b), although the cost may be significant in absolute money terms (Roussanaly, Brunsvold, and Hognes 2014). However, there are other potential benefits in addition to cost sharing (GCCSI 2016e; ZEP 2013b; IEAGHG 2015b), including the following:

Lowering costs in building early infrastructure by utilizing benefits of connecting low-cost industrial sources with storage sites.

Lowering costs by sharing infrastructure. Lowering the entry barriers for participating CCS projects, such as emitters with small-volume

sources and emitters with limited or no access to local storage. Securing sufficient CO2 for CO2-EOR projects, which is likely to be an important element of

some clusters because of the revenue it can contribute. Minimizing the environmental impacts associated with infrastructure development, as well as

the impact on communities. Minimizing and streamlining efforts in relation to planning and regulatory approvals, negotiations

with landowners, and public consultations. Sharing and utilizing surplus heat in the capture processes of industrial clusters.

In order for large-scale CCS deployment to take place, it is necessary to move from project-by-project to systems thinking. The GSSCI (2016e), ZEP (2013b; 2017c), and the IEA (IEAGHG 2015b) reveal few technology gaps for implementing CCS clusters. Most gaps, risks, and challenges are commercial and political in nature and may include the cooperation of different industries across the CCS value chain, the lack of project-on-project confidence, the completion of projects on cost and on schedule, operational availability, flexibility, reliability, financing and political aspects, and last but not least, lack of business models for larger CCS systems. Some thinking on business models has started that includes the separation of CO2 capture at the sources from the transport and storage parts (Esposito, Monroe, and Friedman 2011; Pöyry and Teesside Collective 2017; Banks, Boersma, and Goldthorpe 2017). In these models, a split of costs and risk between the government and the industry players has been explored; for example, governments taking a certain responsibility to develop transport and storage networks. A feasibility study conducted in Norway (MPE 2016) identified three possible industry sources of CO2 (providing in total 1.3 Mt CO2/year), with pipeline/ship transport to an onshore facility and a common storage site located 50 km from the coast. The government will investigate a model in which the state may take on certain responsibilities

14 For example, ZEP (2013b, 2016a); Jakobsen et al. (2017); Bellona (2016); and Brownsort, Scott, and Hazeldine (2016), the last by reuse of an existing oil pipeline.

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for cost and risks in connection with the development of the transport and storage infrastructure together with industry to advance the development of a commercial market for CO2 storage. Another learning from the Norwegian project is that current CO2 storage regulations must be adjusted to clarify roles and responsibilities over the lifetime of CO2 storage projects.

3.2.3. Recommendations for CO2 transport and infrastructure Towards 2020: Governments and industry should work together to:

On transport

Acquire necessary data for impurities in CO2 streams and understand the effects on pipeline materials.

Establish and validate models that include effects as above. Further develop safety measures for large-scale CO2 pipelines, including validation of

dispersion models for impact assessment of incidents pursuant to leakage of CO2 from the transport system.

Qualify pipeline materials for use in CO2 pipes and injection tubing when the CO2 contains impurities.

Optimize and qualify systems for ship transport, in particular direct offshore unloading of CO2 to a well.

Map the competing demands for steel and secure the manufacturing capacity for the required pipe volumes and other transport items.

Develop systems for metering and monitoring CO2 supplied from multiple sources with varying purity and composition that feed into a common collection and distribution system.

Identify business cases for transportation and storage companies.

On infrastructure

Design and initiate large-scale CO2 hubs that integrate capture, transport, and storage, including matching of sources and sinks.

Develop commercial models for industrial and power CCS chains.

Towards 2025: Governments and industry should work together to:

Implement the first large-scale (i.e., >10 Mt CO2/year aggregate throughput) CCS chains in power, industrial, and bio-CCS. These should be focused in industrial regions that have the potential to share infrastructure, rather than focusing on individual projects.

Implement initial shared infrastructure for a limited number of plants within industrial clusters. This should recognize that in the initial phases, volumes within these clusters may be less than one million tonnes per annum, but that expansion from this initial start will occur.

Towards 2035: Governments and industry should work together to:

Continue progressive rollout and expansion of full-scale CCS chains and clusters in power, industrial, and bio-CCS. This includes large-scale CO2 transport networks that integrate CO2 capture, transport, and storage, including matching of sources and sinks.

3.3. Storage Storage works, as exemplified by the projects in table 3.1. These are presently operating or are expected to become operational during 2017 with pure geological storage. Five are large-scale projects (GCCSI 2016b, n.d).

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Table 3.1. Projects with pure geological storage

Project Operational from Amount stored, Mt CO2/year Storage type

Sleipner October 1996 0.9 Offshore aquifer

Snøhvit April 2008 0.7 Offshore aquifer

Quest November 2015 1.0 Onshore aquifer

Illinois Industrial CCS April 2017 1.0 Onshore aquifer

Tomakomai April 2016 0.1 Offshore aquifer

Gorgon Autumn 2017 3.4 Offshore aquifer

The GCCSI identifies a further eight pure geological storage projects under consideration. In all, the GCCSI has identified a total of 38 large-scale projects, of which the majority are enhanced oil recovery projects.

The Sleipner storage project has been running since fall 1996 without any incidents, and it has successfully stored more than 16 million tons of CO2 injected into the Utsira Formation in the Norwegian sector of the North Sea, demonstrating that CO2 can be safely and securely stored in significant quantities over decades.

At Snøhvit, in the Barents Sea, CO2 from an onshore liquefied natural gas plant is transported offshore using a 153 km pipeline and is injected via a subsea template into neighboring reservoirs, from which natural gas is produced from a depth of about 2,400 meters. It has injected around 4 Mt of CO2. After about one year of CO2 injection at the Snøhvit field, the well pressure increased steadily. The operator implemented corrective measures while the relevant authorities were kept informed; there was no risk for leakage of CO2 to the seabed. The Snøhvit case illustrates how risks can be avoided with well-conceived monitoring and risk management systems.

Quest, located in Alberta, Canada, retrofitted CO2 capture facilities to three steam methane reformers at the existing Scotford Upgrader. Launched in November 2015, Quest has the capacity to capture approximately 1 Mt/year of CO2 annually. The captured CO2 is transported via pipeline to the storage site for dedicated geological storage. In July 2017, Quest announced it had captured and stored 2 million tonnes of CO2.

The Illinois Industrial CCS Project is the first CCS project in the United States to inject CO2 into a deep saline formation at a scale of 1 Mt/year, and it is also the world’s first large-scale bio-CCS project. Its CO2 source is derived from a corn-to-ethanol process.

The Gorgon CO2 Injection Project in Australia plans to commence operations in autumn 2017, with injection of CO2 at a depth of about 2 km below Barrow Island, off the northwest coast of Australia. The injection rate will be 3.4–4.0 Mt/year for at least 30 years.

In Japan, the Tomakomai Project has injected approximately 0.1 Mt CO2/year into an offshore aquifer since April 2016. The CO2 is captured at the hydrogen unit at a refinery. The CO2 is injected by two deviation wells drilled from onshore. The injection zones are more than 1,000 meters long. The monitoring system at Tomakomai includes three observation wells, seismometers for earthquake monitoring and marine monitoring surveys with side-scan sonar, water sampling, a seabed profiler, current meters, and sampling and observations of benthos.

In addition, the CO2 re-injection K12B project on the Dutch continental shelf has been operating since 2004, injecting 90,000 tonnes CO2 during continuous natural gas production. Monitoring systems have been in place and tested since 2007. From 2015, monitoring was expanded to include tracers (GDF Suez, n.d.).

The continued deployment of commercial-scale projects is essential for the accelerated technology development needed to reduce costs and enhance confidence in CO2 storage as a safe and permanent solution for curbing CO2 concentrations in the atmosphere. In addition, new business models are needed to make CCS commercially attractive for the operators. CO2-EOR is one

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opportunity for improving the business case, and hydrogen production can be another. Nevertheless, CCS depends on significant investments.

The identification of suitable storage sites and validation of storage capacity remain a challenge, especially where geological and geophysical data coverage is sparse. Moreover, the methods to evaluate CO2 capacity should be improved to include dynamic properties to reduce potential errors in this evaluation. However, based on evaluations of storage capacities, for example in Australia, Brazil, China, South Africa, the United Kingdom, the United States, and the Nordic countries, it is anticipated that sufficient storage is available for several decades.15

The United Nations Economic Commission for Europe Expert Group on Resource Classification (UNECE 2016) has released a report on the classification of injection projects. In addition, the Society of Petroleum Engineers will release a Geologic Storage Resources Management System (SPE 2017).

How to ensure and verify that the stored CO2 remains in place is still a significant question from regulators and the general public. Advanced monitoring methods and well-established natural baselines are essential to ensure and document safe injection and permanent containment, and they will be a key to establishing confidence.

3.3.1. Identified technology needs The CSLF Technology Roadmap 2013 highlighted the risk management elements where continued research is required, and these essentially remain valid today. Significant progress has been made, as exemplified through the site characterizations, extensive monitoring programs, and risk management analyses and systems that accompanied storage applications for Quest, Gorgon, Tomakomai, Snøhvit, and Sleipner projects (renewed permits for the Norwegian projects). Also the Rotterdam Capture and Storage Demonstration Project and Goldeneye (former Peterhead) projects developed plans that met the requirements by national and European Union regulations. However, there will still be room for improvements, and local adaptations are always necessary. Mission Innovation (2018) identifies some research needs for CO2 storage. The following topics have been identified as technology gaps or needs for dedicated storage:16

Storage A unified methodology to estimate a project’s CO2 storage capacity (SPE 2017). Reduced uncertainty in injectivity, which is directly linked with reduced storage risk. Coordinated strategic plans for the development of transport and storage systems. CO2 storage resource portfolios and exploration and appraisal (E&A) procedures adapted to

CO2 storage to reduce uncertainties. Monitoring

New and more reliable and accurate monitoring technologies, and commercialization and cost optimization of existing monitoring technologies and techniques to support the risk management of storage.

Online/real-time monitoring over large areas, which will reduce operational costs and risks, including the challenge of handling large volumes of data, both during and after CO2 injection.

Understanding of long-term reservoir behavior Models for improved understanding of fundamental reservoir and overburden processes,

including integrating hydrodynamic, thermal, mechanical, and chemical processes.

