Carbon Capture & Storage

SPECIAL ISSUE

ISSN: 2220 - 2765

CARBON Capture & Storage Workshop held at Texas A&M University at Qatar, April 2012 Guest Editor: Howard JM Hanley

Sustainable Technologies, Systems and Policies A Qatar Foundation Academic Journal Aims and Scope The journal publishes fundamental and applied research papers, reviews, problem statements and case studies in the primary areas of water and energy sustainability with a focus on sustainable generation, utilization and integrated resources management. The scope covers micro to macro levels in the development and implementation of sustainable solutions. Contributions fall into one of three themes: 1. Technologies associated with the sustainable generation, utilization, recovery, reuse and recycling.

The journal publishes papers on relevant scientific and technological advances, technology assessments and approaches to support technology development.

2. Integrated systems of multiple technical components to achieve sustainable generation, utilization, recovery, reuse and recycling. The scope of journal includes includes the areas of systems analysis, integration, design, operations and management.

3. Policy making and the translation of policies into regulations, legislation and governance mechanisms to enable the implementation of sustainable technologies and systems.

Within these areas the journal covers a broad range of topics including experimental work, testing, modelling, simulation, optimisation, design and development, monitoring and control, decision-making, integrated resources management, economics, environmental assessment, social impact assessment, policy, and regulations, legislation, and governance. The journal caters for inter-disciplinary contributions to reflect the scientific, technical, economical and social challenges involved in the development and implementation of sustainable solutions. The journal specifically excludes the field of sustainable buildings.

ISSN:2220-2765

Editor-in-chief Patrick Linke - Texas A&M University at Qatar, Doha, Qatar

Editorial board Ahmed Abdel-Wahab - Texas A&M University at Qatar, Doha, Qatar Hans Mueller-Steinhagen - Technical University of Dresden, Dresden, Germany Antonis Kokossis - National Technical University of Athens, Athens, Greece Nilay Shah - Imperial College, London, UK Rene Banares-Alcantara - University of Oxford, Oxford, UK Adisa Azapagic - University of Manchester, Manchester, UK Obaid Younossi - RAND Qatar Policy Institute, Doha, Qatar Raymond R Tan - De La Salle University, Manila, Philippines Nesreen Ghaddar - American University of Beirut, Beirut, Lebanon Eduardo Cleto Pires - University of Sao Paulo, Sao Paulo, Brazil Mahmoud El-Halwagi - Texas A&M University, College Station, USA Hideo Iwahashi - Mitsubishi Corporation, QSTP-B, Doha, Qatar

Proceedings of the Workshop on Carbon Capture & Storage held at Texas A&M University at Qatar, Doha, Qatar April 2-3, 2012 Editor: Howard J.M. Hanley Texas A&M University at Qatar, Doha, Qatar

Sponsored by:

Qatar National Research Fund

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Editorial

Preface and overview Howard JM Hanley Texas A&M University at Qatar, Doha, Qatar

http://dx.doi.org/ 10.5339/stsp.2012.ccs.1 Published: 17 December 2012 c 2012 Hanley, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

We organised this workshop because there is an opportunity for Qatar-based industry and academia to make a contribution to the Carbon Capture and Storage (CCS) issues that have recently attracted so much worldwide attention. ‘‘Qatar provides a vital source of hydrocarbon energy but must also lead in reducing the impacts of energy use on the environment,’’ acknowledged the HSE Regulations & Enforcement Division of Qatar Petroleum. The seed was the opening of the November 2010 First Annual Doha Carbon and Energy Forum at which Qatar Petroleum announced that it had officially submitted a proposal to the United Nations for a new methodology that could enable carbon dioxide capture and storage in geological formations to be part of the Clean Development Mechanism of the Kyoto Protocol.

The Workshop’s formal objective was to give an overview of the carbon capture technologies currently available, and to report on the status of current research, pilot projects, and technical innovations in the field. But we wanted the program to provide more than concrete information; we wanted a forum for debate, even controversy. The format was thus set up to juxtapose the industrial and academic viewpoints and to emphasize the questions and comments triggered by the invited talks. The essence of these is reported here as Discussion remarks, which follow the presentations.

We thank the speakers and the audience participants who put themselves out to ensure this approach worked.

Of course, the topic of carbon capture and storage has been covered extensively online and in the literature by several authoritative reviews and surveys, such as those of the International Energy Agency and the Global CCS Institute. Yet the results of this workshop showed that several questions did not always have definitive answers because the situation is often unclear; it is certainly in a state of flux. This is not a negative comment; rather it reflects the challenges to be overcome if CCS is going to be a realistic, and most particularly a global, practise.

This challenge was brought home to the audience, many of whom appreciated for the first time the magnitude of the problem on the international scale: to capture billions of tons of carbon dioxide, and then to safely dispose of it—all at an industrial and politically acceptable cost. In fact, the interface between research and technical innovation with commercial cost and investment risk was a recurring theme throughout the two days. There is a long way to go. An example of how far, and at what cost, is typified by the discussions related to the Canadian SaskPower Boundary Dam CCS project outlined in the presentations of Schwander and Fabricius.

Put simply, Boundary Dam is a coal fired power plant undergoing a billion plus dollar carbon capture retrofit with an expectation of being commercially viable in two years. But there are about 2500 coal-fired power stations (7000–10000 units) operating in the world. Clearly the cost of retrofitting and/or replacing these would be staggering. [Parenthetically, as several speakers remarked, there are only eight commercial integrated CCS facilities currently active, none of which directly involve combustion-based power generation.]

Another theme that ran through the Workshop was how best to get the public to accept any major innovative facilities, or even to be convinced that CCS is really necessary: ‘‘not in my backyard’’ is the understandable reaction. Exactly how to bring the public into the picture prompted lively discussion, but all agreed that this is a problem that has to be solved. The political reality is that people are concerned about the environmental impact of carbon dioxide storage, and are very suspicious that the costs associated with CCS will filter down to them.

Cite this article as: Hanley HJM. Preface and overview, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:1 http://dx.doi.org/10.5339/stsp.2012.ccs.1

Page 2 of 3 Hanley, Sustainable Technologies, Systems and Policies 2012.CCS.1

Overall, then, the issues surrounding carbon capture and storage are indeed challenging but fascinating, presenting exciting opportunities for a smorgasbord of disciplines—basic chemistry, thermodynamics, chemical engineering, geology, economics, politics, and more. As speaker Zhou remarked at the close of the Workshop: ‘‘There are a lot of experts out there and lots was learned over these past two days. I remain hopeful that solutions will be found.’’

There are many people and organizations I want to acknowledge. First of all, thanks to my colleagues on the organizing committee, and most especially co-chair Dr. Iain Macdonald, who realized that Doha was an ideal venue for a CCS workshop. His suggested topics were the basis for the program, and he coordinated the speakers from Imperial College who played such an important role in the event.

Major credit goes to the reporters of the Discussion who had a difficult task which they carried out willingly and successfully. The financial support of the Executive Office of Texas A&M University at Qatar (TAMUQ) was greatly appreciated, as was the considerable administrative help offered by the staff of that Office. I am most grateful to Carol Nader, Brady Creel, and their colleagues for organizing the logistics of the Workshop. Iain and I owe a very special debt of gratitude to Rola Abou Ghaida, of the TAMUQ Department of Research and Graduate Studies, whose efficiency and enthusiasm in handling the overwhelming number of inquires, formatting the program details, and helping in so many ways, made our task manageable. And, of course, the Workshop could not have taken place without the funding and the proactive interest and cooperation of our sponsors: Dolphin Energy, Qatar National Research Fund (QNRF), ExxonMobil Qatar, and Total Exploration and Production Qatar.

Dolphin Energy, Qatar, was the Gold Sponsor whose General Manager, Mr. Adel Ahmed Albuainain, generously endorsed the Workshop concept by stating: ‘‘We are delighted to be the main sponsor of this important workshop and are always keen to support such initiatives that share ideas and highlight innovation. A commitment to carbon capture technologies is becoming increasingly critical, especially in the context of the Qatar National Development Strategy 2011–2016, the Qatar National Vision 2030, and the strides taken to advance sustainability practices.’’ We owe Dolphin Energy much.

We are particularly grateful to Dr. Abdul Sattar Al-Taie, Executive Director, Qatar National Research Fund and his team for QNRF Sponsorship. Their support gave us the confidence to take the Workshop from a concept to completion. Dr. Omar el Farouk Boukhris has remarked: ‘‘We, at the Qatar National Research Fund, recognized immediately the relevance of this workshop and were pleased to underwrite the workshop from its conception. The Qatar National Research Fund is the sole national research funding agency in the state of Qatar. By supporting competitive research in all class of society and in many scientific disciplines, the QNRF is an arm of the Qatar Vision 2030. Clearly, the national priorities are of paramount importance. Since Qatar is classified among the very highest, if not the highest, per capita emission countries, it is natural that we need to discover and implement new ideas targeting carbon capture and storage with a focus on environmental impact and cost reduction. We truly believe that future research will be driven by cross-disciplinary efforts such as you are anticipating to be an outcome of this workshop.’’

ExxonMobil Qatar Inc was a Silver Sponsor and we are most grateful for their enthusiastic support from its early stages. ‘‘Events such as the Carbon Capture Workshop hosted by Texas A&M University at Qatar and Imperial College London are so critical because they help highlight the importance of advancements in technology, in this case carbon capture,’’ said Bart Cahir, President and General Manager. ‘‘At ExxonMobil, we have been active in developing and applying carbon capture and storage component technologies since the 1980s with the understanding that breakthrough technologies can help keep pace with rising global energy demand while also reducing the environmental footprint of energy development.’’

Total Exploration and Production Qatar was a Silver Sponsor and they made a significant contribution to the success of the Workshop by their encouragement to get industry actively involved in the program. Philippe Julien, Director, Total Research Center Qatar, had these kind words to say: ‘‘It has been a pleasure for Total to be a sponsor of this workshop organized by TAMUQ and Imperial College London on such an important subject. Carbon Capture constitutes a real stake for the whole petroleum industry in general and for Qatar in particular. Total is committed to reducing the impact of its activities on the environment, and especially its greenhouse gas emissions in the atmosphere. At Total, we have been developing a fully integrated research CCS pilot project in France, and it has been a pleasure for us to share what we have learn from this interesting project with our academic and industrial Qatari partners.’’

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We are very appreciative of the considerable help offered by QScience.com, who monitored the programme and changed the drafts into a publishable product. We are proud to have made a contribution to this innovative and enterprising organization which has been heralded by Outsell Outlook as one of the top 31 information industry ‘‘companies to watch’’ in 2012; a list of 31 which includes Adobe, Google, and Apple.

Again, to all these individuals and institutions, my grateful thanks.

ORGANIZING COMMITTEE Dr. Howard J. M. Hanley, Research and Graduate Studies, Texas A&M University at Qatar (Co-Chairperson) Dr. Iain Macdonald, Department of Chemical Engineering, Imperial College, London (Co-Chairperson) Dr. Kenneth R. Hall, Associate Dean of Research, Texas A&M University at Qatar Dr. Patrick Linke, Chemical Engineering Program, Texas A&M University at Qatar

DISCUSSION REPORTERS Dr. Apostolos Georgiadis, Imperial College, London Mahmoud Abouseada, Texas A&M University at Qatar Hicham El Hajj, Texas A&M University at Qatar Seifullah El Haraki, Texas A&M University at Qatar Ana Rodriguez, Texas A&M University at Qatar Mohamed Ajmal Abdul Salam, Texas A&M University at Qatar Makram Sarieddine, Texas A&M University at Qatar

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Carbon capture: An introduction Chair: Howard JM Hanley Texas A&M University at Qatar, Doha, Qatar

http://dx.doi.org/ 10.5339/stsp.2012.ccs.2 Published: 17 December 2012 c 2012 Hanley, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

INTRODUCTION Mr. Khalid Mohammed Al-Hitmi (Qatar Petroleum), and Dr. Omar el Farouk Boukhris (Qatar National Research Fund) gave the introduction and set the stage for what followed by emphasizing a crucial conclusion of the Workshop: that the Carbon Capture Storage (CCS) issue cannot be resolved without serious political will, industrial commitment, and substantial support from research funding agencies.

Mr. Khalid Mohammed Al-Hitmi: ‘‘Ladies and Gentlemen, it is with great pleasure this morning that I participate in this Carbon Capture Workshop organized by two of the academic and research organizations engaged here in Qatar in the area of carbon capture and storage. Indeed, the issue of carbon capture and sequestration has been an area of focus for us in Qatar Petroleum, along with some of our partners here in Qatar, for some time now, as evidenced in our support of governmental efforts at 2010 COP (United Nations Climate Change Conference) 16 in Cancun, Mexico and at 2011 COP17 in Durban, South Africa, for inclusion of carbon capture and storage in geologic formation as an approved technology under the ‘‘Clean Development Mechanism’’; as well as our efforts in our operations to move forward in planning some of the necessary steps required for the future carbon capture and storage activities. As Qatar will be hosting the upcoming COP18, it is very timely to be here discussing one of the main technological requirements for emission reductions in our industry.

The expert presentations and discussions in this workshop will address some of these technological challenges and opportunities, which will be highlighted by the next speaker. But to emphasis the magnitude of the problem and the size of the opportunity that this technology can address, I would like to just mention that, by some estimates, human activities in the first 20 years of this century will be responsible for releasing as much carbon to the atmosphere as the entire 20th century.

Although, the recent macroeconomic crisis around the world, and most acutely in the US and Europe, have resulted in a deterioration of the level of urgency to address some of the challenges of climate change and carbon release, the time will come when this issue will be firmly back as an urgent problem requiring collective action. In addition to technological advances and improvements, there is a need for providing credible policy options to pave the way for the industry to implement required changes and establish new operational norms which meet both new regulatory and environmental requirements while addressing societal expectations.

I believe this workshop is a meaningful step in addressing some of the technical issues concerning the vital technology of carbon capture in our industry. Through forums like this, and concentrated efforts by all stakeholders, we will be able to face the challenges ahead and address what will be required of our industry in the future. Therefore, I look forward to the successful start of this workshop and wish you all the best. Thank you! ’’ Dr. Omar el Farouk Boukhris introduced the Executive Director of the Qatar National Research Fund, Dr. Abdul Sattar Al-Taie: ‘‘On behalf of the Qatar National Research Fund executive director, Dr. Abdul Sattar Al-Taie, and on behalf of all the Qatar National Research Fund team, and as a sponsor of this carbon capture workshop, it is my pleasure to be here today to contribute to the success of the endeavor.’’ He outlined the major role the Qatar Foundation’s Research Funding agency (QNRF) has Cite this article as: Hanley HJM. Carbon capture: An introduction, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:2 http://dx.doi.org/10.5339/stsp.2012.ccs.2

Page 2 of 7 Hanley, Sustainable Technologies, Systems and Policies 2012.CCS.2

played in fostering research in the State of Qatar and, in particular, pointed out that its principle arm – the National Priorities Research Program (NPRP) – has committed about $24 million in the last three years on financing and sponsoring research projects related to carbon capture. He listed only a sample of the topics that the NPRP has supported: 1. capture of carbon dioxide from natural and effluent gas streams and its conversion 2. theoretical and experimental study of asphaltene deposition during CO2 injection in Qatar’s oil reservoirs 3. CO2 capture and photo-conversion to a renewable fuel 4. emission free co-production of carbon nanotubes and hydrogen via concentrated solar energy 5. CO2 mineralization and reject brine management through chemical reaction 6. new cold asphalt materials for road and airport pavement that will lead to atmospheric CO2 reduction Several of the attendees commented on the significant contribution the NPRP is making to research on Carbon Capture and Storage, and Boukhris answered several questions on the operation of the Program.

The question was asked if the NPRP was involved in research outside the State of Qatar. Boukhris said this was indeed the case and international cooperation is an important segment of the research efforts. He told the audience that while sixty-five percent of the funds awarded for a given project is required to remain in Qatar (with Texas A&M at Qatar, and Qatar University the majority recipients) the balance can, and does, support international cooperation. In fact, ‘‘We have such key players as Imperial College, University of Toronto, Colorado School of Mines, Arizona State University, University of Oxford, University of California, Irvine, The National University of Singapore, McGill University, Massachusetts Institute of Technology and others which are contributing to different aspects of the carbon capture and storage problem.’’

PRESENTATION Carbon Capture and Storage—The Way Ahead Geoffrey C. Maitland Department of Chemical Engineering, Imperial College, London, UK The paper gives a general introduction and overview of Carbon Capture and Storage (CCS) with an emphasis on the capture of CO2 and other greenhouse gases from the waste gas streams of power plants and industrial processes. This stage accounts for about 80% of the overall cost of the CCS process so is the area where efficiency and cost improvements will have the greatest future impact. The major drivers for continuing to use fossil fuels for most of this century are first considered and the need to implement CCS as one of many measures to mitigate carbon emissions. Current targets will require a commercial CCS capacity to remove about 10Gte CO2 pa by 2050. The overall features of CCS processes are described – capture, compression and transport, sub-surface storage – covering the main capture options and the three main types of storage site (deep saline aquifers, depleted oil and gas reservoirs and unmineable coal seams). The current status of large-scale CCS demonstration projects is reviewed. The main classes of carbon capture technologies are then described, both those currently capable of large-scale deployment and those in development for the future. Finally the main challenges facing CCS, to make it a globally-deployed commercially viable technology, are summarised and suggestions made for future developments in the clean recovery and use of fossil fuels which combine CCS with sub-surface processing.

PRESENTATION Carbon Capture and Storage: An Industry Viewpoint Marcus Schwander Innovation R&D Manager—Qatar Shell Service Companies

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A brief overview of the current status of the carbon capture and storage (CCS) issue is presented from the industrial viewpoint. It is pointed out that it is estimated that fossil fuels will still meet at least 65% of world energy demand in 2050 to supplement the anticipated deployment of alternative lower-CO2 producing sources of energy: efficient and economic methods for CCS are therefore essential if the generally accepted required reductions of GHG emissions are to be satisfied. The challenges – technical, economic, and political – that have to be addressed are discussed and Shell’s collaboration in their solution is outlined. For instance, Shell’s work through its subsidiary Cansolv Technologies is discussed: Shell is involved in the 2012 piloting of its 2nd generation post-combustion capture system for deployment in a large scale integrated CCS project.

In addition, Shell is involved in the development of 3rd generation post combustion; precipitating potassium carbonate based system (carbonate slurry) offering cost reduction, lower amines emissions and energy efficiency breakthroughs.

DISCUSSION The talks of Maitland and Schwander outlined the background of the carbon capture and storage topic from both an academic and an industrial viewpoint, and touched on most of the points raised and expanded throughout the sessions that followed. In particular, the audience were introduced to the scale of the problem and the costs required for remediation.

Ibrahim Al-Kuwari (Dolphin Energy, Qatar ) noted that Maitland had not commented in any detail on carbon capture and storage with respect to the cement industry. Maitland replied that this was excluded merely because he wished to emphasize the problems with respect to the hydrocarbon industries, but Al-Kuwari’s remark did remind the attendees that CCS is a pervasive issue which impacts most industries, those related to iron and steel and cement production – each of which contribute around 5% of the total world CO2 emissions – in particular.