15 See also Global Carbon Atlas (2015). 16 ZEP (2017a) gives an extensive review of CO2 injection and storage technologies and needs.

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Improved and fit-for-purpose well and reservoir technologies and management procedures, including well integrity.

Storage integrity Forecasting CO2 pressure development and related geomechanical effects to minimize risk

of leakage. Robust CO2 wells that prevent migration more efficiently and cost-effectively. Well integrity and plug and abandon strategies for existing wells within CO2 storage. Increasing knowledge on sealing capacity of caprocks. Mitigation/remediation measures.

Interface with other areas Identification of where CO2 storage conflicts with/impacts on other uses and/or resource

extraction and inclusion in resource management plans (for example, oil and gas production, marine and maritime industry, and production of drinkable water).

Assessments of the suitability of existing oil and gas facilities to be reused or repurposed. Understanding of the effects of impurities in the CO2 stream, including their phase behavior,

on the capacity and integrity of the CO2 storage site, with emphasis on well facilities (overlaps with CO2 transport).

Storage closure, post-injection monitoring, and liability transfer Experience with closure and post-closure procedures for CO2 storage projects (must wait

until there are injection projects that close down). Subsea CO2 pipelines and legal aspects concerning national sovereignty and neighboring

territories. Strategies for taking closure into account when designing wells and dialogue with regulators

to establish regulations similar to petroleum regulations. Procedures for securing and closure of CO2 storage, and post-closure monitoring. Procedures for transferring liability.

3.3.2. Recommendations for CO2 storage Towards 2020: Governments and industry should work together to:

On large-scale CO2 storage

Identify, characterize, and qualify CO2 storage sites for large-scale systems. Maintain momentum for the Large-Scale Saline Storage Project Network, which was announced

at the sixth CSLF Ministerial Meeting in Riyadh, Saudi Arabia, in November 2015, and which was proposed to leverage international saline storage projects that can share best practices, operational experience, and lessons learned to advance CCS deployment.

Accelerate learning and technology development by sharing subsurface, well, and other relevant data and knowledge; for example, in initiatives such as the CO2 Storage Data Consortium, an open, international network developing a common platform for sharing data sets from pioneering CO2 storage projects.

Fund RD&D activities to close technology gaps and validate the methods/technologies in case studies to accelerate the pace of CCS deployment.

Facilitate synergies with other technologies; for example, geothermal and other relevant renewables.

Facilitate research into the interface between transport and storage. Undertake regional appraisal programs with dynamic calibration and matched source-sink

scenario analysis. Identify the sites for CO2 storage that are most likely to work, including in developing nations. Improve CCS narratives around CO2 storage, costs, and CO2 containment risks.

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Increase public communication on CO2 storage projects to improve the communication and dissemination of this technology and to increase knowledge and acceptance with the general public—to gain a social license to operate.

On monitoring and mitigation/remediation

Fund activities that continue to drive down costs for existing monitoring technologies and techniques, and the development, demonstration, and validation of new measuring and monitoring techniques and sensors, onshore and offshore. This includes for leakage in terms of anomaly detection, attribution, and leakage quantification.

Fund development and demonstration of monitoring strategies to optimize monitoring and make monitoring more cost-efficient for large-scale projects.

Fund development and verification of mitigation and remediation methods and corrective actions for leakage, including well leakage, and test in small-scale, controlled settings.

Identify minimum requirements/objectives for monitoring and verification (M&V) programs, both onshore and offshore, to inform fit-for-purpose legislation and regulations.

On understanding the storage reservoirs

Further advance and utilize simulation tools, with a focus on multiphase flow algorithms and coupling of fluid flow to geochemical and geomechanical models.

Develop and agree on consistent methods for determining CO2 storage capacity (dynamic) reserves at various scales (as opposed to storage resources), at various levels of project maturity, and with a global distribution of this capacity.

Further improve dynamic CO2 capacity assessment (e.g., Smith 2017). Further improve on well material (steel and cement) technologies to reduce cost and risk (such

as corrosion). Enhance the ability to more precisely predict storage efficiency by using experience from

successful injections (e.g., Sleipner and Snøhvit) and knowledge on geological complexity to improve models on reservoir injectivity and plume migration.

Enable safe injection of large amounts of CO2 by advancing reservoir models with respect to predicting pressure buildup, and avoid hydraulic fracturing.

Recommend workflow for caprock and fault integrity studies in CO2 storage sites, as well as measurements and geochemical modeling of sealing capacity.

Develop a cost model that will help improve CO2 storage assessments.

Towards 2025: Governments and industry should work together to:

On large-scale CO2 storage

Permanently store at least 400 Mt CO2 /year by 2025 (or have permanently captured and stored 1,800 Mt CO2), which corresponds approximately to the 2oC Scenario.

Facilitate exploration, characterization, and qualification of large-scale CO2 storage sites (10–100 Mt CO2/year) in key regions of the world, building on experience from current projects and pilots and including use of existing oil and gas infrastructure.

Facilitate qualification of CO2 storage sites for safe and long-term storage in the scale of tens of millions of tonnes of CO2 annually per storage site, linked to clusters of CO2 transport systems.

Ensure that all CSLF member countries have national storage assessments publicly available. Continue the development and execution of E&A portfolio programs in key potential storage

basins. Develop robust conceptual workflow to assure regulators that site characterization meets

international leading practice.

On monitoring and mitigation/remediation

Reduce M&V overall costs by 25% in average from 2016 levels.

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Towards 2035: Governments and industry should work together to:

On large-scale CO2 storage

Permanently store at least 2,400 Mt CO2/year by 2035 (or have permanently captured and stored 16,000 Mt CO2), which corresponds approximately to the 2°C Scenario.

On monitoring and mitigation/remediation

Reduce M&V overall costs by 40% in average from 2016 levels.

3.4. CO2 utilization, including enhanced hydrocarbon recovery CO2-EOR is the most widely used form of CCUS, with more than 120 operations, mainly onshore in North America. In 2015, over 68 million metric tonnes of CO2 were injected in depleted oil fields in the United States for EOR, transported in a 7,600 km pipeline system (DOE NETL 2015; GCCSI 2016a), with most of the CO2 coming from natural sources. A milestone in CO2 capture for EOR was reached in January 2017, when the Petra Nova project in Texas started injection of 1.4 Mt CO2/year captured from a power plant.

Canada has been injecting sour gas, a mixture of CO2 and hydrogen sulfide, for decades as a necessary process associated with natural gas processing. In certain circumstances, the acid gas injection is in association with enhanced recovery such as the Zama field (Smith et al. 2009). Brazil is currently injecting CO2 for EOR at the offshore fields Lula and Sapinhoá. Many other countries, including the United Kingdom, Japan (for offshore CO2-EOR in Vietnam), Malaysia, China, the United States, Indonesia, and Norway, are working or have worked to characterize the opportunities for offshore CO2-EOR. Other specific applications of CO2 for enhanced hydrocarbon recovery include enhanced coal bed methane production (ECBM), enhanced gas recovery (EGR), enhanced gas hydrate recovery (EGHR), hydrocarbon recovery from oil shale, and the fracturing of reservoirs to increase oil/gas recovery. However, these other applications are processes still being developed or tested in pilot-scale tests (CSLF 2012, 2013a); for example, the K12B site off the shore of the Netherlands has been evaluated for EGR (TNO, n.d.).

Other potential CCUS options that may lead to secure long-term storage are the use of CO2 as the heat-transfer agent in geothermal energy systems, enhanced water recovery (EWR), carbonate mineralization, concrete curing, and bauxite residue. Mixing CO2 with bauxite residue (red mud) has been demonstrated in Australia (GCCSI 2011). EWR is being demonstrated in China and has the opportunity to provide produced waters for other arid regions of the world. EWR has the ancillary benefit of optimizing storage capacity and mitigating pressure differences in the storage formations (Li et al. 2015).

There are several forms of CO2 reuse, or CCU, already in use or being explored, including urea production, ethylene oxide production, ethanol production, utilization in greenhouses, conversion to polymers, methanol and formic acid production, production of bioplastics, and the cultivation of algae as a pathway to bioenergy animal feed, as well as other products. These will not lead to permanent storage but may contribute to reduced CO2 emissions; for example, if the captured CO2 replaces new, fresh hydrocarbons as source for carbon. Also, there may be other related benefits: as an example, the utilization of waste CO2 in greenhouses in the Netherlands already leads to a better business case for renewable heating and a rapid growth of geothermal energy use in the sector. These options could lead to a reduction in capture costs and transport optimization and learnings.

It must be noted that for some countries, such as China (Administrative Center for China’s Agenda 21 2015), CCU may provide a potential for CO2 reduction and early opportunities to catalyze the development of CCS. Its strategic importance lies not only in offsetting the extra cost incurred in the CO2 capture process, but also in providing a technical, policy, and legal basis and valuable engineering experience for the demonstration and promotion of CCS. More importantly, it offers a feasible strategic choice that can help ensure energy security, break regional development bottlenecks, and promote the incubation of low-carbon industries. Finally, the public’s opinion of CCS as a whole may become more positive when utilization options are part of the portfolio.

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For many of the CCUS and, in particular, CCU options, the total amount of CO2 that can be permanently stored is, for all practical and economic purposes, limited (Mac Dowell et al. 2017). CO2-EOR has the largest potential of the various CO2 utilization options described, and it has not been sufficiently explored to date as a long-term CO2 storage option. So far, only the CO2-EOR Weyburn-Midale project in Canada; the CO2-EOR Project at the Bell Creek field in Montana; the CO2-EOR project at Cranfield site in Mississippi; and the Farnsworth, Texas, project have performed extensive monitoring and verification of CO2 stored in EOR operations.

Other utilization options appear to have limited potential for reducing global warming. It is important to perform life cycle assessments of the processes to secure that there are no unintended additional CO2 emissions (Mac Dowell et al. 2017). It will be several years before these sites close down.

The lack of scalability and the economic challenges are significant barriers to the deployment of CO2 utilization technologies in the near and long term (NCC 2016). However, in some countries utilization provides early opportunities to catalyze the implementation of CCS. In this way, the CO2 utilization pathways can form niche markets and make a contribution to paving the way for commercial CCS. This applies not only to oil-producing countries but also to regions with evolved energy systems that will allow the implementation of feasible CO2 business cases.17

3.4.1. Identified technology needs There are technical and policy reasons to further examine the challenges of the utilization of CO2. Recent reviews of utilization18 point to several possible topics requiring RD&D, including the following:

Improving the understanding of how to increase and prove the permanent storage of CO2 in CO2-EOR operations. CSLF (2013b) points out the similarities and differences between CO2-EOR and CO2 injected for storage. One conclusion from this report is that there are no technical challenges per se in converting CO2-EOR operations to CCS, although issues like the availability of high-quality CO2 at an economic cost and in appropriate volumes; infrastructure for transporting CO2 to oil fields; and legal, regulatory, and long-term liability must be addressed.

Make offshore CO2-EOR economic, including the following (CSLF 2017b): Making sufficient CO2 available; e.g., by building transport infrastructure that connects

sources with reservoirs. Supporting RD&D to develop and qualify new technologies. Developing business models for offshore CO2-EOR. Improving volumetric sweep. Due to different well configuration in offshore fields compared

with onshore EOR, alternative methods for are needed. Optimal well placement and mobility controls of CO2 are instrumental for success.

Expanding experience from offshore EOR needs beyond the Lula project in Brazil. Proving offshore CO2-EOR economically viable.

Improving the understanding of how to increase and prove the permanent storage of CO2 in EGR, ECBM, EGHR, enhanced shale gas recovery, and other geological applications of CO2.

Developing and applying carbonation approaches (i.e., for the production of secondary construction materials).

17 Recent reviews of utilization of CO2 include SEAB (2016), DOE (2016), NCC (2016), CSLF (2012, 2013a), Administrative Center for China’s Agenda 21 (2015), GCCSI (2011), ADEME (2010), Styring (2011), Dijkstra (2012), Tomski (2012), Markewitz et al. (2012), and ZEP (2016b). In April 2013, the Journal of CO2 Utilization was launched, providing a multidisciplinary platform for the exchange of novel research in the field of CO2 reuse pathways.

18 See NCC (2016), CSLF (2012, 2013a), Administrative Center for China’s Agenda 21 (2015), GCCSI (2011), ZEP (2016b), Styring (2011), and Mission Innovation (2018).

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Developing large-scale, algae-based production of fuels and animal feed to offset primary fuel consumption and decrease agricultural cultivation practices, which might have a large CO2

footprint. Improving and extending the utilization of CO2 in greenhouses to increase the biological

processes for photosynthesis, investigating marine algae cultivation for wide-scale biomass production, and engineering the rhizosphere to increase carbon sequestration and biomass production.

Developing processes that enable synthetic transformations of CO2 to fuels or chemical products, based on thermo-, electro- or photochemical processes, including catalysts made from inexpensive elements and new materials using advanced manufacturing techniques that enable large-scale processes for conversion of CO2 directly to fuels or other products.

Perform life cycle analysis for a range of utilization options, with the aim to learn the total carbon footprint.

3.4.2. Recommendations for CO2 utilization Towards 2020: Governments and industry should work together to:

Resolve regulatory and technical challenges for the transition from CO2-EOR operations to CO2 storage operations. There may be value in experiences from reporting requirements for CO2 operations that are claiming credits under the 45Q tax credit in the United States. 19

Research, evaluate, and demonstrate carbonation approaches, in particular for mining residue carbonation and concrete curing, but also other carbonate mineralization that may lead to useful products (e.g., secondary construction materials), including environmental barriers such as the consequences of large mining operations and the disposal of carbonates.

Support research and development pathways for the development of novel catalysts using abundant materials and advanced manufacturing techniques to produce nanocatalysts to bring down costs.

Support RD&D on subsea separation and improved mobility control. Map opportunities, conduct technology readiness assessments, and resolve main barriers for the

implementation of the CO2 utilization family of technologies, including benchmarked life cycle assessments and CO2 and energy balances.

Increase the understanding of CO2 energy balances for each potential CO2 reuse pathway and the energy requirement of each technology using technological modeling.

Towards 2025 Governments and industry should work together to:

Promote more offshore CO2-EOR pilot projects as part of deployment of large-scale CO2 storage, as CO2 becomes available in amounts and during time windows relevant for EOR.

19 This refers to § 45Q of the US Internal Revenue Code, which allows for tax credits of $20 per metric tonne of qualified carbon dioxide stored and $10 per metric tonne used for EOR, captured by the taxpayer at a qualified facility. As of September 2017, there were proposals in the US Congress to increase these credits.

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4. Summary Carbon capture and storage, or CCS, will be required for nations to meet their Paris Agreement targets. Experience has shown that CCS prevents significant volumes of CO2 from the power and industrial sectors from entering the atmosphere.

This updated Carbon Sequestration Leadership Forum technology roadmap highlights advances in capturing, utilizing, and storing CO2 since the 2013 roadmap was issued, and it provides the nations of the world with a powerful and strategic way forward to achieve an orderly and timely transition to a lower-emissions future.

Since the last update of the technology roadmap in 2013, there have been advances and positive developments in CCS, although at a lower rate than is necessary to achieve earlier objectives. New commercial large-scale integrated projects as well as demonstration-scale projects have commenced operation both in the power and industrial sectors, and enabling legislation has been enacted in some jurisdictions. This technology roadmap has been updated in light of the Paris Agreement. In particular, the this roadmap highlights the need for CCS mitigation in industries other than the power industry and the potential of achieving negative CO2 emissions using a combination of bioenergy and CCS. The opportunity for reducing costs by harnessing the economies of scale that can be delivered through developing industrial clusters, and CO2 transport and storage hubs, is also highlighted.

Deployment of CCS at scale is not possible without supportive policy settings, long-term political commitment, public acceptance, and the appropriate financial support for early and long-term CCS deployment. Already, much work has been done on building fit-for-purpose regulatory frameworks to provide regulatory certainty to operators and to build confidence in communities that the process is safe.

This technology roadmap demonstrates that CCS has been successfully applied in the power industry, the gas processing industry, refineries, cement and steel production, waste-to-energy, industries using biomass as raw material, and for enhanced oil recovery. This roadmap also highlights that the implementation is well behind the trajectory to reach the Paris Agreement goal of being significantly below a 2°C temperature rise.

This roadmap sets new time horizons for medium- and long-term recommendations, with targets shifted to 2025 and 2035. This is more incisive than the previous version, as the CSLF recognizes that implementation needs to be stepped up.

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5. Priority Actions Recommended for Implementation by Policymakers Based on the findings in this report, governments and industries should partner on CCS to contribute to the Paris Agreement target of limiting the temperature increase from anthropogenic CO2 emissions to 2°C by implementing sufficient large-scale projects in the power and industry sectors to achieve the following:20

Long-term isolation from the atmosphere of at least 400 Mt CO2 per year by 2025 (or permanent capture and storage of in total1,800 Mt CO2).

Long-term isolation from the atmosphere of at least 2,400 Mt CO2 per year by 2035 (or permanent capture and storage of in total 16,000 Mt CO2).

This may be achieved through the following actions:

Demonstrating the value proposition of CCS as a key technology to reduce CO2 emissions across various sectors of the economy while providing other societal benefits (energy security; access; and additional environmental benefits, such as air pollution reduction, grid stability, and jobs preservation and creation).

Developing and implementing policy frameworks that incentivize investments in CCS, including an equitable level of consideration, recognition, and support for CCS on similar entry terms as other low-carbon technologies, and reduce commercial risks.

Creating an enabling market environment and innovative business models for CCS support. Implementing fit-for-purpose and comprehensive legal and regulatory frameworks for CCS, also

on a regional scale (e.g., the London Protocol to provide for offshore cross-border movement of CO2).

Encouraging strategic power and industrial CO2 capture clusters, collection hubs, and CO2 transportation and storage infrastructures, including early mapping matching sources to sinks and identification and characterization of potential storage sites.

Engaging in substantive CCS public outreach and education, aimed at building trust, reducing and tackling misconceptions, supporting educators as well as community proponents of CCS projects, and improving communication.

Promoting the exchange of design, construction, and operational data; lessons learned; and best practices from large-scale projects.

Investing deeply in RD&D for novel and emerging technologies (at the subsystem level) along the whole CCS chain to drive down costs, including synergies between CCS and renewables (e.g., geothermal).

Funding the appraisal of storage opportunities and conducting technology readiness assessments in developing countries.

Mapping opportunities, conducting technology readiness assessments, and resolving main barriers to the implementation of the CO2 utilization family of technologies, including life cycle assessments and CO2 and energy balances.

20 The targets correspond approximately to the International Energy Agency’s 2°C Scenario.

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6. Follow-Up Plans The CSLF should continue to be a platform for an international coordinated effort to commercialize CCS technology working with, among others, the IEA, the GCCSI, and the IEA Greenhouse Gas R&D Programme.

The CSLF should continue to monitor progress in light of the identified priority actions, report the findings at Ministerial meetings, and suggest adjustments and updates of the technology roadmap. It is recommended that the CSLF, through its Projects Interaction and Review Team (PIRT), monitor progress in CCS made in relation to the recommended priority actions. Through the CSLF Secretariat, the PIRT will:

Solicit input with respect to progress of CCS from all members of the CSLF. Gather information from a wide range of sources on the global progress of CCS, including

collaboration partners. Prepare a simple reporting template that highlights the progress made in relation to the priority

actions. Report annually to the CSLF Technical Group Report biennially, or as required, to the CSLF Ministerial Meetings.

The PIRT should continue to have the responsibility for future updates of the CSLF technology roadmap.