Abdullah Al-Swaidi (Qatar Petroleum) asked how Maitland would evaluate the current status of the global efforts to deal with carbon capture and Maitland responded as follows: ‘‘ I think the efforts for commercialisation have been quite so far have been quite poor in that little has changed in the last decade, especially since any progress would not have required any major technological changes. As an example, the Sleipner North Sea project, largely driven by the carbon tax implemented by Norwegian government, was initiated in 1996, and thus has been around for sixteen years.

Looking around the world we see CCS technology applied to less than ten commercial gas treatment/processing projects, to a few major demonstration projects, but – in particular – not as yet to a commercial power plant. To be in that situation, while knowing that CO2 emissions have been an issue for at least ten years, is very disappointing and we need to turn it around.

Unfortunately, I’m concerned that the current rate of growth in research and implementation doesn’t meet the scenarios we have been talking about. I have mentioned that it is estimated that the world needs to capture 10 Gt of CO2 /year and that would mean moving from a few CC projects at the moment to several hundred over the next couple of decades—and even thousands over the next forty years. In my opinion we are well behind the curve.’’

Niall Mac Dowell, Paul Fennell and N. Shah (Imperial College) submitted additional material to expand on Maitland’s comment. ‘‘This (lack of progress) is odd in light of the fact that the technology for one of the most promising CO2 capture technologies, amine scrubbing, was first patented in the 1920s.

Further, the concept of injecting (or sequestering) captured CO2 in partially depleted oil wells was extensively practiced in the 1960s–1970s, as part of enhanced oil recovery (EOR) operations, and several commercial CO2 capture plants were constructed in the US by the late 1970s and early 1980s.’’

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[see, for example, the comments in the presentation of Bruce Palmer (Texas A&M University at Qatar ) later in this volume.]

Adel Ahmed Albuainain (Dolphin Energy, Qatar ) remarked that there are many current initiatives in renewable energy, and asked Maitland if he thought they have been taken into consideration here. Maitland replied that there are several scenarios on how to mitigate 50 GtCO2 pa by 2050 but, at the moment, it is estimated that no more than 30% of this will be achieved by using energy supplied from renewable sources. This, however, may very well change by more accelerated innovation, although the qualitative picture will probably remain the same.

Along these lines, several participants throughout the workshop directly and indirectly followed up Albuainain’s implication of the significance of alternative methods to reduce carbon emissions.

Displayed here, for example, is a graphic from the IEA report of 2008 [1] (also reproduced in Maitland’s paper): Figure 1 shows estimates of alternative routes to industrial carbon emission reduction. (The ‘‘Baseline’’ upper limit is the projection assuming current reduction procedures are maintained until 2050, the ‘‘Blue’’ lower limit assumes the goal of a 50% carbon reduction is achieved.) The projections are speculative but the key point is made: namely, that CCS alone will not be enough to reduce levels of atmospheric carbon to the acceptable level. The target is 20% of the optimal reduction – 10Gt pa – but, as pointed out by Maitland, even this will be a tough challenge given the current rate of progress. One can, however, say with certainty that fuel and feedstock switching will play a major role—in fact there is already evidence that the increased use of natural gas has already had an impact on atmospheric carbon reduction. Related to this, Patrick Linke (Texas A&M Univ. at Qatar ) submitted this comment on energy efficiency.

Figure 1. Slide from Maitland’s paper, reproduced from IEA report of 2008.

A key to success in achieving the envisaged carbon reduction trajectories will be the more efficient use of energy. For the foreseeable future, fossil fuel is envisioned to be by far the major energy source. Energy efficiency will obviously reduce carbon emissions from fossil fuel use directly. Looking into the future, utilizing energy more efficiently will also benefit the introduction of alternative energy sources, the inefficient use of which typically proves rather costly.

A major energy user is the industrial sector. Here, energy efficiency gains can be achieved by developing and installing more efficient technology components and equipment. More importantly, industrial energy efficiency can be enhanced significantly through better planning and policy to stimulate energy recovery and reuse at a systems-wide level. Hence, integrated planning of facilities, both at the level of an individual process or plant, but also at a wider level leading to realization of the concepts of eco-industrial parks will be vital activities in the future. Such approaches to integrated design hold significant promise to reduce emissions at a relatively low cost

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and will be crucial enablers of sustainable solutions; they make it possible to boost system-wide energy efficiency within the existing technology.

Maitland again emphasised that we need a portfolio of carbon mitigation measures over the next 50 years to keep atmospheric CO2 levels below critical and that CCS is just one of those methods.

This is in line with Adel Ahmed Albuainain and Patrick Linke’s views.

Farid Benyahia (Qatar University ) commented on this figure in the context of CO2 storage. He pointed out that potential underground storage areas are unevenly distributed over the Earth’s surface (as discussed during his talk on Day 2). Those parts of the world not blessed with suitable storage sites will have to emphasise CO2 conversion procedures and one can expect that only a fraction of their total emissions can be so converted. Thus, there should be a particular pressure on those countries that do not have suitable geological sites to diversify their portfolio of energy generation: improvements in energy efficiency, system integration, and a substantial switch to renewable energy infrastructure for domestic and agricultural usage.

Peter Lindstedt (Imperial College) added: ‘‘It may further be noted that aggressive targets for energy efficiency can be combined with financial incentives and legislative requirements to encourage improved technologies. The cost of CO2 mitigation associated with such an emphasis can be expected to be very competitive in sectors where a significant infrastructure investment would be required in order to derive true benefits from more speculative efforts. In a sense, it is disappointing that the projected dominant contributor to carbon emission reduction has not been given due attention in a way similar to what the current workshop seeks to achieve for CCS.’’ Maitland showed a slide (Fig. 2) which lead to several remarks: Some numbers...

Current emissions are around 30 Gt CO2 per year (8.5 Gt carbon).

Say inject at 10 Mpa and 40°C – density is 600-700 Kgm–3.

This is about 108 m3/day or around 700 million barrels per day.

Current oil production is around 85 miilion barrels per day Huge volumes – so not likely to be the whole story but could contribute 1-3 Gt carbon/yr...or ~10 Gt CO2 pa Costs: 2-3 cents/KWh for electricity for capture and storage; $40-100 per tonne CO2 removed – shackley and Gough, 2006

Figure 2. CCS in numbers, from Maitland’s presentation.

Many in the audience had their eyes opened to learn that current CO2 emissions, if all were injected, would be equivalent to 700 million barrels of oil a day, especially if that number is compared to the current daily oil production of around 85 million barrels.

Hanley (Texas A&M Univ. at Qatar ) submitted a question to Maitland and Schwander on the capture costs quoted in the slide. ‘‘I assume the figures refer to running cost for CCS (i.e., excluding capital investment). Do you have comments relating these costs to the Carbon Taxes either in place, or proposed by several countries? Quantitative figures are hard to pin down but, for example, Australia is proposing a tax rate of AU$23 per tonne which would probably be equivalent to about 3c per KWh of electricity.’’ [Editor: the tax is now in place].

Maitland and Schwander gave very consistent responses. Maitland stated that the figures quoted cover both capital and running costs for the overall CCS process. He noted that carbon trading prices have fluctuated wildly—for instance the EU trading price was close to 20 euros per tonne CO2 in mid-2011 but has recently plummeted to 7 euros. In its 2012 annual GHG Market Sentiment Survey of EU regulators, Price Waterhouse Cooper found that 80 percent of respondents were in favour of cutting the supply of trading permits in a bid to boost carbon prices to a level that encourages firms to invest in clean technology, including CCS. They estimated that European carbon

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prices could treble from the current levels to 20 euros ($25) over the next eight years if European governments do issue less permits.

He noted that this twenty-five dollars figure is similar to the Australian and the early 2012 Norwegian CO2 tax, but is still low compared with realistic CCS costs. Norway, however, increased the tax rate to $35 per tonne in June 2012 in an attempt to encourage companies to invest in CCS and other carbon mitigation technologies. This combination of upward trends in carbon charges suggests the gap between clean technology costs and financial incentives/charges will close over the next 5–10 years. A major increase in commercial scale implementation, however, still requires major technological advances to bring the capture/compression costs down significantly to make CCS routine at $30–40 per tonne. Schwander’s reply was: ‘‘At this stage, industrial capture and storage costs are still high whilst CO2 prices are very uncertain, thus making CCS business cases very difficult to quantify. CCS projects require a sustained CO2 pricing model (via carbon trading or otherwise), which results in CO2 prices that are high enough to justify commercial investment. Further, the reported costs of CCS vary strongly due to differences in location and the type of capture system involved. As discussed in my talk, commercial scale demonstrations across the full CCS spectrum – from capture through compression/transport to CO2 injection and surveillance, with investigations of the next generation of capture techniques – are required to drive the industry up the learning curve, but down the cost curve to below 100$/tCO2 .’’

An aside question was later submitted relating to the often-quoted statement that CO2 emissions are currently about 30 Gtpa. Several authors refer to this number as the ‘total anthropogenic emissions.’ The public perception, however, is that the figure refers to energy-related carbon dioxide resulting primarily from the combustion of fossil fuels. But shown (Fig. 3), for instance, is a pie chart depicting the sources of CO2 global emission (PBS website, posted October 21, 2008 [2]):

Figure 3. Sources of the world’s CO2 emissions, reproduced from PBS website.

Thus, it was asked if it would be correct to say that the CO2 emission from fossil fuel combustion is around 40% of the 30 Gtpa? Maitland responded by saying that one runs into semantics but a better figure – based on this chart – would be 66.3% if we define ‘fossil fuel combustion’ as that used for energy supply + transportation fuels + fossil fuels burnt in industrial processes + heating of buildings.

Time and time again attendees asked questions on the cost involved in getting a carbon capture project to the commercial stage. When asked for his opinion, Schwander said he could only talk from his experience and recounted his involvement in a clean-coal project in Australia on CO2 separation through coal gasification and the subsequent sequestration. He estimated that it would cost around one billion US dollars to get this project to a level needed to even start demonstrations on an industrial scale. He note that this figure was consistent with an estimate for a power plant upgrade discussed by his colleague, Niels Fabricius (Qatar Shell) in a later talk. He further reminded the audience that the underpinning research is also extremely costly and cannot be undertaken without substantial government support, external funding, and cooperation from the academic community.

Christina Martavaltzi (Texas A&M University at Qatar ) noted that Shell was investing a lot of money in research on capture technology but remarked that calcium and chemical based looping

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perhaps could be the most efficient and cost effective. She asked if Schwander had any comment on that. Robert Moene (Shell) replied that Shell is involved in a small project on chemical looping but calcium processes are not in the scope at this stage. Martavaltzi again offered her opinion that it would be productive to invest more in this area.

Schwander emphasized that Shell has to first consider those proven technologies which could reinforce the demonstration/deployment side of carbon capture, and which could be implemented over a relatively short time scale. He, however, reaffirmed that Shell is investing widely, especially through collaboration, in all aspects of carbon capture and storage. He showed one particular slide (Fig. 4) that outlined the path from discovery to commercial reality: BRINGING CGS FROM DEMONSTRATION TO DEPLOYMENT REQUIREMENTS Urgency – Speed is vital if demo projects are to be operational by 2015.

Regulatory / Legal – Regulatory frameworks for CCS deployment.

Technology cost

Discover and develop

Demonstration

Earlier deployment through demonstration

Deployment

Number of installations

CO2 price Power generation without CCS

Technology – Demonstrate and deploy the existing technology to roll for eventual commercial scale; Public Acceptance – Policy makers and industry need to join to further the understanding of CCS. Funding – Funds or allowances to incentivize commercial scale demonstration projects.

Infrastructure – Demonstration is key but we need to look now at how infrastructure is to be set up (plant clusters, pipelines, hub stations sinks ) and how it is to planned and operated.

4/8/2012 18

Figure 4. Slide from Schwander’s presentation.

Bernie Patterson (AES International Consultants) asked what consideration was given to acid gas injection. Schwander answered that this was, of course, a factor with respect to CO2 injected into carbonate strata. The phenomenon needs to be understood better since a reaction will take place on injection with obvious implications to EOR. But there will also be reactions over the long term with implications to sequestration and storage. Shell is actively supporting research on this problem in Doha.

NOTES All presentations referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

REFERENCES

[1] http://www.iea.org/techno/etp/ETP_2008_Exec_Sum_English.pdf.

[2] http://www.pbs.org/wgbh/pages/frontline/heat/etc/worldco2.html.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Industrial requirements Chair: Patrick Linke Texas A&M University at Qatar, Doha, Qatar

PRESENTATION Life Cycle Assessment of the Natural Gas Chain and Power Generation Options with CO2 Capture and Storage Anna Korre, Zhenggang Nie, and Sevket Durucan Dept. of Earth Science & Engineering, Imperial College, London, UK Fossil fuel based power generation technologies with/without CO2 capture offer a number of alternatives, which involve different fuel production and supply, power generation and capture routes with varied energy consumption rates and subsequent environmental impacts. The holistic perspective offered by Life Cycle Assessment (LCA) can help decision makers to quantify the trade-offs inherent in any change to the fuel supply and power production systems and ensure that a reduction in greenhouse gas (GHG) emissions does not result in increases in other environmental impacts. Besides energy and non-energy related GHG releases, LCA also tracks various other environmental emissions, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. In this respect, the dynamic LCA model developed at Imperial College incorporates fossil fuel production, transportation, power generation, CO2 capture, CO2 conditioning, pipeline transportation and CO2 injection and storage, and quantifies the environmental impacts at the highest level of detail, allowing for the assessment of technical and geographical differences between the alternative technologies considered. The life cycle inventory (LCI) databases developed model the inputs and outputs of the processes at component or unit process level, rather than ‘‘gate-to-gate’’ level, and therefore generate reliable LCI data in a consistent and transparent manner with a clearly arranged and flexible structure for long term strategic energy system planning and decision-making.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.3 Published: 17 December 2012 c 2012 Linke, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

The presentation discussed the principles of the LCA models developed and the newly extended models for the natural gas-fired power generation with alternative CO2 capture systems. Additionally, the natural gas supply chain LCA models, including offshore platform gas production, gas pipeline transportation, gas processing, liquefied natural gas (LNG) processes, LNG shipping and LNG receiving terminal developed are used to estimate the life cycle GHG emissions for an idealised case study of natural gas production in Qatar, LNG transportation to a UK natural gas terminal and use in a power plant. The scenario considers a conventional and three alternative CO2 capture systems, transport and injection of the CO2 off-shore in the Irish Sea.

Cite this article as: Linke P. Industrial requirements, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:3 http://dx.doi.org/10.5339/stsp.2012.ccs.3

Page 2 of 3 Linke, Sustainable Technologies, Systems and Policies 2012.CCS.3

PRESENTATION The CANSOLV SO2 – CO2 Capture Process1 Niels Fabricius Qatar Shell Fabricius’ presentation supplemented that of Schwander’s by giving an outline of a commercial application of capture to a power plant. Of particular interest was the realistic estimate of the costs involved. He discussed the relation between the time to bring the project to fruition and risks involved and – following Schwander’s presentation and remarks – how a risk assessment influences the relevant research. His presentation also lead to discussions on corrosion issues arising from the SO2 content of the flu gas.

The talk centered on one of Shell’s contribution to the commercial application of post-combustion, amine CO2 capture as carried out through their affiliate company CANSOLV Technologies Inc., specifically to upgrade the Boundary Dam Power Station, Estevan, Saskatchewan, Canada. To quote from the site http://www.globalccsinstitute.com/: ‘the project entails the rebuilding of Unit #3 at the existing Boundary Dam coal-fired power plant to include post-combustion CO2 capture at one million tonnes per year. The 110 MW net unit is scheduled to commence operations in 2014.’

The technical challenge is not only to capture CO2 at this scale, but also to remove the other significant pollutant from the flu gas, SO2 . Fabricius’ technical theme was that the mechanism of SO2 and CO2 capture is very similar; applying an amine solvent in an oxgenative environment. There are differences in the chemistry, but the engineering is very similar. Based on this, the capture of SO2 and CO2 can be combined in one integrated process by having two different solvent loops: one to capture SO2 the other to capture CO2 .

DISCUSSION The session covered two examples of how a specific procedure is applied to address a commercial application of a CCS assessment and probable solutions. Fabricius’ talk discussed upgrading the Boundary Dam Power Station, Saskatchewan, Canada, through CANSOLV Technologies Inc. Korre used data from a Qatar LNG supply and transportation train to illustrate her procedure. In fact, Abdulla Al-Sadah (Qatar Petroleum) commented that the choice of Qatar as a case study was most relevant and interesting but asked if Korre had applied her methods to other LNG scenarios. Korre answered that she had and referred to projects in Norway, Australia and elsewhere.

Al-Taie (QNRF ) remarked that the analysis would be enhanced if a cost analysis were included.

Korre agreed but noted that she was currently working on this aspect.

Christina Martavaltzi asked if Korre had carried out an Exergy analysis. Korre replied that the LCA models presented provide a steady-state snapshot of the environmental performance of a given system over a period of time and a calculation of the overall system efficiency in energy conversion to power was perfectly feasible.

Hanley submitted a question to Korre: ‘‘In your case-study of the LNG production and transportation from Qatar to the UK, I take it you have assumed that all the CO2 capture occurs at the UK re-gasification facilities.

As we have heard in this workshop, there is an obvious move to promote carbon capture/reduction at the natural gas source, and also in the LNG shipping process. You mentioned that the reduction of GHG emissions from the supply chain has the potential to decrease life-cycle emissions significantly. Have you applied your LCA models to give an estimate of the possible percentage reductions? Also, have you considered the relative costs of capture in the UK compared with that which could occur in Qatar?’’

1 This presentation and the paper: ‘‘CANSOLV Technologies Inc. SO2 Scrubbing System.’’ are available online as Supplementary Material at http://www.qscience.com/toc/stsp//CCS+Workshop.

Page 3 of 3 Linke, Sustainable Technologies, Systems and Policies 2012.CCS.3

Korre replied that their LCA model has been used to compare emission reduction arising from LNG transport with Qatar’s state-of-the-art Q-Max/Q-Flex tankers as opposed to transport with conventional vessels. Corresponding emission savings, however, are not reported. (She adds, parenthetically, that the Imperial College Group would be happy to undertake this work should it be considered relevant to Qatar industry.) With regards to the relative costs comparison, she indicated that this is the focus of current research, which is due to be completed in the first half of 2013.

Several members of the audience questioned the time needed to upgrade the Boundary Dam project in particular and other commercial facilities in general. Fabricius told the audience that previous results from a one-ton-a-day capture pilot demonstration plant has indicated that one should have the confidence to go ahead with the Boundary Dam in one or two years. He, however, pointed out that, in general, timing is a matter of how much risk a client is prepared to accept. The Boundary Dam clients will invest more than one billion dollars based on results from the pilot. Other companies may, and will be, more cautious.