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7. Acknowledgements This technology roadmap was prepared for the CSLF Technical Group by an editorial committee under the auspices of the CSLF Projects Interaction and Review Team. The committee was chaired by Andrew Barrett, Australia, and had members from the United Kingdom (Brian Allison), Canada (Eddy Chui), South Africa (Tony Surridge), the United States (John Litynski), The International Energy Agency Greenhouse Gas R&D Programme (Tim Dixon), and Norway (Lars Ingolf Eide). The CSLF Secretariat (Richard Lynch) and the CSLF Technical Group Chair Åse Slagtern (Norway) have also taken active part in the discussions. The first draft of the technology roadmap was sent to a large number of international experts, and the following individuals contributed comments and input:

Norway: Philip Ringrose, Sveinung Hagen, Jørg Aarnes, Jens Hetland, Arvid Nøttvedt, Grethe Tangen, Mario Ditaranto, Svein Gunnar Bekken, Jørild Svalestuen, Svend Tollak Munkejord, Arne Dugstad, Hans Aksel Haugen, Partow Partel Henriksen, John Kristian Økland, and Tore Andreas Torp

United States: John Thompson

United Kingdom: Sarah Tennison and Jon Gibbins

South Africa: Sibbele Heikamp

Australia: Paul Feron

Japan: Takayuki Higahsii

Global Carbon Capture and Storage Institute

Valuable input on the Executive Summary was received from Sallie Greenberg, University of Illinois, and Communications Task Force members Jeff Erikson, Tom Howard-Vyse, Ron Munson and Hamoud Otaibi.

Amy Cutter, BEIS, UK, and Valerie Riedel, Energetics, suggested valuable improvements to language.

Several CSLF Technical Group delegates, as well as observers from the International Energy Agency and Global Carbon Capture and Storage Institute, took supplied corrections and suggestions for improvement in the next-to-final draft.

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Annex A. Abbreviations and Acronyms

$/tCO2 dollars per tonne of carbon dioxide

2DS 2°C Scenario

B2DS Beyond 2°C Scenario

CSLF Carbon Sequestration Leadership Forum

CCS carbon capture and storage

CCU carbon capture and utilization

CCUS carbon capture, utilization, and storage

CDM Clean Development Mechanism

CO2 carbon dioxide

CO2-EOR carbon dioxide-enhanced oil recovery

DOE US Department of Energy

ECBM enhanced coal bed methane production

E&A exploration and appraisal

EGHR enhanced gas hydrate recovery

EGR enhanced gas recovery

EOR enhanced oil recovery

EWR enhanced water recovery

GCCSI Global Carbon Capture and Storage Institute

H2 hydrogen

IEA International Energy Agency

ISO International Organization for Standardization

km kilometer

M&V monitoring and verification

MPE Norwegian Ministry of Petroleum and Energy

MW megawatts (106 watts)

Mt megatonnes (106 tonnes)

OECD Organisation for Economic Co-operation and Development

PIRT Projects Interaction and Review Team

ppm parts per million

RD&D research, development and demonstration

RTS Reference Technology Scenario

TRL Technology Readiness Level

UNFCCC United Nations Framework Convention on Climate Change

ZEP European Technology Platform for Zero Emission Fossil Fuel Power Plants

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Annex B. Summary of Technical Recommendations

Towards 2020: Governments and industry should work together to:

On capture

Reduce the avoided carbon cost (or capture cost) in dollars per tonne of CO2 ($/tCO2) of currently available commercial CO2 capture technologies for power and industry by at least 30%, while at the same time minimizing environmental impacts.

Establish a network for knowledge sharing among full-scale facilities (e.g., by expanding the existing International Test Centre Network to share knowledge and experiences and increase understanding of the scale-up challenge).

Resolve issues mentioned in section 3.1.2 regarding industrial CO2 capture and bio-CCS and further develop technologies for applications and implementation in pilot plants and demonstrations.

Increase possibilities for testing at the large pilot and demonstration scale by facilitating planning and construction of more test facilities for technologies other than solvent-based technologies.

Fund and encourage RD&D activities for new and promising capture technologies. Increase activities on large-scale production of hydrogen with CCS, with the aim to develop this

as a serious option in the 2025–2030 time frame.

On transport and infrastructure

Acquire necessary data for impurities in CO2 streams and understand the effects on pipeline materials.

Establish and validate models that include effects as above. Further develop safety measures for large-scale CO2 pipelines, including validation of

dispersion models for impact assessment of incidents pursuant to leakage of CO2 from the transport system.

Qualify pipeline materials for use in CO2 pipes and injection tubing when the CO2 contains impurities.

Optimize and qualify systems for ship transport, in particular direct offshore unloading of CO2 to a well.

Map the competing demands for steel and secure the manufacturing capacity for the required pipe volumes and other transport items.

Develop systems for metering and monitoring CO2 supplied from multiple sources with varying purity and composition that feed into a common collection and distribution system.

Identify business cases for transportation and storage companies. Design and initiate large-scale CO2 hubs that integrate capture, transport, and storage,

including matching of sources and sinks. Develop commercial models for industrial and power CCS chains.

On storage

Identify, characterize, and qualify CO2 storage sites for large-scale systems. Maintain momentum for the Large-Scale Saline Storage Project Network, which was announced

at the sixth CSLF Ministerial Meeting in Riyadh, Saudi Arabia, in November 2015, and which was proposed to leverage international saline storage projects that can share best practices, operational experience, and lessons learned to advance CCS deployment.

Accelerate learning and technology development by sharing subsurface, well, and other relevant data and knowledge; for example, in initiatives such as the CO2 Storage Data Consortium, an open, international network developing a common platform for sharing data sets from pioneering CO2 storage projects.

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Fund RD&D activities to close technology gaps and validate the methods/technologies in case studies to accelerate the pace of CCS deployment.

Facilitate synergies with other technologies; for example, geothermal and other relevant renewables.

Facilitate research into the interface between transport and storage. Undertake regional appraisal programs with dynamic calibration and matched source-sink

scenario analysis. Identify the sites for CO2 storage that are most likely to work, including in developing nations. Improve CCS narratives around CO2 storage, costs, and CO2 containment risks. Increase public communication on CO2 storage projects to improve the communication and

dissemination of this technology and to increase knowledge and acceptance with the general public—to gain a social license to operate

Fund activities that continue to drive down costs for existing monitoring technologies and techniques, and the development, demonstration, and validation of new measuring and monitoring techniques and sensors, onshore and offshore. This includes for leakage in terms of anomaly detection, attribution, and leakage quantification.

Fund development and demonstration of monitoring strategies to optimize monitoring and make monitoring more cost-efficient for large-scale projects.

Fund development and verification of mitigation and remediation methods and corrective actions for leakage, including well leakage, and test in small-scale, controlled settings.

Identify minimum requirements/objectives for monitoring and verification (M&V) programs, both onshore and offshore, to inform fit-for-purpose legislation and regulations.

Further advance and utilize simulation tools, with a focus on multiphase flow algorithms and coupling of fluid flow to geochemical and geomechanical models.

Develop and agree on consistent methods for determining CO2 storage capacity (dynamic) reserves at various scales (as opposed to storage resources), at various levels of project maturity, and with a global distribution of this capacity.

Further improve dynamic CO2 capacity assessment (e.g., Smith 2017). Further improve on well material (steel and cement) technologies to reduce cost and risk (such

as corrosion). Enhance the ability to more precisely predict storage efficiency by using experience from

successful injections (e.g., Sleipner and Snøhvit) and knowledge on geological complexity to improve models on reservoir injectivity and plume migration.

Enable safe injection of large amounts of CO2 by advancing reservoir models with respect to predicting pressure buildup, and avoid hydraulic fracturing.

Recommend workflow for caprock and fault integrity studies in CO2 storage sites, as well as measurements and geochemical modeling of sealing capacity.

Develop a cost model that will help improve the CO2 storage assessments.

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Utilization

Resolve regulatory and technical challenges for the transition from CO2-EOR operations to CO2 storage operations. There may be value in experiences from reporting requirements for CO2 operations that are claiming credits under the 45Q21 tax credit in the United States.

Research, evaluate, and demonstrate carbonation approaches, in particular for mining residue carbonation and concrete curing, but also other carbonate mineralization that may lead to useful products (e.g., secondary construction materials), including environmental barriers such as the consequences of large mining operations and the disposal of carbonates.

Support research and development pathways for the development of novel catalysts using abundant materials and advanced manufacturing techniques to produce nanocatalysts to bring down costs.

Support RD&D on subsea separation and improved mobility control. Map opportunities, conduct technology readiness assessments, and resolve main barriers for the

implementation of the CO2 utilization family of technologies including benchmarked life cycle assessments and CO2 and energy balances.

Increase the understanding of CO2 energy balances for each potential CO2 reuse pathway and the energy requirement of each technology using technological modeling.

Towards 2025: Governments and industry should work together to:

On capture

Fund and facilitate cross-border RD&D cooperation to bring to demonstration CO2 capture technologies for power generation and industrial applications that have avoided cost in $/tCO2

(or capture cost) at least 40% below that of 2016 commercial technologies, while at the same time minimizing environmental impacts.

Fund promising CO2 capture technology ideas to be tested and verified at pilot scale (megawatt range) and/or separating 0.01–0.1 Mt CO2/year.

On transport and infrastructure

Implement the first large-scale (i.e., >10 Mt CO2/year aggregate throughput) CCS chains in power, industrial, and bio-CCS. These should be focused in industrial regions that have the potential to share infrastructure, rather than focusing on individual projects.

Implement initial shared infrastructure for a limited number of plants within industrial clusters. This should recognize that in the initial phases, volumes within these clusters may be less than one million tonnes per annum, but that expansion from this initial start will occur.

On storage

Facilitate exploration, characterization, and qualification of large-scale CO2 storage sites (10–100 million tons CO2 per year) in key regions of the world, building on experience from current projects and pilots and including use of existing oil and gas infrastructure.

Facilitate qualification of CO2 storage sites for safe and long-term storage in the scale of tens of millions of tonnes of CO2 annually per storage site, linked to clusters of CO2 transport systems.

Ensure that all CSLF member countries have national storage assessments publicly available, Continue the development and execution of E&A portfolio programs in key potential storage

basins.

21 Refers to § 45Q of the US Internal Revenue Code, which allows for tax credits of $20 per metric tonne of qualified carbon dioxide stored and $10 per metric tonne used for EOR, captured by the taxpayer at a qualified facility. As of September 2017, there are proposals in the US Congress to increase these credits.

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Develop robust conceptual workflow to assure regulators that site characterization meets international leading practice.

Reduce monitoring and verification (M&V) overall costs by 25% in average from 2016 levels.

On utilization

Promote more offshore CO2-EOR pilot projects as part of deployment of large-scale CO2 storage, as CO2 becomes available in amounts and during time windows relevant for EOR.

Towards 2035: Governments and industry should work together to:

On capture

Encourage and facilitate cross-border RD&D cooperation to bring to demonstration CO2 capture technologies for power generation and industrial applications that capture 100% (or very close to 100%) of the CO2 and at the same time achieve 50% reduction of avoided carbon cost in $/tCO2 (or capture cost) compared to 2016 commercial technologies, while minimizing environmental impacts.

Gain experience in the integration of power plants with CCS into electricity grids that utilize renewable energy sources, seeking to develop optimal hybrid concepts with zero or negative emissions.

On transport and infrastructure

Continue progressive rollout and expansion of full-scale CCS chains and clusters in power, industrial, and bio-CCS. This includes large-scale CO2 transport networks that integrate CO2 capture, transport, and storage, including matching of sources and sinks.

On storage

Reduce M&V costs by 40% from 2015 levels.

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UNIDO (United Nations Industrial Development Organization). 2010. Carbon Capture and Storage in Industrial Applications. Technical Synthesis Report Working Paper – November 2010. https://www.unido.org/fileadmin/user_media/Services/Energy_and_Climate_Change/Energy_Efficiency/CCS/synthesis_final.pdf.

Vermeulen, T. 2011. Knowledge sharing report – CO2 liquid logistics shipping concept (LLSC): overall supply chain optimization. GCCSI. June. https://www.globalccsinstitute.com/publications/co2-liquid-logistics-shipping-concept-llsc-overall-supply-chain-optimization.

Voldsund, M., K. Jordal, and R. Anantharaman. 2016. “Hydrogen production with CO2 capture.” International Journal of Hydrogen Energy 41: 4969–4992. http://www.sciencedirect.com/science/article/pii/S0360319915312659.

Williamson, P. 2016. “Scrutinize CO2 removal method.” Nature 530: 153–155. http://www.nature.com/polopoly_fs/1.19318!/menu/main/topColumns/topLeftColumn/pdf/530153a.pdf.

WRI (World Resources Institute). 2016. “Carbon Capture and Storage: prospects after Paris.” Written by Katie Lebling and Xiaoliang Yang for WRI. World Resources Institute (website). 19 April. http://www.wri.org/blog/2016/04/carbon-capture-and-storage-prospects-after-paris.

ZEP (European Technology Platform for Zero Emission Fossil Fuel Power Plants). 2013a. CO2 capture and storage (CCS) in energy intensive industries: An indispensable route to an EU low-carbon economy. 7 January. http://www.zeroemissionsplatform.eu/news/news/1601-zep-publishes-key-report-on-ccs-in-eu-energy-intensive-industries.html.

. 2013b. Building a CO2 transport infrastructure for Europe. http://www.zeroemissionsplatform.eu/news/news/1610-eu-must-urgently-invest-25-billion-in-co2-transport-infrastructure.html.

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CSLF Technology Roadmap 2017 www.cslforum.org

. 2016b. Carbon Capture and Utilisation. http://www.zeroemissionsplatform.eu/library/publication/272-cleanhydrogen.html.

. 2017a. Future CCS Technologies. January. http://www.zeroemissionsplatform.eu/news/news/1665-zep-publishes-future-ccs-technologies-report.html.

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Active and Completed CSLF Recognized Projects (as of November 2017)

1. Air Products CO2 Capture from Hydrogen Facility Project

Nominators: United States (lead), Netherlands, and United Kingdom This is a large-scale commercial project, located in eastern Texas in the United States, which will demonstrate a state-of-the-art system to concentrate CO2 from two steam methane reformer (SMR) hydrogen production plants, and purify the CO2 to make it suitable for sequestration by injection into an oil reservoir as part of an ongoing CO2 Enhanced Oil Recovery (EOR) project. The commercial goal of the project is to recover and purify approximately 1 million tonnes per year of CO2 for pipeline transport to Texas oilfields for use in EOR. The technical goal is to capture at least 75% of the CO2 from a treated industrial gas stream that would otherwise be emitted to the atmosphere. A financial goal is to demonstrate real-world CO2 capture economics. Recognized by the CSLF at its Perth meeting, October 2012

2. Alberta Carbon Trunk Line

Nominators: Canada (lead) and United States This large-scale fully-integrated 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 240-kilometer pipeline to depleted hydrocarbon reservoirs in central Alberta for utilization and storage in EOR projects. The pipeline is designed for a capacity of 14.6 million tonnes CO2 per year although it is being initially licensed at 5.5 million tonnes per year. The pipeline route is expected to stimulate EOR development in Alberta and may eventually lead to a broad CO2 pipeline network throughout central and southern Alberta. Recognized by the CSLF at its Washington meeting, November 2013

3. Alberta Enhanced Coal-Bed Methane Recovery Project (Completed)

Nominators: Canada (lead), United Kingdom, and United States This pilot-scale project, located in Alberta, Canada, demonstrated, from economic and environmental criteria, the overall feasibility of coal bed methane production and simultaneous CO2 storage in deep unmineable coal seams. Specific objectives of the project were to determine baseline production of CBM from coals; determine the effect of CO2 injection and storage on CBM production; assess economics; and monitor and trace the path of CO2 movement by geochemical and geophysical methods. All testing undertaken was successful, with one important conclusion being that flue gas injection appears to enhance methane production to a greater degree possible than with CO2 while still sequestering CO2, albeit in smaller quantities. Recognized by the CSLF at its Melbourne meeting, September 2004

4. Al Reyadah CCUS Project Nominators: United Arab Emirates (lead), Australia, Canada, China, Netherlands, Norway, Saudi Arabia, South Africa, United Kingdom, and United States This is an integrated commercial-scale project, located in Mussafah, Abu Dhabi, United Arab Emirates, which is capturing CO2 from the flue gas of an Emirates Steel

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production facility, and injecting the CO2 for enhanced oil recovery (EOR) in the Abu Dhabi National Oil Company’s nearby oil fields. The main objectives are to reduce the carbon footprint of the United Arab Emirates, implement EOR in subsurface oil reservoirs, and free up natural gas which would have been used for oil field pressure maintenance. The Al Reyadah Project includes capture, transport and injection of up to 800,000 tonnes per year of CO2 (processed at the required specifications and pressure) and is part of an overall master plan which could also create a CO2 network and hub for managing future CO2 supply and injection requirements in the United Arab Emirates. Recognized by the CSLF at its Abu Dhabi meeting, May 2017

5. CANMET Energy Oxyfuel Project (Completed) Nominators: Canada (lead) and United States This was a pilot-scale project, located in Ontario, Canada, that demonstrated oxyfuel combustion technology with CO2 capture. The project focus was on energy-efficient integrated multi-pollutant control, waste management and CO2 capture technologies for combustion-based applications and to provide information for the scale-up, design and operation of large-scale industrial and utility plants based on the oxyfuel concept. The project concluded when the consortium members deemed that the overall status of oxyfuel technology had reached the level of maturity needed for pre-commercial field demonstration. The project successfully laid the foundation for new research at CANMET on novel near-zero emission power generation technologies using pressurized oxyfuel combustion and advanced CO2 turbines. Recognized by the CSLF at its Melbourne meeting, September 2004

6. Carbon Capture and Utilization Project / CO2 Network Project

Nominators: Saudi Arabia (lead) and South Africa This is a large-scale CO2 utilization project, including approx. 25 kilometers of pipeline infrastructure, which captures and purifies CO2 from an existing ethylene glycol production facility located in Jubail, Saudi Arabia. More than 1,500 tonnes of CO2 per day will be captured and transported via pipeline, for utilization mainly as a feedstock for production of methanol, urea, oxy-alcohols, and polycarbonates. Food-grade CO2 is also a product, and the CO2 pipeline network can be further expanded as opportunities present themselves. Recognized by the CSLF at its Riyadh meeting, November 2015

7. Carbon Capture Simulation Initiative / Carbon Capture Simulation for Industry Impact (CCSI/CCSI2) Nominators: United States (lead), China, France, and Norway This is a computational research initiative, with activities ongoing at NETL, four other National Laboratories, and five universities across the United States, with collaboration from other organizations outside the United States including industry partners. The overall objective is to develop and utilize an integrated suite of computational tools (the CCSI Toolset) in order to support and accelerate the development, scale-up and commercialization of CO2 capture technologies. The anticipated outcome is a significant reduction in the time that it takes to develop and scale-up new technologies in the energy sector. CCSI2 will apply the CCSI toolset, in partnership with industry, in the scale-up of new and innovative CO2 capture technologies. A major focus of CCSI2 will be on model validation using the large-scale pilot test information from projects around the world to help predict design and operational performance at all scales including commercial demonstrations. These activities will help maximize the learning that occurs at each scale during technology development. Recognized by the CSLF at its Abu Dhabi meeting, May 2017

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8. CarbonNet Project Nominators: Australia (lead) and United States This is a large-scale project that will implement a large-scale multi-user CO2 capture, transport, and storage network in southeastern Australia in the Latrobe Valley. Multiple industrial and utility point sources of CO2 will be connected via a pipeline to a site where the CO2 can be stored in saline aquifers in the Gippsland Basin. The project initially plans to sequester approximately 1 to 5 million tonnes of CO2 per year, with the potential to increase capacity significantly over time. The project will also include reservoir characterization and, once storage is underway, measurement, monitoring and verification (MMV) technologies. Recognized by the CSLF at its Perth meeting, October 2012

9. CASTOR (Completed)

Nominators: European Commission (lead), France, and Norway This was a multifaceted project that had activities at various sites in Europe, in three main areas: strategy for CO2 reduction, post-combustion capture, and CO2 storage performance and risk assessment studies. The goal was to reduce the cost of post-combustion CO2 capture and to develop and validate, in both public and private partnerships, all the innovative technologies needed to capture and store CO2 in a reliable and safe way. The tests showed the reliability and efficiency of the post-combustion capture process. Recognized by the CSLF at its Melbourne meeting, September 2004

10. CCS Rotterdam Project

Nominators: Netherlands (lead) and Germany This project will implement a large-scale “CO2 Hub” for capture, transport, utilization, and storage of CO2 in the Rotterdam metropolitan area. The project is part of the Rotterdam Climate Initiative (RCI), which has a goal of reducing Rotterdam’s CO2 emissions by 50% by 2025 (as compared to 1990 levels). A “CO2 cluster approach” will be utilized, with various point sources (e.g., CO2 captured from power plants) connected via a hub / manifold arrangement to multiple storage sites such as depleted gas fields under the North Sea. This will reduce the costs for capture, transport and storage compared to individual CCS chains. The project will also work toward developing a policy and enabling framework for CCS in the region. Recognized by the CSLF at its London meeting, October 2009