Al-Taie had comments relating to the SO2 content of the flu gas. He asked what were the estimated scrubber temperatures since normally one would like to cool the stack gases as much as possible to optimise the efficiency of the scrubbing process. (Fabricius replied about 50 C). He added that working with a mixture of CO2 and SO2 gives rise to a challenge: one has to be aware of the system dew point in order to minimise the effects of corrosion, which could be a huge problem. Fabricius acknowledged this problem but remarked that the absorber was built of concrete lined with corrosion reducing bricks. Al-Taie wanted to emphasize that Fabricius was discussing capture with respect to coal and the resulting problems associated with the combined CO2 and SO2 emissions. He then remarked that Middle East crude is heavily sour, but is used routinely by many countries as a relatively inexpensive fuel. Hence it is very important that the energy sector consider the implications of capture from sulphur containing sources.

NOTES All presentations and related materials referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Pre- and post-combustion Chair: Fedaa Ali Qatar Environmental and Energy Research Institute, Doha, Qatar

PRESENTATION Gas turbine related technologies for carbon capture R. Peter Lindstedt Department of Mechanical Engineering, Imperial College, London, UK. Combustion modes in gas turbines are evolving in order to meet requirements related to lower emissions and greater thermodynamic efficiency. Such demands can be contradictory and the additional complication of fuel flexibility comes to the fore with potential new fuel stream opportunities arising. The latter may include hydrogen and carbon monoxide rich streams as well as blends with significant amounts of carbon dioxide arising from certain types of syngas (e.g. bio-derived). The matter is further complicated by the impact of combustion stability related issues that arise in the context of the ubiquitous transition to lean pre-vapourised premixed (LPP) combustion for power generation applications. Post-combustion carbon capture is generally considered the leading candidate in the context of LPP based technologies. Significant capture related issues arise in terms of parasitic losses associated with CO2 separation and transportation technologies (e.g. compression). The former is typically the major contributor and the relatively low concentration of CO2 in flue gases, combined with excess oxygen resulting from LPP based operation, does impact separation technologies. It hence appears natural to consider the operating mode of the gas turbine and the impact of the fuel composition on the flue gas characteristics alongside the development of efficient and novel separation technologies.

PRESENTATION An overview of carbon capture technology Bruce R. Palmer Chemical Engineering Program, Texas A&M University at Qatar, Doha, Qatar

http://dx.doi.org/ 10.5339/stsp.2012.ccs.4 Published: 17 December 2012 c 2012 Ali, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

This paper gives a brief review of carbon capture technology, but emphasises the problems that can arise from natural gas produced from gas and/or petroleum reservoirs containing substantial amount of hydrogen sulfide and carbon dioxide, known as ‘‘acid gas.’’ Natural gas desulfurization or sweetening processes for treating natural gas are an integral part of natural gas cleanup. Discussed is the coupling of capturing both CO2 and H2 S, particularly using an amine solvent and particularly in the context of post- and pre-combustion. Methods to dispose of these captured gases are outlined. The paper gives an overview of the current status of capture and disposal on the global and commercial scale.

DISCUSSION Lindstedt’s presentation was a variant on the other topics discussed at the Workshop in that he discussed specifically the linkage between energy efficiency and the corresponding capture.

Cite this article as: Ali F. Pre- and post-combustion, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:4 http://dx.doi.org/10.5339/stsp.2012.ccs.4

Page 2 of 3 Ali, Sustainable Technologies, Systems and Policies 2012.CCS.4

Reproduced, for example, is a schematic slide he presented (Fig. 1) to set the theme for his talk: the power and heat units are shown. Lindstedt made the point that the power and heat units are treated separately from the separation unit in the conventional post-combustion process, which is not necessarily the most efficient practice. Lindstedt also had several comments on gas turbine/fuel compatibility and the audience were interested in his comments on this most practical issue.

N2, O2, H2O Flue gas CO2 separation

Post-combustion capture Fual Air

Power and heat

Pre-combustion capture

N2, O2, H2O Gasification or partial oxidation shift + CO2 separation

Fual

Air O2/CO2 recycle (oxyfuel) combustion capture

Air separation

H2

Power and heat

Air

O2 Air

CO2

CO2 dehydration, compression transport and storage

Flue

N2

Power and heat

Fual

CO2

CO2 (H2O) Recycle (CO2, H2O)

N2

Air separation

Source: IPCC, 2005.

Figure 1. Schematic from Lindstedt’s presentation.

In fact, later questions were asked after the workshop regarding turbine/fuel compatibility because projects are in progress at Texas A&M University at Qatar concerning hydrogen as a fuel. Work is also being carried out on turbine performance with GTL blends. Lindstedt was invited to comment. He did so and suggested that the ability to ensure fuel flexibility combined with efficient, low emission, conversion modes that are increasingly based on premixed or partially premixed combustion is perhaps the principal challenge at present. In short, the closer a burner technology operates to stability limits, the more important the properties of the fuel. Furthermore, the operation with some fuels (e.g. syngas related) can pose significant additional safety concerns in case of equipment or operational failure. Another aspect that should not be ignored in this context is the state and quantity of post-combustion pollutants other than CO2 and the link to environmental regulations and separation units. Work is in progress at Imperial College covering aspects of all these areas.

Palmer introduced his overview of the CCS scene by putting the current work in the context of the 50-year sequential evolution of the controls of gaseous emission: particulates, sulphur, NOx and now CO2 . But a major thrust of his talk was to expand on the point made by previous speakers: namely, that if one looks at carbon capture technology, one frequently ends up talking about sulphur recovery at the same time. He discussed acid gas treatment and reminded the audience that there were proven techniques in the gas industry to separate CO2 from H2 S either using separate amine solvents or using a single selective solvent.

Desai Jwalant (Qatargas) inquired if the capture technologies discussed could be used for coal-bed methane. Palmer replied that coal-beds are sinks for CO2 . Nevertheless, there was a later question on the impurity content of coal bed/shale extracted methane. It was asked if remediation from this gas source presented any special problems to which Palmer replied: ‘‘Coal-bed methane is relatively pure. It contains only a few precent CO2 and very little H2 S because this sulphur species adsorbs strongly on the coal matrix. Accordingly, processing this gas is relatively straightforward. Unfortunately coal-bed methane contains only a few of the heavier hydrocarbons which are a significant source of revenue in the case of conventional natural gas.’’

Palmer’s technical comments compared aspects of post- and pre-combustion techniques which lead to the key question asked by Siba Borah (RasGas):

Page 3 of 3 Ali, Sustainable Technologies, Systems and Policies 2012.CCS.4

‘‘ Pre-combustion or post-combustion methods - which one is more advantageous in terms of investment?’’

This question, already indirectly addressed by Schwander and Fabricius who both discussed investment in the context of risk assessment, was answered by Palmer as follows: While the present presentation was not an economic analysis, the literature provides some information concerning the processes which have favourable economics. As shown in the table below, most of these economically viable commercial-scale projects derive value from making product to specification to avoid economic penalties. Most of these processes are not combustion-based processes so the terms ‘‘pre-combustion’’ and ‘‘post-combustion’’ are not stickily applicable in these instances.

However, in terms of processing conditions, these processes are more closely related to pre-combustion processes in that they treat gas streams with relatively high CO2 concentrations.

This line of thought lead to comments and questions directed to Palmer and others during the Workshop on the current status of the commercial capture and storage projects. In the course of his presentation Palmer displayed a slide (Fig. 2) that served to clarify the situation:

Figure 2. Commercial-scale CCS projects in operation, from Palmer’s presentation.

The literature is indeed confusing and often does not distinguish clearly between pilot, demonstration, and ongoing major facilities. In fairness, the situation is in a continuous state of flux. It is recommended that reference be made to the comprehensive data base put out by the Global Institute for Carbon Capture and Storage: http://www.globalccsinstitute.com/publications/data/dataset/status-ccs-project-database NOTES All presentations and related materials referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Industrial procedures and problems Chair: Fedaa Ali Qatar Environmental and Energy Research Institute, Doha, Qatar

PRESENTATION The Lacq industrial CCS reference project (France) Jacques Monne Total Total is committed to reducing the impact of its activities on the environment, especially its greenhouse gas emissions. The group’s priorities are to improve the energy efficiency of its industrial facilities, to invest in the development of complementary energy sources (biomass, solar, clean coal) and to participate in many operational and R&D programs on CO2 capture and geological storage (CCS). Total has been involved in CO2 injection and geological storage for over 15 years, in Canada (Weyburn oil field) for EOR and Norway (Sleipner, Snohvit) in aquifer. In 2006, Total decided to invest 60 million Euros in the Lacq basin for experimenting a complete industrial chain from CO2 capture to transportation and injection in a depleted gas.

This first French CCS pilot project is unique in several respects, by its size capturing carbon from a 30 MWth oxycombustion gas boiler (size unprecedented worldwide), by the choice of a deep onshore depleted gas reservoir (unprecedented in Europe) located at 5 Kilometers south of the town of Pau and its suburbs (around 140,000 inhabitants) and by operating a whole industrial chain (extraction, treatment, combustion of natural gas, High pressure steam production, CO2 capture, transport and injection) fully integrated in the Lacq industrial complex.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.5 Published: 17 December 2012 c 2012 Ali, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

The permitting process was also a first in Europe because at that time (from 2007 up to 2009), the Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide was not issued and the French authorities decided to apply the ‘‘mining law’’ for the subsurface facilities and the environmental code for surface facilities. This permitting process has included two months of official public hearing. In parallel to this official process, TOTAL decided to be proactive in the stakeholder involvement. Public information meetings were held since the start of the project early 2007 and a public consultation and dialog phase has been organized. That led to the creation of a permanent local information and surveillance commission (CLIS). From the beginning of this project, public acceptance has been a major concern. TOTAL’s approach is to set-up a high level of transparency and open dialog with all stakeholders. Sharing data with academics though a scientific follow-up committee and achieving specific scientific collaboration programs are also part of our objectives.

This project entails the conversion of an existing air steam gas-boiler into an oxy-gas combustion boiler, oxygen delivered by an air separation unit is used for combustion rather than air to obtain a more concentrated CO2 stream in the flue gas, easier to be captured. The 30 MWth oxy-boiler can deliver up to 40 t/h of steam to the High Pressure Cite this article as: Ali F. Industrial procedures and problems, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:5 http://dx.doi.org/10.5339/stsp.2012.ccs.5

Page 2 of 4 Ali, Sustainable Technologies, Systems and Policies 2012.CCS.5

steam network of the Lacq sour gas production and treatment plant. After a quench of the flue gas, the rich CO2 stream is compressed (up to 27 barg), dehydrated and transported via a pipeline to a depleted gas field, 30 kilometers away, where it is injected in the deep Rousse reservoir. Over 3 and half years, up to 90,000 tons of CO2 will be injected.

Monne’s talk concentrated on three significant topics: (i) the operation of a pre-combustion demonstration plant, the construction and operation of an integrated CCS chain, (ii) a quantitative attempt to assess the impact of injection on the environment, and (iii) an insight into the sensitivity of the public concerns of the transportation and storage procedures. Two slides from Monne’s presentation illustrate his main points (see Figs. 1 and 2):

Figure 1. Objectives of the CCS pilot plant in Lacq, France. Slide from Monne’s presentation.

Figure 2. Public acceptance of the CCS pilot plant in Lacq, France. Slide from Monne’s presentation.

The question was asked how many pre-combustion demonstrations at this scale were under construction or operational? Monne answered that there are three main pilot projects in Europe: the Schwarze pumpe project (30 MW oxy-coal burners, started in 2008), the Compostilla project (30 MW

Page 3 of 4 Ali, Sustainable Technologies, Systems and Policies 2012.CCS.5

oxy-coal burners, started in 2011) and our Lacq facility. See, for example, ‘‘The global status of CCS’’ reports issued by the Global CCS Institute.

Hanley had the following remark: ‘‘shown is your slide on the comparative merits of pre-verses post-capture. On the face of it, the capture ability of the two procedures is not very different. But, clearly, the relative capital and running costs will influence a judgment of which of the two is preferable.’’ He asked Monne for a comment (Fig. 3).

Figure 3. Why oxycombustion for the CCS pilot plant in Lacq, France. Slide from Monne’s presentation.

‘‘My slide is mainly related to the Lacq project. Total performed some costing studies regarding post- and oxy-combustion capture technologies relating to a Canadian project in the context of the Canadian economic background. The results, however, did not differentiate between these technologies in terms of technical costs. It should be noted that, in general, technical costing is specific for each project and has to be determined accordingly, for instance via a LCA as discussed at this Workshop by the speakers from Imperial College. Further, when comparing pre- and post- capture technologies, it is important to take into account their applications. In principle, pre-combustion technologies are mainly applicable to biomass/coal-fire power stations, integrated gasification combined cycle power generation plants, and to natural gas combined cycle power generation plants. One serious disadvantage of the pre-combustion technology (when compared with post-combustion) is that the older pulversised coal power plants – which currently generate most of the world’s fossil fuel power – cannot be retro-fitted.

In conclusion, the technical costs (Capex and Opex) obviously influence the judgment, but other parameters also have to be taken into account.’’

Maitland took up the theme of communications with the public and questioned as follows: ‘‘I am interested in the public communication exercises that you have been doing. I would like you to give an indication about the cost of your campaign of the regular communication to the public and also if it was a significant fraction of the on going technical and overall costs. Could you also tell us more on the public engagement meetings and the subsequent feedback? ‘‘ Monne answered that, in fact, the cost was not significant. Although we (Total) quickly realized that communications top the public were very important, it that turned out to be more of an organizational problem than a cost problem. Explaining the storage technology to the public was especially difficult:

Page 4 of 4 Ali, Sustainable Technologies, Systems and Policies 2012.CCS.5

reservoir science and subservice phenomena are tough subjects for a nonspecialist to understand.

We had to coordinate Total staff from all disciplines to get the points across. Maitland followed up by asking if there was a feedback on the percentage of people convinced from the campaign. Monne responded by saying that quantitative assessment is one of the objectives of the project.

Ali ended the session with the provocative question: ‘‘what are the consequences of Total’s carbon capture and sequestration project on the environment?’’ Monne gave a detailed response which was supported by the appropriate slides from his presentation, particularly those referring to subsurface and microseismic monitoring, and to the monitoring of the surface and water supply. He mentioned that the interaction of CO2 with the subsurface minerals is a topic for CCS research. However, all the studies (geo-chemical, geo-mechanical) already carried out concerning the project’s local Rousse reservoir have shown that there was no major environmental impact of injected CO2 .

NOTES All presentations and related materials referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Alternatives to amine-based capture & new technologies Chair: Farid Benyahia Qatar University, Doha, Qatar

PRESENTATION Ionic liquids as novel materials for energy efficient CO2 separations Richard D. Noble and Douglas L. Gin Chemical Engineering Department, University of Colorado, Boulder, CO, USA Large improvements in separations technology will require novel materials with enhanced properties and performance. The fundamental interlinks for success in merging synthesis and process incorporation are the structure, relevant physical/chemical properties, and performance of new materials. Specific materials with these interlinks are room-temperature ionic liquids (RTILs) and their polymers and composites. As a chemical platform, RTILs have an enormous range of structural variation that can provide the ability to ‘‘tune’’ their properties and morphology for a given application. Introduction of chemical specificity into the structure of RTIL-based materials is an additional key component.

Membrane separation is the focus as a process for implementation. There have not been new materials successfully developed for this process in thirty years. For CO2 capture, the target improvement in productivity is two orders of magnitude or more compared to commercial materials currently available.

PRESENTATION Metal-organic frameworks and porous polymer networks for carbon capture Julian Patrick Sculley, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe Zhou Chemistry Department, Texas A&M University, College Station, TX, USA

http://dx.doi.org/ 10.5339/stsp.2012.ccs.6 Published: 17 December 2012 c 2012 Benyahia, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

The ability to rationally design materials for specific applications and synthesize materials to these exact specifications at the molecular level makes it possible to make a huge impact in carbon dioxide capture applications. Recently, advanced porous materials, in particular metal-organic frameworks (MOFs) and porous polymer networks (PPNs) have shown tremendous potential for this and related applications because they have high adsorption selectivities and record breaking gas uptake capacities. By appending chemical functional groups to the surface of these materials it is possible to tune gas molecule specific interactions. The results presented herein are a summary of the fundamentals of synthesizing several MOF and PPN series through applying structure property relationships.

PRESENTATION Introduction to market challenges in developing second generationcarbon capture materials Jason Mathew Ornstein, Executive Director, framergyTM Cite this article as: Benyahia F. Alternatives to amine-based capture & new technologies, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:6 http://dx.doi.org/10.5339/stsp.2012.ccs.6

Page 2 of 5 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.6

Absent an economic or social cataclysm, there is no plausible way to meet what will be the world’s unavoidable energy demands without utilizing its vast supply of fossil fuels.

One important technology being contemplated to mitigate the negative impact of anthropogenic carbon dioxide loading of the atmosphere is Carbon Capture and Storage (CCS). CCS will play a vital role in least-cost efforts to limit global warming1 . To achieve future least-cost solutions, second generation or ‘2.0’ carbon capture materials are being developed with government support to improve efficiencies over the current applied solution that is ‘‘a very expensive proposition’’1 for the installed energy generation base. One 2.0 material, Metal Organic Frameworks (MOFs), is ‘‘capable of increasing (carbon dioxide) selectivity, improving energy efficiency, and reducing the costs of separation processes’’1 in CCS. Such materials can address CCS utilization outcomes in addition to lowering the carbon capture cost. To support further 2.0 carbon capture material development while CCS faces economic challenges, framergyTM is leveraging alternative usages for MOFs and other 2.0 materials developed for carbon capture.

PRESENTATION CCS from industrial sources Paul S. Fennell1⇤ , Nick Florin1 , Tamaryn Napp2 , Thomas Hills1,2 .

1 Department of Chemical Engineering, Imperial College, London, UK 2 Grantham Institute for Climate Change, Imperial College London, UK

The literature concerning the application of CCS to industry is reviewed. Costs are presented for different sectors including ‘‘High Purity’’ (processes which inherently produce a high concentration of CO2 ), Cement, Iron and Steel, Refinery and Biomass.

The application of CCS to industry is a field which has had much less attention than its application to the electricity production sector. Costs range from less than $2011 10/tCO2 up to above $2011 100/tCO2 . In the words of a synthesis report from the United Nations Industrial Development Organisation (Unido) ‘‘This area has so far not been the focus of discussions and therefore much attention needs to be paid to the application of CCS to industrial sources if the full potential of CCS is to be unlocked’’.

DISCUSSION Editor’s note. Ornstein gave his presentation slightly later in the program but, since it follows closely the work discussed by Zhou, it is included here.

This segment first covered three papers and presentations on carbon capture using techniques that could replace the well-established procedures of amine scrubbing. A motivation is that these alternative techniques, or their variants, will have to be considered commercially. Ornstein put this forcibly. He quotes Herzog1 : ‘‘Today, the only proven CCS capture technology is amine scrubbing. In some ways it works very well – it is highly selective for CO2 and has recovery rates above 90%...It makes retro-fitting older, less efficient plants very difficult. For example, an existing plant with 35% efficiency when retrofitted with CCS will have its efficiency reduced to 20–25%. This is a very expensive proposition.’’

Hanley, however, submitted this observation: Zhou and Ornstein have made the point that the energy penalty to regenerate MEA solutions could account for 35% of a power plant’s energy output.

An argument in favour of using an alternative is that this loss could be reduced. It would be fairer, however, if the efficiency of an amine alternative was assessed in comparison with that of many of the commercial amine solutions. (But, of course this latter information is usually confidential.) Along these lines, do the authors have any comments on how – with respect to energy consumption – their alternative capture techniques might compare with the traditional amines? Ornstein responded with the statement that the materials licensed from Dr. Zhou’s group would have a significant energy 1 http://sequestration.mit.edu/pdf/Research_Program_for_Promising_Retrofit_Technologies.pdf.

Page 3 of 5 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.6

savings due to their lower regeneration heats, corresponding to a potential approximate 40% reduction in the parasitic energy.

Noble started the session with his presentation on ionic liquid solvents and membranes. Hanley raised the point that the possible environmental hazards of ionic liquids have been questioned, but Noble rebutted by stating that the chemicals he is discussing are not toxic and, furthermore, are safe enough to be ingredients in cosmetics.

Palmer asked what would be the physical size of the ionic liquid capture unit in a power plant and Noble responded: ‘‘the unit would be the same size as an amine scrubber for a liquid. For a membrane configuration, with the membranes stacked vertically, the volume would be in the order of a few thousand square meters.’’ Ornstein added the cautionary comment that replacing solvent scrubbing with a membrane could be challenging commercially because of the volume of flue gas that would need to be processed.

Kira Schipper (TNO) asked how the ionic systems would react for flue gas with significant amounts of water vapour. Noble answered by stating that there is some vapour in the system (bound water), but water vapour does not affect the membrane which, for example which we have confirmed does not swell. In fact, a hydrophobic membranes can be formed specifically to remove any water present.

Moene followed this up: ‘‘building on the previous point on water: from past experience we know amine and water react. Is this important in this case?’’ Noble replied that the chemistry/reaction conditions are different for his systems because the ionic liquid is a different solvent than water.

Thus, the amine reactions do not follow the same stoichiometry and, in some cases, do not include water in the reaction mechanism.

In his talk Noble quoted that an approximate cost of CO2 capture was $10/tn. Fennell picked up on this and asked if that estimate could be explained. Noble stated that the economic analysis was carried out by third parties and he could not give a precise answer. He did, however, note that a membrane only has a small ionic liquid content, which would keep the costs down. Following up on the membrane format, Fennell asked how many cycles do the membranes last. Noble answered that he had not explicitly tested for this but he has yet to see any effect of membrane degradation.

Maitland speculated what would happen if you added the ionic liquid/amine phase to the polymer membrane, instead of only the ionic liquid. Noble acknowledged this was a good point and his group was looking into it; he would expect improved performance.

After the technical presentations of Noble and Zhou, the audience was interested in the presentation of Ornstein who discussed the promotion of alternative capture technologies, particularly that of his colleague, Dr. Zhou. Unfortunately, as is often the case with discussions on problems of industrial concern, we cannot give a published summary of the questions and answers because much of the material is privileged.

There was, however, a lively debate following Ornstein’s remarks on projected storage difficulties.

He offered the opinion that the Carbon Capture Storage picture might have changed. Accordingly: ‘‘Without a storage option, the concept of ‘utilization’ for captured carbon dioxide from CCS has gained popularity. Several key organizations have relabeled CCS by adding ‘‘utilization’’ to the acronym, thus CCUS, or sometimes – as in the UK – even removing the word storage altogether, thus CCU.’’ That utilization rather than storage might be a path to follow lead to the following comment from Fennell: ‘‘If the UK is actually diverting into carbon capture and utilisation (CCU), I disavow my countrymen. Carbon dioxide utilisation is a dangerous distraction from CCS. Roughly 30Gtn of CO2 are emitted per year worldwide. The total utilisation of CO2 , excluding EOR is of the order of 100 Mtn/year—orders of magnitude less. Moreover, most processes capturing CO2 (particularly urea production, at 65–146 Mtn/ year, release the CO2 immediately after production). The other main processes of methanol, polyurethanes, technological and food and drink production, use around 10 Mt/yr each.

Utilisation is nothing compared to total CO2 emissions and it is nonsense to suggest that they are part of the solution to global warming.’’

Page 4 of 5 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.6

Ornstein countered: ‘‘I am not saying that there is a policy towards CCU in the UK at the moment, but certainly it’s something that’s been looked at. It may not be a permanent solution, or solution on its own, but certainly a step change towards a more broad approach. In addition, this approach may help to mobilise capital in this area towards CCS.’’ Fennell submitted this response: ‘‘I was an expert reviewer for the CCU report produced by the centre for low carbon futures in the UK, to which I presume you refer. There were many aspects which I found highly troubling—many changes suggested were not made (this is reflected in the introduction). You have suggested that mobilisation of capital into the area of CCS may be predicated in the US on CCU applications. Again, this is potentially a worrisome area because if technologies have a niche CCU application, sub-optimal technologies for full-chain CCS may be developed and promoted. At the end of the day, CCU will do almost nothing for climate change, owing to the tiny amounts of CO2 used.’’ ‘‘From a private capital perspective, pointing out to governments that CCU could be a good investment is important for moving things forward financially,’’ replied Ornstein.

Contributing to this debate, Zhou made the observation that storage, in contrast to CCU, is going to be very difficult to push forward without any accepted national and international policy: a problem that has been alluded to by previous speakers and will be taken up again.

Part of Fennell’s lecture followed up the comments made on the first day in that he reminded the attendees that carbon capture issues are not only fossil fuel related—which tends to be the public’s perception. He discussed, for example, the significant amount of carbon produced by cement production and the iron and steel industry with possible ways to reduce and/or capture it. The technique of Calcium Looping was promoted as a realistic viable procedure.

Hanley submitted a comment and question. Shown is Fennel’s slide (Fig. 1) indicating a possible interaction between cement processing and the production of electricity. The observation is consistent with a theme discussed at the onset of the Workshop: namely, that the necessary carbon emission reduction will be impossible unless there are substantial improvements in energy efficiency, together with process integration. He asked Fennell if this potential linkage in the cement production process is being researched, or was even at a proof-of-concept stage.

Integration with Ca looping

flue without CO2

CaO purge

limestone

CO2

CaO purge + fresh limestone

Cement plant

CaCO3 flue

coal, air

carbonator

N2

calciner CaO O2 coal

Unlike most other CO2 capture technologies, the exothermic reaction capturing CO2 occurs at a sufficiently high temperature (650°C) hat electricity can be generated from it.

Consequently, highly thermodynamically efficient , and an important synergy with electricity generation.

Also, if applied to a power plant, the spent CaO can be directly used in cement manufacture, eliminating more than 50% of the emissions from the cement works and leaving no residues from the power generation.

Sorbent costs are virtually zero (~ £ 20 / ton) If all fossil capacity were fitted with Ca looping, run 1/3 of the time, and a reasonable purge flowrate were used, the electricity industry produces exactly the correct amount of CaO for current cement manufacture.

Figure 1. Integration with Ca looping.

ASU air

Page 5 of 5 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.6

Fennell replied that there is indeed some research ongoing around the world into this synergy [1–3], with research at Imperial College [4] being the first to demonstrate experimentally that the spent material from the calcium looping technology described is actually suitable for use in cement manufacture. This was done by demonstrating that the cement produced has similar properties to that produced from fresh limestone. The research is supported by Cemex, the world’s third largest cement manufacturer. Indeed, Alstom and Heidelberg Cement [5] have also recently announced that they will trial the technology, with a view to potential scale-up.

NOTES All presentations and related materials referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

REFERENCES

[1] Bosoaga A., Masek O. and Oakey J.E. CO2 Capture Technologies for Cement Industry. Energy Procedia. 2009;1:1, 133–140.

[2] Dean C. et al. The calcium looping cycle for CO2 capture from power generation, cement manufacture and hydrogen production. Chem. Eng. Res. Design. accepted [3] González B. et al. Calcium looping for CO2 capture: sorbent enhancement through doping. Energy Procedia.

2011:4, 402–409.

[4] Dean C.C. et al. The calcium looping cycle for CO2 capture from power generation, cement manufacture and hydrogen production. Chem. Eng. Res. Design. 2011;89:6, 836–855.

[5] Alstom, http://www.alstom.com/press-centre/2011/6/alstom-heidelbergCement-study-co2-capture-technologiestested-norcem-cement-plant-norway/, accessed 4th August 2012.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Transport Chair: Farid Benyahia Qatar University, Doha, Qatar

PRESENTATION Shipping and CCS: A systems perspective N. Mac Dowell and N. Shah Centre for Process Systems Engineering, Dept. of Chemical Engineering, Imperial College London, UK In this contribution, we present an overview of the contribution made by the shipping sector to global CO2 emissions. We review the currently proposed technology options for mitigating these emissions, and propose a new option for the control of greenhouse gas emissions from shipping.

PRESENTATION Green shipping Talal Al-Tamimi RasGas Company Limited, Doha, Qatar The state-of-the-art facilities of RasGas and QatarGas process natural gas from Qatar’s North Field, the World’s largest non-associated gas field. At the Ras Laffan site, gas is liquefied to LNG and then loaded to tankers for transportation. But along with the objective of supplying LNG to customers as efficiently as possible comes the responsibility to be environmentally aware and, in particular, to ensure that any carbon emissions during the loading and transportation are minimised. The presentation outlines RasGas’s approach.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.7 Published: 17 December 2012 c 2012 Benyahia, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

The transportation of LNG by the giant tankers designated Q-Flex and Q-Max–vessels with cargo capacities of the order of 215,000 m3 and 266,000 m3 , respectively–is discussed. A key point is that, although these vessels are much larger than the conventional carriers, the fuel consumption is almost the same, with obvious economic and environmental advantages. It is emphasised that carbon dioxide emissions to the atmosphere from the LNG cargo itself are minimal since the carriers are fitted with on-board facilities to liquefy the boil-off gas and return the LNG to the cargo tanks.

Mentioned is a proposal to retro-fit systems so that natural gas can be delivered to the existing diesel main engines: LNG from the vessel’s cargo tanks will be vaporized and the gas used as the fuel. The benefits of replacing marine diesel fuel with gas are delineated, not only with respect to carbon emission reduction, but also to ensure that the legal restrictions on the sulphur content of a marine fuel are satisfied.

Finally, the Jetty Boil-off Gas Recovery Project (JBOG) is discussed. The project is a major attempt to reduce the BOG generated and flared at the Ras Laffan LNG terminal. It is remarked that GHG emissions can be substantially reduced and the recovered gas can be used to generate a significant percentage of the power required by the State of Qatar.

Cite this article as: Benyahia F. Transport, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:7 http://dx.doi.org/10.5339/stsp.2012.ccs.7

Page 2 of 3 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.7

DISCUSSION Several in the audience remarked that it was interesting to learn from Mac Dowell’s talk that the CO2 emissions from shipping are approximately equivalent to that from road transport and aircraft.

Apas Bandyopadhay (Qatar Ministry of Environment ) followed up Mac Dowell’s outline of the special requirements for ship-board capture facilities; two points, for example were mentioned in the paper: that the size of the equipment has to be minimal and, if the equipment was solvent based, the solvent had to have low volatility—to avoid, in particular, a potential fire hazard.

Mac Dowell recommended ammonia as a possible candidate. Bandyopadhay then asked if ammonia had been used in shipping. Mac Dowell said: ‘‘To my knowledge ammonia hasn’t been used as a sorbent for CO2 capture from shipping. I think that it is a possible solution though as it is cheap and produces useful byproducts during the capturing process. Other amines, for example MEA, have in fact been onboard submarines for years. So solvents are a feasible solution—though making them operate on the small scale with low energy requirement would be the challenge.’’

The audience, especially those visitors to Qatar, appreciated Al-Tamimi’s description of the huge tankers, designated Q-Flex and Q-Max, in Qatar’s LNG fleet. Discussion was stimulated by the contents of his slide reproduced in Fig. 1. Many in the audience, for example, learnt that the LNG cargo itself does not contribute directly to CO2 emissions. Mac Dowell and others remarked that improvements in fuels, and in ship construction and operation in general, would give significant reductions in GHG pollutants. Lindstedt, for instance, remarked that more efficient propeller systems would obviously reduce emissions.

Economies of Scale The Q-Flex/Q-Max fleet:

.Benefit from economies of scale where more LNG can be transported per journey thereby lowering the transportation cost per unit of LNG. Although those vessels are much larger than the conventional vessels the fuel consumption is almost the same. This means that by using larger vessels the number of voyages are reduced resulting in lowering emissions to the environment. .Those vessels are fitted with a reliquefaction plant. Gas venting into the atmosphere is very unlikely in this type of LNG carrier. .In contrast to conventional LNG vessels these Q-Flex and Q-Max vessels can deliver all the cargo loaded as well as act as an efficient floating storage facility.

Figure 1. Description of economies of scale of the Q-Flex/Q-Max fleet, from Al-Tamimi’s slides.

Robert Steele (QatarGas) stated that the Qatar fleet used a 5% pilot fuel largely in order to satisfy the mandated maximum sulphur content, but he also added that converting the engines to burn natural gas is an obvious solution to reducing sulphur and other pollutant emissions. Al-Tamini reinforced this statement: ‘‘Using LNG as energy source onboard the LNG carriers will reduce the amount of sulphur produced from the vessels and will allow the vessel operators and the charteres to comply with the mandatory rules inside the emission controls area in Europe and other parts of the world.’’

Attendees took up Al-Tamimi’s brief overview of the Ras Laffan Jetty Boil-off Gas Recovery Project; to quote from the website (April 4th, 2012)1 : ‘‘The ‘Jetty Boil-off Gas (JBOG) Recovery Project’ aims to recover gas currently being flared during Liquefied Natural Gas (LNG) ship loading at the Port of Ras Laffan. The 1 http://www.zawya.com/story/Qatargas_Jetty_Boiloff_Gas_Project.

Page 3 of 3 Benyahia, Sustainable Technologies, Systems and Policies 2012.CCS.7

project is part of the Common Facilities Projects at Ras Laffan Industrial City in the north of Qatar. The project will enable boiled-off gas to be collected from LNG ships and compressed at a central facility. The compressed gas will then be sent to the LNG producers to be consumed as fuel or converted back into LNG. This project, when fully operational, will recover the equivalent of some 0.6 million tonnes per year of LNG.’’ Thus, not only would a reduction in flaring reduce GHG emissions directly, the recovered gas could be used to generate power for domestic consumption.

NOTES All presentations and related materials referred to in this article are available as ‘Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

O PE N ACCE SS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Meeting report

Economic and social issues Imperial College, London, UK

Chair: Iain Macdonald

PRESENTATION The carbon conundrum: GCC perspectives Farid Benyahia Department of Chemical Engineering, Qatar University, Doha, Qatar The solution to the carbon conundrum does not seem to be within reach in the short or medium term despite significant advances and knowledge gains in demonstration scale CCS facilities. This stems from the fact that currently carbon management has no binding policies and legal framework. Without this legislation, it is unlikely that international cooperation in carbon trade and management would flourish.

The situation is also exacerbated by doubts about the suitability of sites and global capacity to store captured CO2. Sophisticated cost models have been developed for carbon capture and storage, and these indicate that cost reduction in the complete carbon value chain should be focused on the capture phase as this is the most energy intensive. However, there are uncertainties about properly costing carbon storage as this should involve search for suitable site location costs. The GCC states have characteristics that make them one of the largest consumers of fresh water and energy in the world, and by default emitters of CO2 per capita. There are currently no demonstration or commercial scale CCS facilities in the GCC and in the short term, it is unlikely to be the case given that current carbon capture technologies favor coal rather than natural gas as fuel in power plants. It is also unlikely that underground carbon storage be considered in the short term, given the risk of CO2 plume migration that may displace brine in saline formations into strata containing hydrocarbon resources or potable. It is therefore imperative that substantial research be conducted to identify storage sites, reduce energy consumption in carbon capture and develop alternatives to CCS in the form of carbon conversion into useful products or minerals with low environmental impact. The GCC have tremendous opportunities to lead the world in carbon management given their strong experience in hydrocarbon processing. However, this may only be successful if agreed policies and legal frameworks are in place to facilitate a robust carbon pricing.

DISCUSSION

http://dx.doi.org/ 10.5339/stsp.2012.ccs.8 Published: 18 December 2012 Š 2012 Macdonald, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Benyahia’s talk gave balance to the workshop in that it stimulated a healthy debate on many of the technical and political problems that proponents of the carbon capture storage chain must address if CCS is truly going to make a lasting global impact. He noted, for example that potential underground storage areas are by no means distributed evenly over the Earth’s surface; he mentioned that there were many unresolved safety and legal issues relating to transport and storage.

Bandyopadhay opened the discussion by asking if carbon dioxide will be considered a commodity or waste product? What will be the long-term effect of stored CO2?

The first part of the question recalled the earlier exchange between Ornstein and Fennell on the role of possible CO2 utilization. Maitland remarked that, at this time, the amount of CO2 converted is minuscule compared to the gross CO2 emissions. Fennell added the perceptive aside that high-value synthetic products, the synthesis of which is often discussed as a route for CO2 utilization, will not be high value for long if they were to be produced at a sufficiently large scale to affect climate change.

Cite this article as: Iain Macdonald. Economic and social issues, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:8 http://dx.doi.org/10.5339/stsp.2012.ccs.8

Page 2 of 5 Macdonald, Sustainable Technologies, Systems and Policies 2012.CCS.8

On the other hand, no one implied that CO2 utilization is not a practical and necessary commercial tool.

[Editor’s note. It turned out that an example of this approach in Qatar was publicized while the Workshop was underway. The press reported that The Qatar Fuel Additives Company (QAFAC) will be recovering CO2 from its Methanol Reformer stack and injecting it into its existing methanol plant to enhance the production capacity.

Khalid Mubarak Rashid Al-Hitmi (QAFAC) has kindly submitted a short paper which is reproduced in the Appendix.]

As to the second part of the question the long term effects of stored CO2, Benyahia implied it would be best answered by industrial experts (and, in fact it was a major theme during and after Monne’s talk at the Monday afternoon session) but he noted that information supplied to the general public on the storage issue could be improved. This lead to a submission by Korre, who wrote that this statement should be qualified. She referred to the several reports and papers from the GHGT series of conferences published in the public domain (Energy Procedia, Volume 1, Issue 1, February 2009 and Energy Procedia, Volume 4, 2011), and the papers in International Journal of Greenhouse Gas Control. She continued: “There are also many international projects that offer access to up-to date-knowledge in the field. In Europe, for example, entities such as SACS, CASTOR, CO2 GeoNet, CO2 ReMoVe, SiteChar, and CO2 CARE are active; there are national projects in many European countries (for example Imperial’s Multiscale CCS projects funded by the UK Research Councils); and North America has several regional CCS partnerships.”