11. CGS Europe Project (Completed)

Nominators: Netherlands (lead) and Germany This was a collaborative venture, involving 35 partners from participant countries in Europe, with extensive structured networking, knowledge transfer, and information exchange. A goal of the project was to create a durable network of experts in CO2 geological storage and a centralized knowledge base which will provide an independent source of information for European and international stakeholders. The CGS Europe Project provided an information pathway toward large-scale implementation of CO2 geological storage throughout Europe. This was a three-year project, started in November 2011, and received financial support from the European Commission’s 7th Framework Programme (FP7). Recognized by the CSLF at its Beijing meeting, September 2011

12. China Coalbed Methane Technology/CO2 Sequestration Project (Completed)

Nominators: Canada (lead), United States, and China This pilot-scale project successfully demonstrated that coal seams in the anthracitic

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coals of Shanxi Province of China are permeable and stable enough to absorb CO2 and enhance methane production, leading to a clean energy source for China. The project evaluated reservoir properties of selected coal seams of the Qinshui Basin of eastern China and carried out field testing at relatively low CO2 injection rates. The project recommendation was to proceed to full scale pilot test at south Qinshui, as the prospect in other coal basins in China is good. Recognized by the CSLF at its Berlin meeting, September 2005

13. CO2 Capture Project – Phase 2 (Completed)

Nominators: United Kingdom (lead), Italy, Norway, and United States This pilot-scale project continued the development of new technologies to reduce the cost of CO2 separation, capture, and geologic storage from combustion sources such as turbines, heaters and boilers. These technologies will be applicable to a large fraction of CO2 sources around the world, including power plants and other industrial processes. The ultimate goal of the entire project was to reduce the cost of CO2 capture from large fixed combustion sources by 20-30%, while also addressing critical issues such as storage site/project certification, well integrity and monitoring. Recognized by the CSLF at its Melbourne meeting, September 2004

14. CO2 Capture Project – Phase 3 (Completed)

Nominators: United Kingdom (lead) and United States This was a collaborative venture of seven partner companies (international oil and gas producers) plus the Electric Power Research Institute. The overall goals of the project were to increase technical and cost knowledge associated with CO2 capture technologies, to reduce CO2 capture costs by 20-30%, to quantify remaining assurance issues surrounding geological storage of CO2, and to validate cost-effectiveness of monitoring technologies. The project was comprised of four areas: CO2 Capture; Storage Monitoring & Verification; Policy & Incentives; and Communications. A fifth activity, in support of these four teams, was Economic Modeling. This third phase of the project included field demonstrations of CO2 capture technologies and a series of monitoring field trials in order to obtain a clearer understanding of how to monitor CO2 in the subsurface. Third phase activities began in 2009 and continued into 2014. Recognized by the CSLF at its Beijing meeting, September 2011

15. CO2 Capture Project – Phase 4

Nominators: United Kingdom (lead), Canada, and United States This multistage project is a continuance of CCP3, with the goal is to further increase understanding of existing, emerging, and breakthrough CO2 capture technologies applied to oil and gas application scenarios (now including separation from natural gas), along with verification of safe and secure storage of CO2 in the subsurface (now including utilization for enhanced oil recovery). The overall goal is to advance the technologies which will underpin the deployment of industrial-scale CO2 capture and storage. Phase 4 of the project will extend through the year 2018 and includes four work streams: storage monitoring and verification; capture; policy & incentives; and communications. Recognized by the CSLF at its Riyadh meeting, November 2015

16. CO2CRC Otway Project Stage 1 (Completed) Nominators: Australia (lead) and United States This is a pilot-scale project, located in southwestern Victoria, Australia, that involves transport and injection of approximately 100,000 tons of CO2 over a two year period into a depleted natural gas well. Besides the operational aspects of processing,

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transport and injection of a CO2-containing gas stream, the project also includes development and testing of new and enhanced monitoring, and verification of storage (MMV) technologies, modeling of post-injection CO2 behavior, and implementation of an outreach program for stakeholders and nearby communities. Data from the project will be used in developing a future regulatory regime for CO2 capture and storage (CCS) in Australia. Recognized by the CSLF at its Paris meeting, March 2007

17. CO2CRC Otway Project Stage 2 Nominators: Australia (lead) and United States This is a continuance of the Otway Stage 1 pilot project. The goal of this second stage is to increase the knowledge base for CO2 storage in geologic deep saline formations through seismic visualization of injected CO2 migration and stabilization. Stage 2 of the overall project will extend into the year 2020 and will include sequestration of approx. 15,000 tonnes of CO2. The injected plume will be observed from injection through to stabilization, to assist in the calibrating and validation of reservoir modelling’s predictive capability. An anticipated outcome from the project will be improvement on methodologies for the characterization, injection and monitoring of CO2 storage in deep saline formations. Recognized by the CSLF at its Riyadh meeting, November 2015

18. CO2 Field Lab Project (Completed) Nominators: Norway (lead), France, and United Kingdom This was a pilot-scale project, located at Svelvik, Norway, which investigated CO2 leakage characteristics in a well-controlled and well-characterized permeable geological formation. The main objective was to obtain important knowledge about monitoring CO2 migration and leakage. Relatively small amounts of CO2 were injected to obtain underground distribution data that resemble leakage at different depths. The resulting underground CO2 distribution, which resembled leakages, was monitored with an extensive set of methods deployed by the project partners. The outcomes from this project will help facilitate commercial deployment of CO2 storage by providing the protocols for ensuring compliance with regulations, and will help assure the public about the safety of CO2 storage by demonstrating the performance of monitoring systems. Recognized by the CSLF at its Warsaw meeting, October 2010

19. CO2 GeoNet

Nominators: European Commission (lead) and United Kingdom This multifaceted project is focused on geologic storage options for CO2 as a greenhouse gas mitigation option, and on assembling an authoritative body for Europe on geologic sequestration. Major objectives include formation of a partnership consisting, at first, of 13 key European research centers and other expert collaborators in the area of geological storage of CO2, identification of knowledge gaps in the long-term geologic storage of CO2, and formulation of new research projects and tools to eliminate these gaps. This project will result in re-alignment of European national research programs and prevention of site selection, injection operations, monitoring, verification, safety, environmental protection, and training standards. Recognized by the CSLF at its Berlin meeting, September 2005

20. CO2 Separation from Pressurized Gas Stream

Nominators: Japan (lead) and United States This is a small-scale project that will evaluate processes and economics for CO2

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separation from pressurized gas streams. The project will evaluate primary promising new gas separation membranes, initially at atmospheric pressure. A subsequent stage of the project will improve the performance of the membranes for CO2 removal from the fuel gas product of coal gasification and other gas streams under high pressure. Recognized by the CSLF at its Melbourne meeting, September 2004

21. CO2 STORE (Completed)

Nominators: Norway (lead) and European Commission This project, a follow-on to the Sleipner project, involved the monitoring of CO2 migration (involving a seismic survey) in a saline formation beneath the North Sea and additional studies to gain further knowledge of geochemistry and dissolution processes. There were also several preliminary feasibility studies for additional geologic settings of future candidate project sites in Denmark, Germany, Norway, and the United Kingdom. The project was successful in developing sound scientific methodologies for the assessment, planning, and long-term monitoring of underground CO2 storage, both onshore and offshore. Recognized by the CSLF at its Melbourne meeting, September 2004

22. CO2 Technology Centre Mongstad Project

Nominators: Norway (lead) and Netherlands This is a large-scale project (100,000 tonnes per year CO2 capacity) that will establish a facility for parallel testing of amine-based and chilled ammonia CO2 capture technologies from two flue gas sources with different CO2 contents. The goal of the project is to reduce cost and technical, environmental, and financial risks related to large scale CO2 capture, while allowing evaluation of equipment, materials, process configurations, different capture solvents, and different operating conditions. The project will result in validation of process and engineering design for full-scale application and will provide insight into other aspects such as thermodynamics, kinetics, engineering, materials of construction, and health / safety / environmental. Recognized by the CSLF at its London meeting, October 2009

23. Demonstration of an Oxyfuel Combustion System (Completed)

Nominators: United Kingdom (lead) and France This project, located at Renfrew, Scotland, UK, demonstrated oxyfuel technology on a full-scale 40-megawatt burner. The goal of the project was to gather sufficient data to establish the operational envelope of a full-scale oxyfuel burner and to determine the performance characteristics of the oxyfuel combustion process at such a scale and across a range of operating conditions. Data from the project is input for developing advanced computer models of the oxyfuel combustion process, which will be utilized in the design of large oxyfuel boilers. Recognized by the CSLF at its London meeting, October 2009

24. Dry Solid Sorbent CO2 Capture Project Nominators: Korea (lead), and United Kingdom This is a pilot-scale project, located in southern Korea, which is demonstrating capture of CO2 from a 10 megawatt power plant flue gas slipstream, using a potassium carbonate-based solid sorbent. The overall goal is to demonstrate the feasibility of dry solid sorbent capture while improving the economics (target: US$40 per ton CO2 captured). The project will extend through most of the year 2017. There will be 180 days continuous operation each year with capture of approx. 200 tons CO2 per day at more than 95% CO2 purity. Recognized by the CSLF at its Riyadh meeting, November 2015

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25. Dynamis (Completed) Nominators: European Commission (lead), and Norway This was the first phase of the multifaceted European Hypogen program, which was intended to lay the groundwork for a future advanced commercial-scale power plant with hydrogen production and CO2 management. The Dynamis project assessed the various options for large-scale hydrogen production while focusing on the technological, economic, and societal issues. Recognized by the CSLF at its Cape Town meeting, April 2008

26. ENCAP (Completed)

Nominators: European Commission (lead), France, and Germany This multifaceted research project consisted of six sub-projects: Process and Power Systems, Pre-Combustion Decarbonization Technologies, O2/CO2 Combustion (Oxy- fuel) Boiler Technologies, Chemical Looping Combustion (CLC), High-Temperature Oxygen Generation for Power Cycles, and Novel Pre-Combustion Capture Concepts. The goals were to develop promising pre-combustion CO2 capture technologies (including O2/CO2 combustion technologies) and propose the most competitive demonstration power plant technology, design, process scheme, and component choices. All sub-projects were successfully completed by March 2009. Recognized by the CSLF at its Berlin meeting, September 2005