Nevertheless, Benyahia responded with the opinion that communication with the general public through published material is hardly comforting or even convincing. He reinforces the point made by Monne in the earlier lecture that communication with the general public cannot be done through published articles alone, but by using simple language that is both accurate and has legal legitimacy.

At this stage Hanley submitted a comment. He suggested that the proponents of CCS should appreciate that many in the general public are cynical about CCS, especially as the cost will be borne by them. It is a given that industry and governments have taken a `reduce the possible risk’ approach and accepted that manufacturing processes and plant operations should minimize any resulting carbon dioxide emissions. This is the political and technical reality. This workshop was not the forum to discuss an exact relationship between carbon emissions, global warming, and human activity. Nevertheless, there is scope for a debate, if a debate could take place without emotions taking over.

As a coincidental aside, a paper was published online the day after the Workshop ended: Jeremy D. Shakun et. al., “Global Warming preceded by increasing carbon dioxide concentrations during the last deglaciation” Nature, 484, 4954, 2012. From a press release: “The study reveals that rising temperatures were preceded by CO2 increases during the last deglaciation . . .These results support an important role for CO2 in driving global climate change.”

The cynic might concede that increased atmospheric carbon dioxide will cause global warming but note that there was little industry around during the ice ages. Whether this is a specious conclusion or not, is irrelevant because many people will continue to argue that the carbon dioxide- human activity role is not definitive.

Ken Hall (Texas A&M University at Qatar) followed this up in his communication: “I am disappointed that no one mentioned the recent NASA data that essentially refute the claim that CO2 is the villain the global warming proponents claim. See, for example, http:// news.yahoo.com/nasa-data-blow-gaping-hold-global-warming-alarmism-192334971.html. In fact, shortly after the Workshop ended, it was reported that several former NASA scientists and astronauts sent a letter to the NASA Administrator ‘admonishing the agency for it’s role in advocating a high degree of certainty that man-made CO2 is a major cause of climate change while neglecting empirical evidence that calls the theory into question.’ See, http:// articles.businessinsider.com/2012-04-11/news/31322407_1_climate-change-nasa-scientistsgavin-schmidt. In general, the whole issue of anthropogenic CO2 (which accounts for about 0.0015- 0.003% of the atmosphere) destroying the planet seems a bit far-fetched, and yet many authors suggest spending trillions of dollars to eliminate the ‘problem.’ As several people at the workshop have remarked, this is social and political dilemma.”

Bandyopadhay asked Korre and others if you would you tell us how the areas where CO2 can be stored are chosen? Korre answered: “That depends on the formation characteristics and the presence of a competent and sealing caprock. Potential important operational properties include the storage formation capacity and

Page 3 of 5 Macdonald, Sustainable Technologies, Systems and Policies 2012.CCS.8

injectivity followed by injection well and formation pressure. With respect to the longer term storage performance and associated risk management, important issues include possible CO2 plume migration, potential pressure and stress changes in the storage formation and caprock, and any projected geochemical changes.

The discussion presented in the website (http://www.dnv.com/industry/energy/segments/carbon_capture_storage/ recommended_practice_guidelines/co2qualstore_co2wells/index.asp) is very informative. Further, industry has a wealth of experience demonstrated in the front-end engineering design studies prepared for various projects (e.g. http://www.decc.gov.uk/en/ content/cms/emissions/ccs/demo_prog/feed/scottish_power design/design.aspx). As, however, mentioned in the last two days by several speakers and participants, areas around the world capable for storing CO2 depend on public acceptance, particularly in densely populated areas.

An example includes the Barendrecht project in the Netherlands which was cancelled recently due to public concerns.’’

More comments on very long-term storage came up and many referred to the presentation of Benyahia and that of Monne of the previous day. Maitland, for instance, communicated: “Concerning CO2 monitoring/storage and issues relating to future predictions, there is a good understanding in modeling the relevant longer term mechanisms, i.e. capillary trapping, dissolution of CO2 in the aqueous phase, and mineralization. These models cover a wide range of timescales, from the immediate capillary trapping processes, to the decadal dissolution processes through to mineralization on the hundred-year horizon. Although 100% certainty may not be there, we believe that the models will yield reliable predictions and the basis for strong reassurance on the long-term robustness and safety of reservoir storage operations. So the challenge is to clearly communicate to the general public a quantified and simply voiced message to address the concerns.’’

Noble, however, was somewhat more cautious: “Despite reassurances, extrapolating predictions is dangerous. There are models for 20 years ahead, but do we really know what will happen in 100 years? No one can answer this question and this worries the general population. Care must be taken before quoting predictions.”

In this context, the infamous Lake Nyos disaster (http://en.wikipedia.org/wiki/Lake_Nyos) came up as an illustration of what might happen, but Fennell, cautioned that care must be taken when discussing this event.

Korre added that “It is very different to compare loss of containment at a managed geological site to loss of containment at a volcanic crater lake CO2 accumulation site. Natural sites for example, the Latera site in Italy, the Laacher See in Germany, and Panarea in Italy to name but a few along with field CO2 release experiment sites around the world are being studied extensively to test monitoring methods and to understand better ecosystem impacts from potential CO2 leakage from storage. (See http://nora.nerc.ac.uk/4777/, http://www.ieaghg.org/docs/General_Docs/Natr%20rel%20worksop/M.KRUEGER,%20 Ecosystem%20Effects_SEC.pdf and http://www.montana.edu/zert/).’’

Benyahia’s point. that legal issues relating to transport and storage must be addressed, was taken up by several participants. Mac Dowell, Fennell, and Maitland [with a contribution from N. Shah] submitted a lengthy comment: “The large scale transport of compressed fluids by pipeline or ship is by no means new, and does not, in and of itself, present a major challenge. There are obvious opportunities to import a lot of the required expertise for both the transport and subsequent injection and storage of the CO2 from the oil and gas industry. However, the deployment of national and/or international transport infrastructure requires large capital investment in addition to sustained political co-operation. As emphasized here, in particular by Monne, an important aspect of this part of the CCTS value chain is the provision of assurance to the public. This will require continuous and stringent monitoring of pipeline conditions. Furthermore, there are important questions

Page 4 of 5 Macdonald, Sustainable Technologies, Systems and Policies 2012.CCS.8

surrounding the ultimate liability for the captured CO2. It is highly unlikely that corporations will accept this liability, particularly in the time-scales that are relevant in the context of CO2 storage. One can envisage a scenario where a corporation would accept a limited-term liability perhaps a few decades after which, this liability would be assumed by the state. In this, we can take some examples from similar situations where waste material had to be stored securely for extremely long periods of time the nuclear industry. For example, in Canada, the federal government has jurisdiction over the nuclear industry and has adopted the polluter pays principle under which it has assigned liability in regard to waste storage to plant operators.

However, the federal government has assumed liability for ``historic’’ waste ``for which the original producer cannot reasonable be held responsible’’ or when the producer no longer exists.

The extensive and potentially international nature of these transport networks raises the obvious question of who pays for its deployment and operation. Essentially this comes down a question of a public or private source(s) of funding. However, regardless of the initial option, it is inevitable that the costs will, in one way or another be passed on to the consumer. In this instance, it might appear that a traditional Freidmanite line of argument would provide sufficient justification for this being privately managed. An important issue here is that there is, at the time of writing, no CCS industry.

The technological challenges are primarily associated with the purity of the gas stream. It is well known that small levels of impurities can significantly change the phase behaviour of CO2-rich streams, leading to abrupt phase transition and shockwave propagation. Further the formation of aqueous acid streams can compromise pipeline integrity; thus there is a clear requirement to control the pH of fluid streams for transport -potentially by blending streams from various sources.

Further, in large networks, network balancing is a concern. It is desirable to operate the network at more-or-less a steady state. This leads to a complex control problem, best solved by the decomposition of the network into a number of interacting, regional hubs. It is interesting to note that the network operator may need to incentivise injection of CO2 into the network at certain times, and penalise it at others. This clearly leads to a complex interaction between the CO2 producers and the transport and storage actors.’’

Another point that Benyahia made was that Qatar, and the Gulf States in general, had a special responsibility to tackle the CCS problem in that they are the world’s greatest GHG polluters on a per capita basis. Al- Hamed, (Qatar Petroleum) asked if this statement could be substantiated and Benyahia said this was documented in numerous statistical surveys. Fedaa Ali agreed that, per capita, Qatar is of the highest in CO2 emissions but stressed that the State is addressing both the move towards cleaner fuels and CO2 storage.

Hanley asked a general question: “It is well documented that the BRIC and other non-OPEC nations are, and most certainly will be, central to any efforts to remediate carbon emissions on the global scale. Naively one has to say that efforts to resolve CCS problems proposed largely by the OPEC-affiliated nations can be swamped by the action, or lack of action, by the others. Along these lines, I quote from the IEA Energy Technology Transitions for Industry report of 2009: `Many industries compete in global or regional markets, and so the introduction of policies that impose a cost on CO2 emissions in some regions, but not in others, risks damaging competitiveness and, in other words (may lead to) industries relocating to regions with lesser carbon restrictions.’ Have the projections of the CCS scenario taken these factors realistically into account?”

Benyahia responded by stating that heavy industries have indeed relocated from the West to other parts of the globe where energy and labor costs are low. Since the CCS costs related to several industries, including the petrochemical industry, could severely penalise profitability, the carbon issue may add to this migration pattern. Ethical considerations, however, could be a mitigating factor. Maitland added that, while this `migration’ effect of manufacturing processes to zero/low carbon charge areas might have some effect in delaying global implementation of CCS, it will be a relatively minor factor given that GHG emissions are dominated by heat and power generation which is locally-based and not amenable to long-distance supply.

Once CCS becomes established and accepted practice for the heat/power sector, political and social factors are likely to become more important in driving low-GHG emission manufacturing plants. Like previous environmentally/health-driven industrial process changes, such as SOx reductions once the consequences

Page 5 of 5 Macdonald, Sustainable Technologies, Systems and Policies 2012.CCS.8

of acid rain were realized or CFC elimination due to concerns about the ozone layer, it is difficult to predict where and when the tipping points for change will come. The economic consequences of climate change must also be factored into future energy scenarios as well as the carbon mitigation/CCS costs and carbon charges.

The workshop wound down with a summary remark from Maitland who said that the discussions during these two days of the meeting were intriguing both as far as new technical developments are concerned but also how existing technologies are applied commercially. Hanley expanded on this and submitted a rather gloomy reference to the current commercial situation. He recalled the inventory of active commercial projects listed by Palmer and others and recommends that reference be made to the comprehensive data base put out by the Global Institute for Carbon Capture and Storage: http://www.globalccsinstitute.com/ publications/data/dataset/status-ccs-project-database.

The database lists only eight operating commercial integrated capture and storage facilities with another seven under serious construction. Only two of these fifteen are power plants, including the Boundary Dam project discussed here by Schwander and Fabricius. Further, the estimated CO2 capture from all the items listed in the database ongoing, under construction and projected is around 130Mtpa, obviously a drop in the ocean compared to the global estimated annual emissions. The comment is not negative, rather it emphasizes the enormous financial, political, and technical commitment required if the goals so often expressed in this workshop are to be met.

Moene, (Shell), however, was positive and commented: ``carbon dioxide emission and climate change are coupled, this is a fact for Shell, and Shell intends to make CCS knowledge available to the global community.’’

Zhou had the last word: ``there are a lot of experts out there and lots was learned over these past two days. I remain hopeful that solutions will be found.’’

NOTES All presentations and related materials referred to in this article are available as `Supplementary Material’ online at http://www.qscience.com/toc/stsp//CCS+Workshop.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Carbon capture and storage: The way ahead Geoffrey C. Maitland* Department of Chemical Engineering, Imperial College, Exhibition Road, London SW7 2AZ, UK * Email:

g.maitland@imperial.ac.uk

ABSTRACT The paper gives a general introduction and overview of Carbon Capture and Storage (CCS) with an emphasis on the capture of CO2 and other greenhouse gases from the waste gas streams of power plants and industrial processes. This stage accounts for about 80% of the overall cost of the CCS process so is the area where efficiency and cost improvements will have the greatest future impact.

The major drivers for continuing to use fossil fuels for most of this century are first considered and the need to implement CCS as one of many measures to mitigate carbon emissions. Current targets will require a commercial CCS capacity to remove about 10Gte CO2 pa by 2050. The overall features of CCS processes are described – capture, compression and transport, sub-surface storage – covering the main capture options and the three main types of storage site (deep saline aquifers, depleted oil and gas reservoirs and unmineable coal seams). The current status of large-scale CCS demonstration projects is reviewed. The main classes of carbon capture technologies are then described, both those currently capable of large-scale deployment and those in development for the future. Finally the main challenges facing CCS, to make it a globally-deployed commercially viable technology, are summarised and suggestions made for future developments in the clean recovery and use of fossil fuels which combine CCS with sub-surface processing.

Keywords: Carbon Capture, CCS, Amine scrubbing, Calcium looping, CCS challenges, Sub-surface processing

http://dx.doi.org/ 10.5339/stsp.2012.ccs.9 Published: 17 December 2012 c 2012 Maitland, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Maitland GC. Carbon capture and storage: The way ahead, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:9 http://dx.doi.org/10.5339/stsp.2012.ccs.9

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INTRODUCTION Carbon Capture and Storage (CCS) is a technology that can in principle eliminate or substantially reduce the emissions of carbon dioxide (CO2 ) to the atmosphere resulting from the combustion and processing of fossil fuels to produce power, fuels, chemicals and carbon-based materials in centralised facilities, where CO2 can be extracted from the gaseous product streams and then be transported to suitable underground long-term storage sites. If widely deployed it can make a substantial contribution to carbon mitigation in the decades ahead and be a critical technology in enabling atmospheric CO2 concentrations to be maintained at levels that will avoid catastrophic climate change consequences. This paper gives an overview of the main technical, social and economic issues concerning CCS and the current status of its deployment, with a particular emphasis on the CO2 capture stage.

Figure 1 summarises the world’s energy landscape. Current world energy consumption amounts to about 15TW [1]. Whilst nuclear and emerging renewable energy sources, such as wind, tidal, wave, biomass, hydroelectric, geothermal and solar, are gradually making an increasing contribution to meet this demand, they currently contribute only about 20% globally. Fossil fuels provide the major share, 12.5TW [1], of our energy needs. By 2050 it is expected that global energy demand will double [2]. If we set aside solar and nuclear, the other sources are restricted to providing a few TW and collectively are unlikely to match even the current energy demand, let alone the large projected future increases. Nuclear energy could in principle meet a large proportion of this growing demand but its widespread implementation is still restricted by safety and security concerns and lead times for installation are long. Solar energy must be the long-term hope meeting long-term demand renewably; if we can harness effectively but a small fraction of the >105 TW of solar energy falling on the earth (36,000 TW on land), through a combination of thermal solar and photovoltaic processes, then our future energy needs will be assured. The challenges here are substantially improving efficiency and reducing costs and, whilst good progress has been made in recent years, the timescales for making this competitive are still long. Fossil fuels on the other hand have the capacity to provide about 25TW of energy even based on existing known reserves of both conventional and non-conventional (e.g. heavy oils, tar sands, shale oil/gas, coalbed methane, gas hydrates) sources [3]—and it is highly likely that significant further reserves will be discovered and economic routes to exploit them developed. So most projections are that we will need to continue to use fossil fuels to meet global demand for a large part of this century and that even by 2050 they will provide at least 60% of our energy requirements (see for example Fig. 2).

The Energy Landscape

current wotld consumption 15 TW

Hydroelectric: 4.6 TW gross, 1.6 TW feasible technically, 0.6 TW installed capacity Tidal/Wave/Ocean Currents: 2 TW gross

Fossil Fuels: Current 12.5 TW Potential 25 TW

Geothermal: 9.7 TW gross (small % technically feasible) Solar: 1.2 ×10 earth's surface, 36,000 TW on land

5 TW on

Wind 2-4 TW extractable Biomass/fuels: 5-7 TW, 0.3% efficiency for nonfood cultivatable land

Figure 1. Schematic of the world energy landscape indicating current and potential energy supply from fossil fuels and a portfolio of renewable sources.

There are several concerns with this scenario. One is that in continuing to use fossil fuels we are depleting a non-renewable resource, making such an approach non-sustainable and endangering the quality of life of future generations. In particular, some argue [4] that we are approaching, or have even reached, ‘peak oil and gas’ so that fossil fuels cannot meet growing energy demand for more

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1400 1200 1000

EJ

800 600 400 200 0 1990

2000 Other Renewables

2010 Biomass

2020 Years Nuclear

2030

2040 Oil

Gas

2050

Coal

Figure 2. Typical future energy projection by source (Intergovernmental Commission on Climate Change, Third Assessment Report 2001, Scenario A1T). Energy in exajoules EJ = 1018 joules.

than a decade or two. The continuing discovery of conventional oil and gas, the large global reserves of coal and the recent increasing amount of non-conventional oil and gas exploitation [1] all indicate that there are plentiful supplies of fossil fuels that could meet our energy needs well beyond 2050, albeit at an increasing cost as we must turn to increasingly hostile and difficult environments and more difficult to recover and process non-conventional sources. Just as the stone age did not end because we ran out of stone, it is increasingly clear that we will not stop using fossil fuels because we run out of coal, oil and gas.

The other major and more pressing concern is that the use of fossil fuels produces greenhouse gases (GHGs), of which the most predominant is CO2 , and the dramatic rise in such emissions from industrial and power generation processes [5] since the industrial (see Figs. 3 and 4) revolution leading to atmospheric levels of GHGs which the strong weight of evidence indicates are leading to significant climate change.

30

CO2 emissions from fossil fuel combustion and transformation (Gt)

25

20

15

10

5

0 1700

1800

1900

2000

2100

Year (-)

Figure 3. Emissions from fossil fuel combustion, and fuel transformation (Carbon Dioxide Information Analysis Centre CDIAC, http://cdiac.ornl.gov/ftp/ndp030/global.1751_2006.ems).

Current emissions of anthropogenic CO2 are about 30Gte pa (or 8Gte pa of carbon), an increase of 30% on 1990 levels [6]. Atmospheric CO2 levels have reached 390 ppm [7], already above the 380 ppm target set at Kyoto [8] in 1996 as the cap we must stay below to avoid major climate change. The current best case scenario adopted by the main climate change monitoring bodies such as IPCC [9] is to maintain atmospheric levels below 450 ppm [10] (see Fig. 5), which would still correspond to a mean global temperature increase of 2 C, still resulting in significant ice cap melting, sea level rises, spread of desert-like conditions and their adverse consequences for the human and

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2005 Sources of CO2 5,751.2 Fossil Fuel Combustion Non-Energy Use of Fuels Cement Manufacture Iron and Steel Production Natural Gas Systems Municipal Solid Waste Combustion Ammonia Manufacture and Urea Application Lime Manufacture Limestone and Dolomite Use Soda Ash MAnufacture and Consumption Aluminium Production Petrochemical Production Titanium Dioxide Production Ferroalloy Production Phosphoric Acid Production Carbon Dioxide Consumption Zinc Production Lead Production Silicon Carbide Production and Consumption

CO2 as a portion of all Emissions 83.9%

<0.5 <0.5 <0.5 0

25

50

75

100 125 150 175

TgCO2 Eq

Figure 4. Distribution of anthropogenic carbon dioxide emissions from power generation and industrial processes (Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2005, April 2007, EPA EPA 430-R-07002 http://www.epa.gov/climatechange/Downloads/ghgemissions/07ES.pdf).

16

∆T 1000 ppm

4-6°C

Global Carbon Emissions 8 GT

550 ppm

3-4°C

4

450 ppm

2°C

12

375 ppm [CO2] 2000

2010

2020

2030

2040

2050

2060

Year

Figure 5. Projection of evolution of global carbon emissions, mean atmospheric CO2 concentrations and likely man global temperature increases for three scenarios: ‘business as usual’ (red), capping mean CO2 levels at 550 ppm (orange) and capping mean CO2 concentrations at 450 ppm (green, the preferred scenario).

animal habitat. To achieve this modest target will require the reduction of CO2 emissions to 80% of pre-1990 levels by 2050, amounting to the reduction of CO2 emissions by 50Gte pa by that date.

Failure to achieve this goal will result in more extreme climate change consequences—see Fig. 5.

Although most discussion of climate change focuses on the release of CO2 from power generation plants, other GHGs [11] and other processes are also a major concern. Although over 80% of GHG emissions come from energy-related sources, and CO2 represents 94% of all GHG emissions, the impact of major industrial processes such as cement and iron and steel manufacture is coming under increasing scrutiny [12,13]. The other major GHGs are methane (5% of total emissions) and oxides of nitrogen (1%); these have a global warming capacity respectively 40 and 250 times that of CO2 , although their persistence duration in the upper atmosphere is significantly shorter than that of CO2 due to photochemical degradation. Nevertheless prevention of their release (by for example reduced natural gas flaring and the use of pure oxygen rather than air for power combustion processes – ‘oxyfuel’ – as well as capture and storage) will make a useful contribution to reducing climate change.

This degree of carbon mitigation will not be achieved by a single approach; it will require a portfolio of solutions (see Fig. 6) [14]. About 50% of the CO2 emission reductions can be achieved by improved end-use and power generation efficiencies and fuel switching (e.g. from coal and oil to gas, whose use results in a 50% reduction in CO2 emissions at constant energy provision). Another 30% of the required reduction can be achieved through the increased use of affordable renewable and

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70

Baseline emissions 62 Gt

CCS industry and transformation 9%

60

CCS power generation 10% Nuclear 6%

CO2 emissions (GtCO2/yr)

50

Renewables 21% 40

Power generation efficiency & fuel switching 7%

30

End-use electricity efficiency 12%

20

End-use fuel efficiency 24%

End-use fuel switching 11%

BLUE Map emissions 14 Gt 10

0 2005

WEO 2007 450 ppm case

ETP 2008 BLUE Map scenario 2050

Figure 6. Portfolio of CO2 reduction mechanisms required to reduce mean atmospheric CO2 concentrations from the ‘business as usual’ scenario (red in Fig. 5) to the preferred 450 ppm scenario (green in Fig. 5) (from International Energy Agency, Energy Technology Perspectives, 2008).

safe, low waste nuclear energy. However, the remaining 20%, at least, must be achieved by capturing and storing as much as possible of the CO2 and other GHGs released by the extraction, processing and use of fossil fuels. This capability, alongside the other measures, will enable the continued use of fossil fuels into the second half of this century but will require the global capacity to capture and store 10Gte CO2 per annum. Given that today there are no fully commercial CCS projects and only eight demonstration projects that meet the large-scale integrated project criteria [15] (>0.8 Mte CO2 pa captured and stored – see Fig. 7), which collectively with the 40 or so smaller projects planned or underway give a current global CCS capacity of barely 10Mte CO2 pa, achieving this is a daunting task.

Figure 7. Demonstration projects that meet the large-scale integrated project criteria (from Global CCS Institute 2011, ‘The global status of CCS 2010’).

The International Energy Agency, in its 2010 CCS Technology Roadmap [16], estimates that meeting the 2050 CCS target will require about 3500 commercial-scale projects by that date, representing about 100 systems coming on stream each year from 2020 onwards (see Fig. 8).

CARBON CAPTURE AND STORAGE—THE OVERALL PROCESS The CCS process involves three main stages (see Fig. 9): - Capture of CO2 (and sometimes other GHGs) from waste product gas streams of centralised fossil fuel burning facilities e.g. flue gas from coal-fired power plants, cement manufacture.

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12000

4000

Number of projects

3000

OECD North America OECD Europe

10000

OECD Pacific China & India 8000

Other 2500

CO2 captured (world)

2000

6000

1500

captured (MxO2/yr)

3500

4000 1000 2000

500 0

2010

2015

2020

2025

2030

2035

2040

2045

2050

0

Figure 8. Projection of commercial scale CCS projects required to achieve the 450 ppm scenario, equivalent to capturing 10Ft CO2 pa by 2050 (IEA, Technology Roadmap, CCS, 2010).

Figure 9. Schematic summary of overall carbon capture and storage process, indicating the range of CO2 emission sources and storage sinks involved (N. H. Florin and P.S. Fennell, Imperial College London, Grantham Institute for Climate Change, Briefing paper No. 3, November 2010).

- Compression of CO2 to supercritical state (T > 31 C, P > 72 bar) and transportation (via pipeline or tanker) to storage site.

- Injection of supercritical CO2 into a suitable (in terms of injectivity, storage capacity and long-term storage integrity) sub-surface storage site; this needs to at depths greater than 800 m to maintain supercritical fluid conditions.

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In the supercritical state CO2 has a similar density to oil, 600–700 kg m 3 , slightly lower than water but about 600 times greater than gaseous CO2 at lower pressures. This has obvious advantages for both transport and storage. However the viscosity in the supercritical state remains similar to that of a gas so whilst this aids injectivity, care must be taken to ensure that there is good, relatively uniform displacement of the in situ fluids (unrecovered oil, reservoir brines) by the supercritical CO2 , avoiding the fingering instabilities that can arise in multiphase fluid displacements involving fluids of greatly contrasting viscosity. These fluid mechanical issues are one of the major challenges of designing effective carbon storage processes.

There are three main types of subsurface storage sites suitable for CO2 storage (see Fig. 10).

Power station with CO2, capture

Injection well

Figure 10. The three major types of storage sites being exploited for long-term CO2 sequestration.

(Source: IEA Greenhouse Gas R&D Programme).

The largest potential capacity (estimated to be up to 10,000Gte CO2 ) are deep saline aquifers [17,18]. Close to 2000Gte CO2 capacity is considered to be available in depleted oil and gas reservoirs. For some of these reservoirs, where the pressure has still not fallen below the minimum miscibility pressure (for CO2 /oil), there is the additional incentive of using the initial CO2 injection to lower the in situ oil viscosity and recover a significant fraction of the oil in place that has not been produced during the secondary water-flooding production phase—enhanced oil recovery (EOR) [19], see Fig. 11. The value of the resulting additional recovery can be used to offset some or all of the costs of the CCS process and help minimise the additional cost of producing ‘green’ power from fossil fuels.

Figure 11. Schematic diagram of CO2 enhanced oil recovery (D. Hussain, www.insanemath.com).

The suitable aquifers and depleted reservoirs will be a mix of sandstone and carbonate reservoirs.

The differences in the structure (broader pore size distribution and more natural fractures in carbonates) and geology/chemical reactivity to CO2 (carbonates will dissolve in acidic CO2 /brine fluids, resulting in reactive transport and complex dissolution-precipitation processes, making porosity and permeability variable in time and space in carbonates in contrast to the relatively inert and time-invariant rock matrix of clastic reservoirs) means that there are major design challenges in optimising the injection and retention of CO2 in different types of geological environment.

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A third option is to store the CO2 in unmineable or uneconomic (e.g. offshore) coal seams. Here the trapping mechanism for the CO2 is strong adsorption on the high internal surface area of fractured, porous coal. Initially methane is adsorbed on the coal and is displaced by the more strongly adsorbing CO2 , resulting in the production of large quantities of the cleanest fossil fuel, natural gas (50% CO2 emissions compared to oil and coal) alongside the effective long-term sequestering of CO2 . This process is known as Enhanced Coal Bed Methane, ECBM [20], and estimates of the available storage capacity vary widely, from 50 to over 1000Gte CO2 [17,18].

Overall it is safe to say that globally there is proven storage capacity for at least 2000Gte CO2 , or about 10 times the amount of CO2 targeted for capture between now and 2050 (ramping up to 10Gte CO2 pa by 2050). Since it is very likely that more storage capacity will be identified and verified in future years, especially once CCS becomes a viable commercial process, then the ability to deploy CCS as an effective carbon mitigation mechanism is unlikely to be limited by available storage capacity. A bigger challenge will be posed by the juxtaposition of sources of CO2 emissions and suitable storage sinks—the selection of suitable storage sites relatively close to major emission sources and the development of effective CO2 transportation networks (national and trans-national CO2 grids) to make optimal use of available storage capacity (maybe linked to possible EOR or ECBM opportunities) wherever that is located.

Complex though the underground storage processes are, there is a wealth of field experience in the oil and gas industry over many decades of injecting CO2 and other gases into subsurface formations for EOR, reservoir re-pressurisation or gas storage applications [21]. The major technical and economic challenges lie in the upstream carbon capture stage. Here again there are three major types of process currently being deployed in demonstration projects or under consideration for future commercial deployment in power generation or industrial manufacturing processes—see Fig. 12.

Post combustion

N2 O2

Coal Gas Biomass

CO2 Separation

Power & Heat Air

Coal Gas Biomass

Pre combustion

CO2

Air/O2 Steam

Gasification Gas, Oil

CO2 H2

Reformer +CO2 Sep

Power & Heat

N2O2

Air

Oxyfuel

Coal Gas Biomass

Power & Heat Air

Indusrial Processes

Coal Gas Biomass

Air Separation

CO2 Compression & Dehydration

CO2 N2

Air/O2 Process+CO2 Sep Raw material

CO2

Gas, Ammonia, Steel

Figure 12. Schematic representation of major classes of carbon capture processes ( www.kbr.com).

These are [22,23]: - Post-combustion capture of CO2 , in which the fossil fuel is first burned in air to provide the heat for e.g. steam production for driving turbines for electricity generation, resulting in a nitrogen-rich flue gas from which the CO2 (and other GHGs) is removed by solvent or solid adsorption or other processes under development.

- Pre-combustion capture, where the fossil fuel is converted – by for example steam reforming (gas) or gasification (coal, tar sands...) – to synthesis gas (‘Syngas’, a mixture of hydrogen and carbon monoxide) and subsequently via the water gas shift reaction CO + H2 O ! CO2 + H2 to CO2 + H2 . The CO2 is then captured from this stream whilst the H2 is used as a ‘clean’ fuel to generate electricity using gas turbines, to power fuel cells or as an energy source for manufacturing processes. Alternatively, or alongside this, Syngas can be used as a feedstock to produce liquid fuels or chemicals via catalytic Fischer-Tropsch like processes.

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- A third alternative, which has growing impetus, is oxyfuel combustion whereby the fossil fuel is combusted using pure oxygen rather than air, resulting in a flue gas containing mainly CO2 and steam. Condensation of the steam results in a concentrated CO2 with minor impurities (such as SO2 , H2 S which may require a desulphurisation stage) which can be compressed and transported directly to storage. Here the gas separation stage is relatively cheap; the major costs of the process are however simply transferred upstream to an initial air separation stage.

Cryogenic distillation is the current preferred but expensive option; more cost-effective options such as gas membranes are currently under development.

Post-combustion capture has the advantage that it is relatively easy to retrofit to existing plant whereas the other two approaches are best introduced as part of a new build. Industrial processes can use any of these options, depending on the nature of the feedstocks and the precise requirements and constraints of the process. Again post-combustion capture is likely to be the most viable option for existing plant.

A typical cost breakdown for the full carbon capture and storage chain is illustrated in Fig. 13. By far the most expensive stage is carbon capture, amounting to about 80% of the total cost [24–26]. The precise costs depend on the type of capture process used, the composition of the CO2 -containing gas stream, the nature and location of the storage site relative to the CO2 sources and the mode of transportation. However, typically costs per te CO2 are $50–100 for capture, $10 for storage, $2 for transportation and $1–2 for long-term monitoring. These add about 1–3 cents per kWh to electricity generation costs. $10-20 per te CO2

Storage –

Transport $10 per te CO2 per 250 km

Capture $50-100 per te CO2

Figure 13. Relative costs of components of carbon capture and storage processes.

There are currently eight integrated CCS demonstration projects which are categorised as Large Scale Integrated Projects (LSIPs): Mte CO2 pa captured and stored >0.8 for coal power plants or >0.4 for gas power plants or industrial processes. These were summarised in Fig. 7 [15]. They are located in Norway (2), Algeria, Canada and USA (4). A major US investment is the FutureGen $1.5bn clean coal project [27].

The world’s first field demonstration project was the Norwegian North Sea Sleipner project [28] which injects CO2 separated from produced gas into the relatively permeable Utsira Sand formation.

About 1Mte CO2 is injected pa using a 3 km horizontal injection well; to date over 11Mte of CO2 have been injected since the project started in 1996. Gravity segregation and flow under 800 m of impermeable shale controls the CO2 movement. Major drivers for this project were the imposition of a Norwegian carbon tax (⇠%55 per te CO2 ) in 1991 and the need to reduce the CO2 concentration from 9% in the produced gas to below 2.5% for domestic gas supplies. In 2014, it is expected that the carbon capture facilities at Sleipner T will separate an additional 100,000–200,000 te pa of CO2 from the gas produced from the Gudrun field, currently under development.

The first major CCS project in the Middle East was the In Salah project in Algeria [29]. This also removes CO2 from produced gas (⇠10% CO2 ) since it cannot be put into the commercial pipelines.

The project started in 2004 and stores 1 Mte CO2 pa by injection into a deep (2 km) saline aquifer in the Krechba formation. An interesting more recent development is the Lacq project in France. Started in 2010, this project aims to test a fully integrated industrial CCS process by capturing 120,000 te CO2 over a two year period using an oxyfuel combustion unit on the steam generation plant of the Lacq industrial complex. The CO2 is transported via a 27 km pipeline for injection into the Rousse natural gas reservoir at a depth of 4500 m. A summary of current and planned CCS projects worldwide is given in Fig. 14.

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Figure 14. Current Carbon Capture and Storage Projects, planned or underway ( http://www.co2crc.com.au/demo/worldprojects.html).

CARBON CAPTURE TECHNOLOGIES Solvent processes The most common approach for capturing CO2 from waste gas streams is to absorb the gas in a suitably selective solvent and then regenerate the CO2 for storage, usually by heating the solvent. For post-combustion capture, where the concentration of CO2 in the flue gas is relatively low (15–20%), the preferred option is to exploit the acidic nature of CO2 by using reactive absorption in alkaline solvents, the most common of which are amines. Such a process has been widely used for CO2 scrubbing in chemical processes for many years, so has been a readily transferable technology to CCS applications. This process is illustrated in Fig. 15.

Figure 15. Post-combustion capture of CO2 from power plant flue gas by the amine scrubbing process (http://www.vattenfall.com/www/co2_en/co2_en/index.jsp).

The most common amine solvent used is monoethanolamine, MEA [30]. The CO2 -rich flue gas is exposed to an aqueous MEA solution (15–30 wt%) in a scrubbing column, typically at about 55 C and a pressure of 1 bar. The loading of CO2 at the exit from the column is ⇠0.4 mol CO2 /mol MEA. The CO2 is then removed from the MEA in a stripper column by boiling at a pressure of ⇠2 bar and a temperature of ⇠120 C). The energy required for this stripping stage (typically 4 GJ

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te 1 CO2 captured) is a significant part of the overall capture cost [31]. It results in a so-called ‘efficiency penalty’ when the process is fitted to a power station as some of the generated steam must be diverted to the stripping unit rather than used in the steam turbine for electricity generation. This efficiency penalty is typically 10% for post-combustion processes [32].

Capital and operating costs account for 45% of the process costs whereas over 50% is covered by the energy consumption of the process. This energy cost is split almost equally between the energy input to the stripper reboiler in recovering the captured CO2 and that used to compress the CO2 to liquid/supercritical conditions for transport and storage.

The key parameters controlling the efficiency, and hence the cost, of solvent capture processes are therefore - The rate of reactive adsorption - The solvent loading capacity - The energy of regeneration.

There is considerable activity in designing improved amine-related and other alternative solvents for CO2 capture [33]. Hindered (secondary or tertiary) amines show some promise in approaching a capacity of 1 mol CO2 per mol amine and a larger cyclic capacity (significantly lower loadings under stripper conditions) than MEA, combined with smaller values of regeneration energy. Specifically the secondary amine 2-Amino-2-Methyl-1-Propanol (AMP) and tertiary amine 2-Dimethylaminoethanol (DMMEA) have been investigated as possible MEA replacements [34]. However, the rate of CO2 absorption for hindered amines is usually lower than for MEA; activators like piperazine accelerate absorption and amine/activator blends look promising. Major reductions in the regeneration energy are a challenge; the value for ammonia, 55 kJ mol 1 , is about 60% that for MEA and a chilled ammonia process has been proposed as a viable alternative to current systems [35,36].

Degradation with continued recycling and corrosion of vessels and pipework [37,38] are other significant issues which influence choice of amine-related solvents; the optimisation of the solvent molecular structure and the process conditions is a complex multi-parameter problem.

For pre-combustion processes, where the waste gas stream is already at elevated pressure (2–7 MPa) and the CO2 concentration is significantly higher (15–60% by volume) [39], or for produced gas streams containing significant CO2 concentrations, physical rather than reactive solvents can be used (e.g. methanol or n-alkanes) [40]. These have the advantage of binding the CO2 much more weakly resulting in significantly lower regeneration energies and hence efficiency penalties. They also degrade less and are less corrosive. Overall therefore the costs associated solvent capture for post-combustion processes are lower [33].

A relatively new class of solvents, which is emerging as a candidate for selective CO2 capture is ionic liquids [41]. These materials, composed of combinations of large cations and anions (see Fig. 16), have a very wide liquid range with particularly high boiling points and can be designed to be both selective to CO2 or other GHGs and to tune the absorption/desorption energetics. They are relatively expensive but have the potential for combining high loadings with high regeneration yields and efficient recycle with very low solvent make-up. These systems are still in the research phase but seem to have high future potential [38].

Solid adsorption processes Adsorbing CO2 on high surface area solids is the other major class of capture processes under active consideration for carbon capture, or indeed in some cases for permanent storage. As with solvent processes, the adsorption can be physical or reactive. The process closest to commercial deployment as a viable rival to amine scrubbing is Calcium Carbonate Looping [42] (see Fig. 17). Here finely divided calcium carbonate, in the form of limestone or other mineral forms, is calcined at about 650 C to lime, calclum oxide CaO. This is passed to a carbonator vessel where it is contacted at 900–950 C with the flue gas or other CO2 -containing stream and converted exothermically back to CaCO3 . This product is returned to the calciner where CO2 is released and sent for compression, transport and storage with the lime is recycled back to the carbonator for another CO2 capture stage.