27. Fort Nelson Carbon Capture and Storage Project Nominators: Canada (lead) and United States This is a large-scale project in northeastern British Columbia, Canada, which will permanently sequester approximately two million tonnes per year CO2 emissions from a large natural gas-processing plant into deep saline formations of the Western Canadian Sedimentary Basin (WCSB). Goals of the project are to verify and validate the technical and economic feasibility of using brine-saturated carbonate formations for large-scale CO2 injection and demonstrate that robust monitoring, verification, and accounting (MVA) of a brine-saturated CO2 sequestration project can be conducted cost-effectively. The project will also develop appropriate tenure, regulations, and MVA technologies to support the implementation of future large-scale sour CO2 injection into saline-filled deep carbonate reservoirs in the northeast British Columbia area of the WCSB. Recognized by the CSLF at its London meeting, October 2009

28. Frio Project (Completed)

Nominators: United States (lead) and Australia This pilot-scale project demonstrated the process of CO2 sequestration in an on-shore underground saline formation in the eastern Texas region of the United States. This location was ideal, as very large scale sequestration may be needed in the area to significantly offset anthropogenic CO2 releases. The project involved injecting relatively small quantities of CO2 into the formation and monitoring its movement for several years thereafter. The goals were to verify conceptual models of CO2 sequestration in such geologic structures; demonstrate that no adverse health, safety or environmental effects will occur from this kind of sequestration; demonstrate field-test monitoring methods; and develop experience necessary for larger scale CO2 injection experiments. Recognized by the CSLF at its Melbourne meeting, September 2004

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29. Geologic CO2 Storage Assurance at In Salah, Algeria Nominators: United Kingdom (lead) and Norway This multifaceted project will develop the tools, technologies, techniques and management systems required to cost-effectively demonstrate, safe, secure, and verifiable CO2 storage in conjunction with commercial natural gas production. The goals of the project are to develop a detailed dataset on the performance of CO2 storage; provide a field-scale example on the verification and regulation of geologic storage systems; test technology options for the early detection of low-level seepage of CO2 out of primary containment; evaluate monitoring options and develop guidelines for an appropriate and cost-effective, long-term monitoring methodology; and quantify the interaction of CO2 re-injection and hydrocarbon production for long-term storage in oil and gas fields. Recognized by the CSLF at its Berlin meeting, September 2005

30. Gorgon CO2 Injection Project

Nominators: Australia (lead), Canada, and United States This is a large-scale project that will store approximately 120 million tonnes of CO2 in a water-bearing sandstone formation two kilometers below Barrow Island, off the northwest coast of Australia. The CO2 stored by the project will be extracted from natural gas being produced from the nearby Gorgon Field and injected at approximately 3.5 to 4 million tonnes per year. There is an extensive integrated monitoring plan, and the objective of the project is to demonstrate the safe commercial-scale application of greenhouse gas storage technologies at a scale not previously attempted. Recognized by the CSLF at its Warsaw meeting, October 2010

31. IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project (Completed) Nominators: Canada and United States (leads) and Japan This was a monitoring activity for a large-scale project that utilizes CO2 for enhanced oil recovery (EOR) at a Canadian oil field. The goal of the project was to determine the performance and undertake a thorough risk assessment of CO2 storage in conjunction with its use in enhanced oil recovery. The work program encompassed four major technical themes of the project: geological integrity; wellbore injection and integrity; storage monitoring methods; and risk assessment and storage mechanisms. Results from these technical themes, integrated with policy research, were incorporated into a Best Practices Manual for future CO2 Enhanced Oil Recovery projects. Recognized by the CSLF at its Melbourne meeting, September 2004

32. Illinois Basin – Decatur Project

Nominators: United States (lead) and United Kingdom This is a large-scale research project that will geologically store up to 1 million metric tons of CO2 over a 3-year period. The CO2 is being captured from the fermentation process used to produce ethanol at an industrial corn processing complex in Decatur, Illinois, in the United States. After three years, the injection well will be sealed and the reservoir monitored using geophysical techniques. Monitoring, verification, and accounting (MVA) efforts include tracking the CO2 in the subsurface, monitoring the performance of the reservoir seal, and continuous checking of soil, air, and groundwater both during and after injection. The project focus is on demonstration of CCS project development, operation, and implementation while demonstrating CCS technology and reservoir quality. Recognized by the CSLF at its Perth meeting, October 2012

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33. Illinois Industrial Carbon Capture and Storage Project Nominators: United States (lead) and France This is a large-scale commercial project that will collect up to 3,000 tonnes per day of CO2 for deep geologic storage. The CO2 is being captured from the fermentation process used to produce ethanol at an industrial corn processing complex in Decatur, Illinois, in the United States. The goals of the project are to design, construct, and operate a new CO2 collection, compression, and dehydration facility capable of delivering up to 2,000 tonnes of CO2 per day to the injection site; to integrate the new facility with an existing 1,000 tonnes of CO2 per day compression and dehydration facility to achieve a total CO2 injection capacity of 3,000 tonnes per day (or one million tonnes annually); to implement deep subsurface and near-surface MVA of the stored CO2; and to develop and conduct an integrated community outreach, training, and education initiative. Recognized by the CSLF at its Perth meeting, October 2012

34. ITC CO2 Capture with Chemical Solvents Project

Nominators: Canada (lead) and United States This is a pilot-scale project that will demonstrate CO2 capture using chemical solvents. Supporting activities include bench and lab-scale units that will be used to optimize the entire process using improved solvents and contactors, develop fundamental knowledge of solvent stability, and minimize energy usage requirements. The goal of the project is to develop improved cost-effective technologies for separation and capture of CO2 from flue gas. Recognized by the CSLF at its Melbourne meeting, September 2004

35. Jingbian CCS Project

Nominators: China (lead) and Australia This integrated large-scale pilot project, located at a coal-to-chemicals company in the Ordos Basin of China’s Shaanxi Province, is capturing CO2 from a coal gasification plant via a commercial chilled methanol process, transporting the CO2 by tanker truck to a nearby oil field, and utilizing the CO2 for EOR. The overall objective is to demonstrate the viability of a commercial EOR project in China. The project includes capture and injection of up to about 50,000 tonnes per year of CO2. There will also be a comprehensive MMV regime for both surface and subsurface monitoring of the injected CO2. This project is intended to be a model for efficient exploitation of Shaanxi Province’s coal and oil resources, as it is estimated that more than 60% of stationary source CO2 emissions in the province could be utilized for EOR. Recognized by the CSLF at its Regina meeting, June 2015

36. Kemper County Energy Facility

Nominators: United States (lead) and Canada This commercial-scale CCS project, located in east-central Mississippi in the United States, will capture approximately 3 million tonnes of CO2 per year from integrated gasification combined cycle (IGCC) power plant, and will include pipeline transportation of approximately 60 miles to an oil field where the CO2 will sold for enhanced oil recovery (EOR). The commercial objectives of the project are large-scale demonstration of a next-generation gasifier technology for power production and utilization of a plentiful nearby lignite coal reserve. Approximately 65% of the CO2 produced by the plant will be captured and utilized. Recognized by the CSLF at its Washington meeting, November 2013

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37. Ketzin Test Site Project (formerly CO2 SINK) (Completed) Nominators: European Commission (lead) and Germany This is a pilot-scale project that tested and evaluated CO2 capture and storage at an existing natural gas storage facility and in a deeper land-based saline formation. A key part of the project was monitoring the migration characteristics of the stored CO2. The project was successful in advancing the understanding of the science and practical processes involved in underground storage of CO2 and provided real case experience for use in development of future regulatory frameworks for geological storage of CO2. Recognized by the CSLF at its Melbourne meeting, September 2004

38. Lacq Integrated CCS Project (Completed)

Nominators: France (lead) and Canada This was an intermediate-scale project that tested and demonstrated an entire integrated CCS process, from emissions source to underground storage in a depleted gas field. The project captured and stored 60,000 tonnes per year of CO2 for two years from an oxyfuel industrial boiler in the Lacq industrial complex in southwestern France. The goal was demonstrate the technical feasibility and reliability of the integrated process, including the oxyfuel boiler, at an intermediate scale and also included geological storage qualification methodologies, as well as monitoring and verification techniques, to prepare for future larger-scale long term CO2 storage projects. Recognized by the CSLF at its London meeting, October 2009

39. Michigan Basin Development Phase Project

Nominators: United States (lead) and Canada This is a large-scale CO2 storage project, located in Michigan and nearby states in the northern United States that will, over its four-year duration, inject a total of one million tonnes of CO2 into different types of oil and gas fields in various lifecycle stages. The project will include collection of fluid chemistry data to better understand geochemical interactions, development of conceptual geologic models for this type of CO2 storage, and a detailed accounting of the CO2 injected and recycled. Project objectives are to assess storage capacities of these oil and gas fields, validate static and numerical models, identify cost-effective monitoring techniques, and develop system-wide information for further understanding of similar geologic formations. Results obtained during this project are expected to provide a foundation for validating that CCS technologies can be commercially deployed in the northern United States. Recognized by the CSLF at its Washington meeting, November 2013

40. National Risk Assessment Partnership (NRAP) Nominators: United States (lead), Australia, China, and France This is a risk assessment initiative, with activities ongoing at NETL and four other National Laboratories across the United States, including collaboration with industry, regulatory organizations, and other types of stakeholders. The overall objective is development of defensible, science-based methodologies and tools for quantifying leakage and seismic risks for long-term CO2 geologic storage. The anticipated outcome is removal of key barriers to the business case for CO2 storage by providing the technical basis for quantifying long-term liability. To that end, NRAP has developed and released a series of computational tools (the NRAP toolset) that are being used by a diverse set of stakeholders around the world. The toolset is expected to help storage site operators design and apply monitoring and mitigation strategies, help regulators and their agents quantify risks and perform cost-benefit analyses for specific CCS projects, and provide a basis for financiers and regulators to invest in and approve CCS projects with greater confidence because costs long-term liability can be estimated more easily