The looping of the mineral adsorbent in the capture-release cycle can continue for a large number (10–30) cycles. Adsorption carrying capacity does fall with successive cycles due to reductions in the particle microporosity [42] but regeneration is possible (e.g. using steam) which enables further recycling of ‘spent’ adsorbent [43,44].

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(a)

(c) N

R

N

R' N R

(b) N

O F3C

N

(e)

-

O

S

(d)

P(R)4 R'

R

(f )

N(R)4

S

O CF3

F3C

S

O

(g)

O O

(h)

O

–PF

6

(i)

–BF

4

Figure 16. Ionic Liquids – typical anions and cations (N. Mac Dowell, N. Florin, A. Buchard, J. Hallet, A. Galindo, G. Jackson, C. Adjiman, C. Williams, N. Shah, P. Fennell. An overview of CO2 capture technologies. Energy and Environ. Sci., 2010, 3, 1645–1669).

Figure 17. Simplified process flow diagram of Calcium Looping applied to post combustion capture, after e.g. J. Blamey, EJ. Anthony, J.Wang and P.S. Fennell, Prog. Energy Comb. Sci., 2010, 36, 260–279.

Although the endothermic calcination stage requires significant energy, this is partially offset by the recovery of heat from the hot CaO and CO2 streams, and heat produced from the exothermic carbonation reaction ( 179 kJ mol 1 ), all of which can used to generate additional steam. Hence the efficiency penalty associated with CO2 capture from a power station using carbonate looping turns out to be extremely competitive (⇠3–4% for the capture stage and 3% for subsequent compression) [45]. It has a number of potential advantages: it uses a sorbent derived from cheap and abundant natural limestone; it has a relatively low efficiency penalty; it uses mature large-scale equipment, such as circulating fluidised beds (CFBs), which reduces the scale-up risk; the technology has been demonstrated on medium scale plant; it has particular synergy with cement manufacture where CaO can be used first as a sorbent and subsequently as a key raw material for cement clinker.

There are still key issues to be resolved, mainly the sorbent deactivation (not only due to sintering and porosity loss but also due to sulphate formation in the presence of sulphur-based gases such as SO2 [45]) and particle attrition with the continued looping of the sorbent. However, this process could reduce the thermal efficiency de-rating associated with CO2 capture to about 6–8% compared to 8–10% for MEA-scrubbing, representing a significant fuel and cost saving over the lifetime of a typical power station [46].

A range of other CO2 adsorbents have been studied as the basis for alternative solid adsorption capture processes. These include reactive systems such as amine-impregnated solid sorbents [47,48], and physisorption systems such as structured porous solids (molecular cages) including zeolites, molecular-organic frameworks (MOFs) [49] and gas hydrates [50,51].

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Other capture processes An approach that combines some features of calcium carbonate looping and oxy-combustion processes is â&#x20AC;&#x2DC;chemical loopingâ&#x20AC;&#x2122; [52]. Here, direct contact between air and the fossil fuel is eliminated by using a metal oxide (e.g. iron, copper, nickel, cobalt) as an oxygen carrier. Like carbonate looping, the process involves cycling of material between two fluidised bedsâ&#x20AC;&#x201D;see Fig. 18. In one (the regenerator), the metal is oxidized using air and/or steam in an exothermic process that can be used to raise steam; the oxide is fed to the other reactor (the reformer) where it is reduced back to the metal by reaction with the fossil fuel, producing CO2 and steam, which is readily separated by condensation to yield a pure CO2 stream for compression and storage.

Figure 18. Simplified process flow diagram of Chemical Looping Combustion (Metal, Me = e.g. iron, copper, nickel, cobalt).

Unfortunately, the oxygen carriers tend to degrade during long-term cycling, a limitation that must be overcome to achieve overall efficiencies of greater than 50% [53]. Chemical looping-combustion has been investigated using gaseous and solid fuels, as well as advanced H2 production processes [54,55]. The major challenges are in optimisation of the oxide(s) used, balancing raw material availability and cost, the energetics of the redox process and the long-term degradation rate of the oxygen carrier.

A particularly promising technology is membrane separation and capture (see Fig. 19), which involves the selective permeation of gases through porous materials, driven by a pressure difference that is achieved by either compressing the gas upstream, or creating a vacuum downstream.

Figure 19. CO2 Capture using Gas Membrane Separation of flue gas stream.

Because they exploit pressure gradients, membranes have high potential for achieving CO2 capture from high pressure process streams without significant depressurisation, hence reducing greatly subsequent compression costs, one of the key economic factors in the overall CCS chain. Three main types of membrane can be deployed, polymeric, metallic or ceramic; the choice is strongly dependent

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on the temperature and gases involved in the particular application. In the case of CO2 separation from flue gas, a critical issue is to increase membrane permeability in order to reduce the efficiency penalty associated with achieving the pressure gradient across the membrane [56]. Major challenges which must be overcome to make this technology robust include: the cost of membrane materials, membrane lifetimes and reliability issues due to exposure to particulates, SOx , NOx and trace metals, demonstration of large-scale equipment and efficient integration with power systems.

Other CO2 capture technologies that are being investigated for possible commercial deployment are: - Biological capture: These processes involve using the waste heat and CO2 waste gas from combustion, together with water and sunlight, to grow microorganisms such as algae or cyanobacteria. The use of highly productive genetically engineered algal strains is expected to enhance greatly the capture capacities and rates for these systems [57,58]. Another biological capture option being pursued involves enzymes. One such process uses carbonic anhydrase to capture and release CO2 in a similar way to the mammalian respiratory system [59,60].

Biological capture processes suffer from inherent scale-up issues because of the limited rate at which algae can grow, and challenges associated with bioreactor design.

- Cryogenic separation: This is an alternative approach for gas–gas separation exploiting the different boiling temperatures and partial pressures of the gases in a mixture, to separate them into distinct phases by cooling or pressurization [61]. For CO2 separation/capture, CO2 can be frozen at 75 C and atmospheric pressure, or condensed to a supercritical fluid when pressurised beyond its critical point at 31 C and 74 bar. The major problem for cryogenic separation is the high-energy consumption and cost associated with compression and cooling.

Another challenge is the removal of water which is necessary before cooling to avoid the formation of ice [62].

- Building CO2 into materials [63,64]: Although CO2 contains carbon in its highest oxidation state (+4) and is hence the lowest energy carbon-containing neutral binary molecule, carbonates, formed by reaction with hydroxyl ions from water, are even lower in energy than CO2 . The natural weathering of silicates is also an exothermic process, albeit extremely slow.

With some rocks of volcanic origin (e.g. basalts [65]) reaction with CO2 is much quicker (days–months). Such mineralisation processes represent the longer-term processes for retaining CO2 in storage reservoirs, taking over from the shorter-term trapping mechanisms of capillary trapping and dissolution in the reservoir fluids.

On the other hand, the reduction of CO2 to lower oxidation states requires significant energy. This can be achieved via electrochemical or photoelectrochemical reduction [66] (assuming the availability of suitable amounts of renewable electricity) or by using highly reactive organic or organometallic compounds [67]. The potential for expanding commercial processes for using CO2 as a feedstock is in producing three main classes of products: fine chemicals, including urea, carboxylic acids, and carbonates; fuels or commodity chemicals such as methanol and formic acid; and plastics such as polycarbonates and polyurethanes [68,69]. The main challenges to this ‘re-use’ of CO2 are the significant energy requirements, which challenge its sustainability if non-renewable, CO2 -generating sources are used, and the possible limitations of the markets for such CO2 -based materials. Currently only about 150 Mte CO2 is used each year as a chemical feedstock compared with the 2050 target of removing 10Gte pa CO2 via CCS or other capture-based processes.

THE FUTURE CHALLENGES FOR CO2 CAPTURE It can be seen that several CO2 capture technologies are in commercial or semi-commercial use and are being deployed in demonstration projects across the world. However, this stage represents by far the most expensive part of the overall CCS chain so much R&D is being carried out to produce more efficient, lower-cost and more environmentally acceptable solutions. A summary of the major challenges to be addressed are: - Lower capital and operating costs of the capture process - Processes that operate at higher pressures where can take place to contribute to lowering compression costs

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- Sorbents capable of high CO2 loadings with low regeneration energies - Smaller and more efficient gas–liquid contacters - Low cost air separation (for oxyfuel) - Exploit membranes fully for selective, low-energy separation and capture.

Addressing these and other challenges will hopefully bring down significantly the costs of carbon capture, and CCS overall, over the next decade or so. Processes will become more complex but also more efficient. A possible roadmap or technology adoption trajectory, based on the current state of maturity of the various candidate approaches and the anticipated time to reach commercial readiness, is shown in Fig. 20 [23,36].

Figure 20. Likely carbon capture technology adoption trajectory after Figueroa et al. (Int. J. Greenhouse Gas Control, 2008, 2, 9–20.).

Finally, we can ask the question ‘what lies beyond CCS?’. In the long-term, maybe not until the end of the 21st century, we will hopefully have developed cost-effective renewable energy supplies, particularly those based on solar, to the extent that there will no longer be any need to use fossil fuels for heat and power, and our liquid fuels, chemicals and materials requirements will all be met using renewable biofeedstocks. However, the transition to this state will take many decades and CCS as we now envisage it may only be a short-term measure. Rather than using a lot of energy to bring fossil fuels to the surface, where we use more energy to process and convert them to fuels, power, heat, chemicals and materials, one possible scenario would be to utilise - the in situ high temperature/pressure/chemical energy of oil, gas and coal - the many kilometres of interconnected underground wells, currently used only as production conduits to carry out much of this processing and conversion in situ, underground.

The energy could be supplied by supplementing the in situ temperatures and pressures by in situ combustion of some of the fossil fuel to both mobilise hydrocarbons and carry out in situ gasification, partial oxidation, reforming and even catalytic cracking, accompanied by in situ membrane separation and capture of CO2 and other GHGs and toxic products [70,71]. We would deliver to the surface, or at the surface, the high value products that we need: power, heat, ‘clean’ fuels (H2 , methanol, DME...), syngas feedstock for chemicals and materials production. The CO2 and other waste or low value materials (asphaltenes, tars) would remain buried in the sub-surface, surplus to requirements.

Such a scenario is depicted in Fig. 21, where the only footprint on the surface is a fuel retail station and a subsurface control centre, linked by satellite communication to reservoir and refinery engineering experts running and monitoring the underground refinery from their technical bases across the globe [72].

Fantasy or tomorrow’s reality? Such a paradigm shift in the way that we produce and process fossil fuels would take many decades to develop and introduce. Yet the ‘clean fossil fuels’ era, with

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Figure 21. The shape of things to come for carbon capture and storage? Subsurface processing refining with in situ CO2 capture for integrated production of clean energy, fuels and chemical feedstocks [72].

increasingly lower CO2 emissions, bridging today’s high GHG emissions energy mix to the long-term renewables era, will last more than five decades. So there is plenty of time to develop and refine these approaches to optimising our utilisation of the energy and materials content of fossil fuels and reducing the environmental footprint of their exploitation more and more.

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OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Carbon capture and storage: An industry viewpoint Marcus Schwander Qatar Shell Service Companies

INTRODUCTION Economic growth in developing nations – driven not least by fast growing populations – is leading to a surge in demand for energy, with rapid increases in both renewable energy deployment and fossil fuel production. Since 2000, the world has added 0.3 billion tonnes oil equivalent per annum of renewable energy, but nearly eight times this amount from fossil production.1 Current trends are that increasing renewable energy system deployment is not backing out other fuels; rather, it is supplementing a constrained fuel pool, allowing for faster economic growth. This approach will not deliver the necessary global greenhouse gas (GHG) reduction goals by 2050. Thus, there is an enormous challenge for global efforts to halve CO2 emissions by 2050 in order to avoid the worst effects of climate change.

Supply from lower-CO2 energy sources, such as renewables and nuclear, will grow and represent more of the energy mix in future, however it is estimated that fossil fuels could still meet at least 65% of world energy demand in 2050. Moreover, even with strong government support, it takes time for newer energy technologies to become affordable and available at scale. Therefore, large scale CO2 mitigation technologies for fossil fuels are necessary, which underpins the importance of carbon capture and storage (CCS); many countries will therefore need to adopt CCS, post-2020, to meet GHG reduction goals consistent with the ‘‘2 C target’’ are to be met. The IEA Energy Technology Pathway has found that CCS could deliver 19% of the total emission reductions required to meet the 2 C target, and would require just 6% of the overall investment needed to achieve a 50% reduction in GHG emissions in 2050. It has been estimated that, without CCS, the overall costs to halve global emissions by 2050 could rise by 70%.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.10 Published: 19 December 2012 c 2012 Schwander, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

CARBON CAPTURE AND STORAGE CCS is not one single novel technology but rather represents a combination of largely existing and proven technologies to first separate or capture CO2 from different sources, the to compress and transport it, and finally to inject it deep underground and monitor its movement. All of these technologies have individually been deployed safely for many years – much experience on compression, transport, injection and recirculation of large quantities of CO2 has been gained from the Enhanced Oil Recovery (EOR) industry in West Texas, which has been operating for decades – but the combination of the technologies in a single project for the sole purpose of storing CO2 underground permanently, needs to be demonstrated at a larger commercial scale.

Today, eight large-scale integrated capture-to-storage projects (LSIPs) are in operation2 sequestering some 8 mtpa. Most of these projects are associated with the oil & gas industry, either through using CO2 -rich gas fields as source or through using CO2 -EOR as a sink. Six of the eight operating projects are in natural gas processing, while the other two are in synthetic fuel production 1 Source: IEA.

2 Source: Global CCS Institute.

Cite this article as: Schwander M. Carbon capture and storage: An industry viewpoint, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:10 http://dx.doi.org/10.5339/stsp.2012.ccs.10

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and fertiliser production, and five of the projects involve EOR. In addition there are six large-scale integrated projects under construction, including the first project in the United States that will store CO2 in a deep saline formation (the Illinois Industrial Carbon Capture and Sequestration (ICCS) project), Shell’s Quest3 project in Canada, which will be the first application of CCS to oil sands upgraders, and the Gorgon project (Shell interest 25%), a liquefied natural gas (LNG) venture off Western Australia that will include the largest CCS project in the world. The total CO2 storage capacity of all 14 projects in operation or under construction is over 33 million tonnes a year, broadly equivalent to preventing the emissions from more than six million cars from entering the atmosphere each year.

Whilst progress continues to be made to push CCS forward, it is patchy and slow. With the exception of the Gorgon project there are no other purely CCS projects that will start operations before 2015. Moreover, all the other 74 globally-recorded LSIPs projects estimate a total injection rate of 120 million tones of CO2 sequestered annually by 2020—far from the needed 300 million tons by 2020 to achieve 50% reduction by 2050. Of these 74 projects 10 may decide within the next 12 months whether to take a final investment decision and move into construction.4 Around ten large-scale projects have been put on hold or cancelled over the past year. The most frequently cited reason for a project being put on hold or cancelled is that the project was deemed uneconomic in its current form and the general policy environment.

ACTIVITY A large number of universities and national or international GHG management and CCS consortia from around the world are active in the development, testing and demonstration of individual CCS technologies. Current CCS fundamental research and developments concentrate on understanding the impact of impurities in CO2 streams and the CO2 behaviour underground, to improve or develop new systems for monitoring, measurement and verification of stored CO2 and to develop second and third generation capture technologies.

A critical CCS activity is the selection of suitable storage site to ensure responsible and safe operations of CCS projects and the secure long-term containment of injected CO2 in the subsurface.

Best-practices oil and gas industry techniques including established risk and uncertainty management are being deployed to characterize, assess and ultimately develop a storage complex that can contain securely the CO2 from impacting groundwater and mineral resources. To this end the Qatar Carbonate & Carbon Storage Research Collaboration launched in 2008 by Qatar Petroleum, Qatar Shell, Qatar Science & Technology Park and Imperial College London is developing the underlying science and know-how to support secure and cost-effective large-scale CCS in the Middle Eastern carbonate system.

It goes beyond the purpose of this document to describe in detail each capture technology; grouped into post-combustion capture,5 pre-combustion capture6 and oxyfiring.7 Many capture technologies and many engineering solutions are currently available, but there are no silver bullets; it is hard engineering work and new developments have to be tested at industrial scales. Shell pioneered gas and liquid treating and holds the leading position in the number of licenses for acid gas capture processes. Its portfolio of technologies covers deep and selective removal of gas contaminants, such as carbon dioxide, mercaptans and hydrogen sulphide for natural gas, and refining and industrial process gases. Since the 1950s, Shell has built or licensed around 1,200 acid gas treatment plants throughout the global oil and gas industry. Fig. 1 shows the range of technologies Shell is using for these various applications. Selecting the most suitable process for CO2 removal is, to a great extent, determined by the nature of the CO2 source, the utilities available, and injection conditions of the CO2 .

3 Quest project would potentially capture 1 million tonnes of CO per year from the Scotford Upgrader, where bitumen 2 produced by Shell’s Athabasca Oil Sands Project is processed into synthetic crude oil.

4 Most of these LSIP’s are associated with the power industry in North America, Europe, and Australia where regulations are emerging and government funding for a set of demonstration projects has been offered. Some are developed in China and only few large-scale projects are planned in developing countries.

5 End of pipe flue gas scrubbing usually through a CO selective separation process like amines or other chemical 2 solvents.

6 Fuel streams are being ‘‘de-carbonized’’ upstream of the combustion step at high partial pressure i.e. in Hydrogen Manufacturing Units (HMU) or IGCC’s. Today’s technology does this through physical absorption in solvents but in the future membrane, adsorbent or cryogenic technology may occur to be more cost effective.

7 Through combustion with pure oxygen in oxy firing, pure CO is produced in the combustion facility which, often after 2 additional treating is compressed and stored.

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CO2 separation and capture

Absorption

Chemical

Physical

Adsorption Cryogenics

Hybrid

Membranes

Polymer

Microbial

Process Integration

Inorganic

Figure 1. CO2 Separation and Capture technologies used by Shell.

In general, industry is maturing next-generation CO2 capture technologies to reduce costs and increase efficiencies to allow scale up to commercial levels, thus making the technology environmentally acceptable. To this end, improved and novel systems solutions are being investigated with utility integration and utility-led designs and full-integrated capture, transport and storage optimization of line-ups. On the process side, emphasis is on energy optimization and integration, smart line-ups, minimizing process footprint (solvent losses, waste, toxicity), high-pressure separation and regeneration concepts. Smart equipment and materials are in development concentrating on high efficiency contactors, heat exchangers and rotating equipment and low-cost construction materials with low levels of required maintenance and high levels of reliability. Innovative breakthroughs on adsorbents, solvents, membranes and hybrid solutions are expected to optimize CO2 separation.