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and with greater certainty. Recognized by the CSLF at its Abu Dhabi meeting, May 2017

41. Norcem CO2 Capture Project (Completed) Nominators: Norway (lead) and Germany This project, located in southern Norway at a commercial cement production facility, conducted testing of four different post-combustion CO2 capture technologies at scales ranging from very small pilot to small pilot. Technologies evaluated were a 1st generation amine-based solvent, a 3rd generation solid sorbent, 3rd generation gas separation membranes, and a 2nd generation regenerative calcium cycle, all using cement production facility flue gas. Objectives of the project were to determine the long-term attributes and performance of these technologies in a real-world industrial setting and to learn the suitability of such technologies for implementation in modern cement kiln systems. Focal areas included CO2 capture rates, energy consumption, impact of flue gas impurities, space requirements, and projected CO2 capture costs. Recognized by the CSLF at its Warsaw meeting, October 2014

42. NET Power 50 MWth Allam Cycle Demonstration Project Nominators: United States (lead), Japan, Saudi Arabia, and United Kingdom This is a capture-only large-scale pilot project, located in La Porte, Texas in the United States, whose overall objective is to demonstrate the performance of the Allam power cycle. The Allam Cycle is a next-generation gas turbine-derived power cycle that uses high-pressure CO2 instead of steam to produce power at low cost and with no atmospheric emissions. The project includes construction and operation of a 50 MWth natural gas-fueled pilot plant and also design of a much larger proposed commercial-scale project. The anticipated outcome of the project is verification of the performance of the Allam Cycle, its control system and components, and purity of the produced CO2 with learnings being used in the design of a future commercial-scale project using this technology. Recognized by the CSLF at its Tokyo meeting, October 2016

43. Oxy-Combustion of Heavy Liquid Fuels Project Nominators: Saudi Arabia (lead) and United States This is a large pilot project (approx. 30-60 megawatts in scale), located in Dhahran, Saudi Arabia whose goals are to investigate the performance of oxy-fuel combustion technology when firing difficult-to-burn liquid fuels such as asphalt, and to assess the operation and performance of the CO2 capture unit of the project. The project will build on knowledge from a 15 megawatt oxy-combustion small pilot that was operated in the United States by Alstom. An anticipated outcome from the project will be identifying and overcoming scale-up and bottleneck issues as a step toward future commercialization of the technology. Recognized by the CSLF at its Riyadh meeting, November 2015

44. Quest CCS Project Nominators: Canada (lead), United Kingdom, and United States This is a large-scale project, located at Fort Saskatchewan, Alberta, Canada, with integrated capture, transportation, storage, and monitoring, which will capture and store up to 1.2 million tonnes per year of CO2 from an oil sands upgrading unit. The CO2 will be transported via pipeline and stored in a deep saline aquifer in the Western Sedimentary Basin in Alberta, Canada. This is a fully integrated project, intended to significantly reduce the carbon footprint of the commercial oil sands upgrading facility

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while developing detailed cost data for projects of this nature. This will also be a large-scale deployment of CCS technologies and methodologies, including a comprehensive measurement, monitoring and verification (MMV) program. Recognized by the CSLF at its Warsaw meeting, October 2010

45. Plant Barry Integrated CCS Project (Completed)

Nominators: United States (lead), Japan, and Canada This pilot-scale fully-integrated CCS project, located in southeastern Alabama in the United States, brought together components of CO2 capture, transport, and geologic storage, including monitoring, verification, and accounting of the stored CO2. A flue gas slipstream from a power plant equivalent to 25 megawatts of power production was used to demonstrate a new amine-based process for capture of approximately 550 tons of CO2 per day. A 19 kilometer pipeline transported the CO2 to a deep saline storage site. The project successfully met its objectives of gaining knowledge and experience in operation of a fully integrated CCS large-scale process, conducting reservoir modeling and test CO2 storage mechanisms for the types of geologic storage formations that exist along the Gulf Coast of the United States, and testing CO2 monitoring technologies. The CO2 capture technology utilized in the project is now being used at commercial scale. Recognized by the CSLF at its Washington meeting, November 2013

46. Regional Carbon Sequestration Partnerships Nominators: United States (lead) and Canada This multifaceted project will identify and test the most promising opportunities to implement sequestration technologies in the United States and Canada. There are seven different regional partnerships, each with their own specific program plans, which will conduct field validation tests of specific sequestration technologies and infrastructure concepts; refine and implement (via field tests) appropriate measurement, monitoring and verification (MMV) protocols for sequestration projects; characterize the regions to determine the technical and economic storage capacities; implement and continue to research the regulatory compliance requirements for each type of sequestration technology; and identify commercially available sequestration technologies ready for large-scale deployment. Recognized by the CSLF at its Berlin meeting, September 2005

47. Regional Opportunities for CO2 Capture and Storage in China (Completed)

Nominators: United States (lead) and China This project characterized the technical and economic potential of CO2 capture and storage technologies in China. The goals were to compile key characteristics of large anthropogenic CO2 sources (including power generation, iron and steel plants, cement kilns, petroleum and chemical refineries, etc.) as well as candidate geologic storage formations, and to develop estimates of geologic CO2 storage capacities in China. The project found 2,300 gigatons of potential CO2 storage capacity in onshore Chinese basins, significantly more than previous estimates. Another important finding is that the heavily developed coastal areas of the East and South Central regions appear to have less access to large quantities of onshore storage capacity than many of the inland regions. These findings present the possibility for China’s continued economic growth with coal while safely and securely reducing CO2 emissions to the atmosphere. Recognized by the CSLF at its Berlin meeting, September 2005

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48. SaskPower Integrated CCS Demonstration Project at Boundary Dam Unit 3 Nominators: Canada (lead) and the United States This large-scale project, located in the southeastern corner of Saskatchewan Province in Canada, is the first application of full stream CO2 recovery from flue gas of a commercial coal-fueled power plant unit. A major goal is to demonstrate that a post-combustion CO2 capture retrofit on a commercial power plant can achieve optimal integration with the thermodynamic power cycle and with power production at full commercial scale. The project will result in capture of approximately one million tonnes of CO2 per year, which will be sold to oil producers for enhanced oil recovery (EOR) and injected into a deep saline aquifer. Recognized by the CSLF at its Beijing meeting, September 2011

49. SECARB Early Test at Cranfield Project

Nominators: United States (lead) and Canada This is a large-scale project, located in southwestern Mississippi in the United States, which involves transport, injection, and monitoring of approximately one million tonnes of CO2 per year into a deep saline reservoir associated with a commercial enhanced oil recovery operation, but the focus of this project will be on the CO2 storage and monitoring aspects. The project will promote the building of experience necessary for the validation and deployment of carbon sequestration technologies in the United States, and will increase technical competence and public confidence that large volumes of CO2 can be safely injected and stored. Components of the project also include public outreach and education, site permitting, and implementation of an extensive data collection, modeling, and monitoring plan. This “early” test will set the stage for a subsequent large-scale integrated project that will involve post-combustion CO2 capture, transportation via pipeline, and injection into a deep saline formation. Recognized by the CSLF at its Warsaw meeting, October 2010

50. South West Hub Project

Nominators: Australia (lead), United States, and Canada This is a large-scale project that will implement a large-scale “CO2 Hub” for multi-user capture, transport, utilization, and storage of CO2 in southwestern Australia near the city of Perth. Several industrial and utility point sources of CO2 will be connected via a pipeline to a site for safe geologic storage deep underground in the Triassic Lesueur Sandstone Formation. The project initially plans to sequester 2.4 million tonnes of CO2 per year and has the potential for capturing approximately 6.5 million tonnes of CO2 per year. The project will also include reservoir characterization and, once storage is underway, MMV technologies. Recognized by the CSLF at its Perth meeting, October 2012

51. Tomakomai CCS Demonstration Project

Nominators: Japan (lead), Australia, Canada, France, Norway, Saudi Arabia, United Kingdom, and United States This is an integrated large-scale pilot project, located at a refinery complex in Tomakomai city on the island of Hokkaido in Japan, which is capturing CO2 from the refinery’s hydrogen production unit with a steam methane reformer and a pressure swing adsorption process, and injecting the CO2 by two directional wells to the nearby offshore sub-seabed injection site. The overall objective is to demonstrate the technical viability of a full CCS system, from capture to injection and storage in saline aquifers. This will contribute to the establishment of CCS technology for practical use in Japan and set the stage for future deployments of commercial-scale CCS projects. The project includes capture and injection of up to about 100,000 tonnes per year of

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CO2 for three years and a comprehensive measurement, monitoring and verification (MMV) regime for the injected CO2. The project also includes a detailed public outreach effort which has engaged local stakeholders and increased community awareness about CCS and its benefits. Recognized by the CSLF at its Tokyo meeting, October 2016

52. Uthmaniyah CO2-EOR Demonstration Project

Nominators: Saudi Arabia (lead) and United States This large-scale project, located in the Eastern Province of 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 pipeline transportation of approximately 70 kilometers to the injection site (a small flooded area in the Uthmaniyah Field). The objectives of the project are determination of incremental oil recovery (beyond water flooding), estimation of sequestered CO2, addressing the risks and uncertainties involved (including migration of CO2 within the reservoir), and identifying operational concerns. Specific CO2 monitoring objectives include developing a clear assessment of the CO2 potential (for both EOR and overall storage) and testing new technologies for CO2 monitoring. Recognized by the CSLF at its Washington meeting, November 2013

53. Zama Acid Gas EOR, CO2 Sequestration, and Monitoring Project Nominators: Canada (lead) and United States This is a pilot-scale project that involves utilization of acid gas (approximately 70% CO2 and 30% hydrogen sulfide) derived from natural gas extraction for enhanced oil recovery. Project objectives are to predict, monitor, and evaluate the fate of the injected acid gas; to determine the effect of hydrogen sulfide on CO2 sequestration; and to develop a “best practices manual” for measurement, monitoring, and verification of storage (MMV) of the acid gas. Acid gas injection was initiated in December 2006 and will result in sequestration of about 25,000 tons (or 375 million cubic feet) of CO2 per year. Recognized by the CSLF at its Paris meeting, March 2007

--- Note: “Lead Nominator” in this usage indicates the CSLF Member which proposed the project.