In the power sector, a major emphasis is on research to reduce costs for the CCS energy penalty or ‘parasitic load’ (i.e. indirect emissions related to the energy consumption of the capture process) that is involved in applying the capture technologies.8 Solutions for reduction of parasitic CO2 emissions are investigated through energy efficient solvents technology, heat integration and use of low CO2 -intense energy sources (i.e. waste heat, renewable energy). Although CCS costs, in particular involving flue gas capture systems, are currently high, around 50% cost reduction appears feasible when deploying next-generation capture systems. Through the R&D effort and the early demonstration projects, efficiency in design and operation will reduce costs over the coming years, as with all new technologies.

Current status to climb the pyramid to commercial readiness through the reduction of energy use, costs, HSE exposure to an acceptable level the following status appears to be: At the exploratory stage there are materials such as metal-organic framework’s (MOF’s), ionic liquids, liquid crystals, supported amines and innovative methods such as cryogenic separation and electrochemical separation.

At the proof of concept stage are the biphasic solvents and non-aqueous solvent, membrane absorption and polymeric membranes.

At the pilot-scale testing stage are the blended alkanol amines, amino acid salts and absorbent carbonate slurries.

Shell Shell is active in researching and developing next generation of CO2 capture systems from a variety of sources, including sources that are generally: 1. High pressure and medium-to-high CO2 concentration in nature, such as gas processing facilities for natural, high CO2 -content reservoirs, hydrocarbon-gas-feeding gas treatment plants, such as liquefied natural gas (LNG), gas to liquids (GTL) or domestic gas plants and HMU and gasification product streams. Higher partial pressure of CO2 usually leading to easier and cheaper CO2 removal.

8 With today’s technology the parasitic CO emissions are in the order of 25–30% of the amount of CO that is 2 2 captured.

Page 4 of 4 Schwander, Sustainable Technologies, Systems and Policies 2012.CCS.10

2. Low pressure and medium-to-low concentration in nature, such as industrial combustion flue gas from furnaces or gas turbines. Lower partial pressure of CO2 usually leading to difficult and more expensive CO2 removal.

Through our subsidiary Cansolv Technologies, Shell is involved in the 2012 piloting of its 2nd generation post-combustion capture system for deployment in large scale integrated CCS projects such as the ‘‘Boundary Dam’’ in Canada, for which the final investment decision was taken in May 2011 with the government of Saskatchewan as co-funder. In a separate Shell paper reported in this volume, the breakthrough solvent technologies of Cansolv for low-cost, post-combustion capture and related industry-scale demos will be discussed in detail. In addition, Shell is involved in the development of 3rd generation post-combustion, potassium carbonate-based system (precipitating carbonate slurry) offering cost reduction, lower nitrosamines emissions and energy efficiency breakthroughs.

In Norway, Shell is involved with partners in the Technology Centre Mongstad,9 the largest demonstration facility to develop and test CO2 capture technology, with the ambition of reducing costs and the technical, environmental and financial risks related to large-scale CO2 capture. Existing (Aker’s amine-based capture system) and new technologies (chilled ammonia) are being deployed.

One of the key investigations is related to emissions of amines from absorbers in post-combustion capture, an environmental concern. After release of emissions of amines into the environment, the subsequent photo-oxidative degradation mechanisms – with its environmental impact and toxicity aspects – need to be fully understood before safe deployment of amine processes can be carried out.

These phenomena are partially generic, but also partially specific for individual amines, which implies that studies into the degradation of amines and health aspects, as well as the development of mitigation steps, are an integral part of the technology development.

A comprehensive and rapid response to the climate change challenge is required. Shell believes that increased use of natural gas for electricity generation and CCS are two fast, low-cost measures that are critical for tackling the global challenge. Natural gas, is recognized as a rapidly deployable, near term CO2 mitigation opportunity to displace coal and natural gas plants can be fitted with CCS to reduce emissions by around 90% over the longer term. CCS has huge potential but needs demonstration projects to be in place quickly in order to realise its full potential in mitigating CO2 emissions. The first wave of demonstration projects need to get up and running to drive down the cost of CCS and to ensure that the lessons learned from this initial wave of demonstration projects will drive the industry up the learning curve for the larger wave of commercial scale investment grade plants needed from 2030 onwards.

CCS can be efficiently incentivised through a carbon price, but this is only emerging on a fragmented basis. However, even national implementation, which results in local rather than global CCS deployment, can still be considered of global benefit because emissions are captured and stored. Given that CCS exists primarily as a CO2 mitigation solution, government policies to encourage and support progress are vital. This requires that many enablers are put in place, such as clarity on liabilities, the building of public confidence and support, stable regulations and a proven technology and value chain. Clear incentives, linked to policy goals, that give the necessary price signals to the value of emissions avoided are important, as these will support the action to drive investment into CCS projects. Without government support, a global CCS effort will not appear. The inescapable truth is that CCS will be needed. According to the IEA, we need to see 100 CCS projects by 2020, half in the OECD and the remainder in the developing world.

Shell and its partners are well placed to contribute to the development of CCS and we will continue to focus on this highly promising technology over the coming years.

9 Partners: Gassnova SF (Norwegian State), Statoil, A/S Norske Shell and Sasol. Statoil is building the facilities.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Life Cycle Assessment of the natural gas supply chain and power generation options with CO2 capture and storage: Assessment of Qatar natural gas production, LNG transport and power generation in the UK Anna Korre*, Zhenggang Nie, Sevket Durucan MERG, Department of Earth Science and Engineering, Royal School of Mines, Imperial College London, SW7 2BP, UK * Email:

a.korre@imperial.ac.uk

http://dx.doi.org/ 10.5339/stsp.2012.ccs.11 Published: 20 December 2012 c 2012 Korre, Nie, & Durucan, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

ABSTRACT Fossil fuel-based power generation technologies with and without CO2 capture offer a number of alternatives, which involve different fuel production and supply, power generation and capture routes with varied energy consumption rates and subsequent environmental impacts. The holistic perspective offered by Life Cycle Assessment (LCA) can help decision makers to quantify the trade-offs inherent in any change to the fuel supply and power production systems and ensure that a reduction in greenhouse gas (GHG) emissions does not result in increases in other environmental impacts. Beside energy and non-energy related GHG releases, LCA also tracks various other environmental emissions, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of resources, such as water, minerals and land use. In this respect, the dynamic LCA model developed at Imperial College incorporates fossil fuel production, transportation, power generation, CO2 capture, CO2 conditioning, pipeline transportation and CO2 injection and storage, and quantifies the environmental impacts at the highest level of detail, allowing for the assessment of technical and geographical differences between the alternative technologies considered. The life cycle inventory (LCI) databases that were developed, model the inputs and outputs of the processes at component or unit process level, rather than ‘‘gate-to-gate’’ level, and therefore generate reliable LCI data in a consistent and transparent manner, with a clearly arranged and flexible structure for long-term strategic energy system planning and decision-making.

The presentation discussed the principles of the LCA models developed and the newly extended models for the natural gas-fired power generation, with alternative CO2 capture systems. Additionally, the natural gas supply chain LCA models, including offshore platform gas production, gas pipeline transportation, gas processing, liquefied natural gas (LNG) processes, LNG shipping and LNG receiving terminal developed are used to estimate the life cycle GHG emissions for an idealised case study of natural gas production in Qatar, LNG transportation to a UK natural gas terminal and use in a power plant. The scenario considers a conventional and three alternative CO2 capture systems, transport and injection of the CO2 offshore in the Irish Sea. Cite this article as: Korre A, Nie Z, Durucan S. Life Cycle Assessment of the natural gas supply chain and power generation options with CO2 capture and storage: Assessment of Qatar natural gas production, LNG transport and power generation in the UK, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:11 http://dx.doi.org/10.5339/stsp.2012.ccs.11

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INTRODUCTION According to the recent World Energy Outlook report, the world energy demand will grow by 35% by 2035, assuming that recent government policy commitments will be implemented in a cautious manner [1]. Although the share of fossil fuels in the global primary energy consumption is expected to fall slightly, from 81% in 2010 to 75% in 2035, natural gas is the only fossil fuel to increase its share in the global mix in the period up to 2035 [1]. Arguably, the growth of energy demand has the potential to cause a significant increase in greenhouse gas (GHG) emissions associated with climate change. It is widely accepted that, in terms of energy, the coming decades will be challenging for all nations in terms of developing energy-efficient, low carbon, energy-secure and competitive economy.

Especially, the electricity industry in the industrialised world holds an important and pro-active role in providing solutions to both secure economic growth and prosperity, and to reduce greenhouse gas emissions in economically feasible ways [2]. Together, with the development of renewables and nuclear energy, clean fossil fuel technology with carbon capture and storage is an essential part of future energy portfolios in order to make a low-carbon power generation mix a reality [1,2].

The power generation technologies available today, and under development, introduce new processes which may release GHG emissions or other environmental burdens. These may either be directly, from the operations, or indirectly, through the upstream processes required in their implementation. For example, carbon dioxide capture processes can result in both direct and indirect GHG emissions and other environmental impacts [4â&#x20AC;&#x201C;6]. This is also the case for renewable technologies; for example, considerable GHG emissions occur from the consumption of energy in manufacturing monocrystalline silicon for photovoltaic solar cells [3].

In order to make credible comparisons between alternative power generation options, it is imperative to conduct a comprehensive environmental assessment of the processes involved in power generation, tracking GHG releases throughout all stages of power generation life cycle (or value chain). It is then possible to provide accurate information for decision makers and ensure that a new power generation technology option would not result in upstream or downstream changes that will increase the overall release of GHGs. It is also important to ensure that the power generation systems considered do not aggravate other environmental concerns, such as solid and hazardous waste generation and the release of toxic substances which impact upon human health and ecological systems. This requires a holistic and system-wide environmental assessment.

Life cycle assessment (LCA) meets this criteria as it not only tracks energy and non-energy related GHG releases but also tracks various other environmental releases (e.g. solid wastes, toxic substances and common air pollutants) as well as the consumption of other resources (e.g. water, minerals and land use). This holistic perspective offered by LCA helps decision makers to quantify the trade-offs inherent in any change to the power production systems and helps to ensure that a reduction in GHG emissions does not result in increases in other environmental impacts. The other strength of LCA is that the International Organization for Standardization (ISO) has developed the ISO 14040 series of LCA standards, which provide guidance on setting appropriate system boundaries, reliable data collection, evaluating environmental impacts, interpreting results, and reporting in a transparent manner. This offers an excellent starting point for the development of measurement protocols for GHGs and other environmental impacts [7]. Considering the three flexible mechanisms developed to help emitters in developed countries to meet their GHG emission targets (Emissions Trading, Joint Implementation and the Clean Development Mechanism), LCA offers the means to include new power generation projects into the CDM framework and help the participants of flexible mechanisms to assess their proposed projects and verify their emission reductions from a value chain perspective using a credible and internationally accepted tool.

The life cycle performance of various power generation plant configurations without/with alternative CO2 capture systems, transport and injection scenarios have been investigated by previous LCA studies [8â&#x20AC;&#x201C;16]. However, since these studies are based on a low resolution analysis (plant level analysis or gate-to-gate data from generic databases), these studies report wide ranging results for climate change impacts and other impact categories such as abiotic resource depletion, acidification, human toxicity, etc. which cannot be adequately characterised in coarse resolution LCA studies. The use of gate-to-gate data implies that the electricity generation systems have been largely simplified to a single black box with constants and linear coefficients used to assign inputs and outputs, covering a broad range of technological and geographical differences, in which the actual variability of process parameters and operating conditions are implicitly neglected. In addition, plant

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level analysis limits the capacity of such studies to quantify the trade-offs inherent in any change to the power production systems and restrict the ability to identify design options that eliminate highly polluting emissions.

In this respect, the dynamic LCA model developed at Imperial College incorporates fossil fuel production, transportation, power generation, CO2 capture, CO2 conditioning, pipeline transportation and CO2 injection and storage, and quantifies the environmental impacts at the highest level of detail. This allows for the assessment of technical and geographical differences between the alternative power generation, CO2 capture, transport and storage technologies considered. Earlier publications by the authors [4,6] present the post-combustion life cycle model developed and a comparative assessment between the post-combustion and oxy-fuel capture options modelled for coal fired plants. This paper presents the principles of the LCA models developed and the newly extended models for the natural gas-fired power generation with alternative CO2 capture system.

Additionally, the natural gas supply chain LCA models, including offshore platform gas production, gas pipeline transportation, gas processing, liquefied natural gas (LNG) processes, LNG shipping and LNG receiving terminal developed are used to estimate the life cycle GHG emissions for an idealised case study of natural gas production in Qatar, LNG transportation to a UK natural gas terminal and use in a power plant. The scenario considers a conventional and three alternative CO2 capture systems, transport and injection of the CO2 off-shore in the Irish Sea. LIFE CYCLE ASSESSMENT METHODOLOGY AND ITS APPLICATION IN POWER GENERATION WITH CO2 CAPTURE AND STORAGE Life Cycle Assessment methodology Life Cycle Assessment is a compilation and evaluation of the inputs and outputs and the potential environmental impacts of a product system throughout its entire life cycle, ranging from raw material extraction and acquisition, through energy and material production and manufacturing, to use and end of life treatment and final disposal [17]. In order to deal with the complexity of LCA, the International Standards Organisation (ISO) established a methodological framework for performing LCA studies, which comprises four phases, including the goal and scope definition, Life Cycle Inventory Analysis (LCI), Life Cycle Impact Assessment (LCIA) and Interpretation, as shown in Fig. 1.

Life Cycle Assessment and framework (ISO 14040) Goal and scope definition

Direct Applications: Inventory analysis

Interpretation

Development and improvement Strategic planning etc.

Impact assessment

Figure 1. Methodological framework of LCA: phases of an LCA (After: [17]).

The goal and scope definition states the aim of an intended LCA study, the system boundary, the functional unit, competing systems considered, and the breadth and depth of (or level of detail) the LCA study in relation to this aim. Life Cycle Inventory Analysis is the phase where input/output relationships are quantified and an inventory of input/output data for all component processes involved in the life cycle of the system(s) under study is prepared. The input/output flows for a unit process to be quantified include economic and environmental flows as shown in Fig. 2.

The objective of Life Cycle Impact Assessment is to understand and evaluate the magnitude and significance of the potential environmental impacts of a product system [17]. In this phase, impact

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OUTPUTS

INPUTS

Economic flows

Product

Products Services Materials Energy

Wastes (for treatment)

Environmental interventions

Abiotic resources Biotic resources Land transformation Land occupation

UNIT PROCESS / PRODUCT SYSTEM

Goods Services Product Materials Energy Waste (for treatment)

Chemicals to the air Chemicals to water Chemicals to the soil Radionuclides Sound Waste heat Casualties Etc.

Economic flows

Environmental interventions

Figure 2. Environmental interventions and economic flows (After [18]).

categories (e.g. global warming, acidification, and human toxicity), category indicators, and characterisation factors are defined first. Then the LCI results are assigned to categories and converted into category indicators via characterisation factors. Characterisation factors can convert environmental flows into environmental impacts.

There are two characterisation approaches: midpoint method (e.g. [18]) and endpoint method (e.g. [19]). The midpoint approach stops quantitative modelling at any point before the end of causeâ&#x20AC;&#x201C;effect chain (including fate, exposure, effect and damage) and uses midpoint indicators (such as global warming potential, acidification etc.) to reflect the relative environmental importance of an emission or extraction. The endpoint approach models the causeâ&#x20AC;&#x201C;effect chain up to the final environmental damages, the damages to human health, ecosystems and resources. Interpretation is the phase in which the findings of either the inventory analysis or the impact assessment, or both, are analysed in relation to the defined goal and scope in order to deliver conclusions, explain limitations and provide recommendations [17].

LCA application in power generation with CO2 capture and storage One of the objectives of the dynamic LCA model developed at Imperial College was to build a comprehensive LCI database for the analysis of power generation with alternative CO2 capture and storage options and of fossil fuel supply chain, in a consistent and transparent manner. The underlying principle applied in developing this methodology can be summarised as follows: 1. Transparency: to show precisely how life cycle impacts are calculated and the extent to which the inputs/outputs of any unit process have been quantified.

2. Comprehensiveness: to identify all of the inputs/outputs that may give rise to significant environmental impacts.

3. Consistency of methodology: models and assumptions to allow valid comparisons to be made between technological or operational options for a unit process.

The system boundaries of LCA in power generation with CO2 capture and storage, a generalised outline of which is presented in Fig. 3, covers power generation, alternative CO2 capture options and upstream processes such as extraction and processing of fossil fuels, raw materials production, as well as CO2 compression, transport and storage. The functional unit selected for the analysis was 1 MWh of electricity generated.

In this research, the power generation system has been broken down or modularised into subsystems or component unit processes for the natural gas combined cycle (NGCC) power plant with post-combustion CCS system. The component unit processes are connected through flows of intermediate products or emissions as illustrated in Fig. 4. The purpose of modularisation was to make complex systems more easily understood and more accurately modelled. Through modularisation, the LCI models quantify flows of materials, natural resources, energy, intermediate products or emissions at component or unit process level. This approach ensures that the technical, spatial and temporal differences that exist between different industrial sites and operations can be accounted for by modifying the parameters of the component unit processes as necessary.

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Extraction of fossil fuel

Electricity and by-products

Emissions to air, water and soil

Natural resources

Power Generation with CO2 Capture

Consumables Production

Processing of fossil fuel

Raw Material Production

CO2 Conditioning

Fossil fuel transportation

Consumables transportation

CO2 Transportation

CO2 Storage Upstream processes infrastructure

Power plant and CO2 capture facility infrastructure

CO2 pipeline infrastructure

CO2 injection infrastructure

Figure 3. Generalised outline of the power generation with CCS LCA system and its boundaries.

Emissions in to the Atmosphere (CO2 Depleted Flue Gas):

Exhaust steam

Air, Natural gas (components):

CO2 depleted flue gas

Steam Gas Combustion Turbine

Flue gas

HRSG

Condensate return Water make-up

Water Sodium Hydroxide Sulphuric acid

LP steam

Steam Turbine

Stack

Electricity

Water treatment plant

Soil wastes:

Air cooled condenser

Flue gas

CO2 capture

Energy

CO2 conditioning CO2

HRSG blowdown

Waste water

CO2 pipeline transportation CO2

Storm water basin Effluent

CO2 injection

CO2 CO2 saline aquifer storage

Discharge to surface waters

Potential CO2 Leakage to Air

Figure 4. The level of detail involved in the LCA of NGCC with post-combustion CCS system.

Furthermore, modularisation allows plant operators and designers to model and compare different technical and engineering scenarios from a life cycle perspective. Ultimately, modularisation eliminates the limitations introduced by the linear input/output coefficients used by conventional LCI models.

The following paragraphs demonstrate the LCI model developed for a chemical absorption CO2 capture unit as an example. A typical chemical absorption unit is based on an aqueous CO2 absorption and CO2 stripping system, which is comprised of two sections (Fig. 5). In the absorber, CO2 is chemically absorbed from the inlet gases by contacting it with the countercurrent CO2 -lean solvent, e.g. monoethanolamine (MEA). The treated gas exits the top of the absorber column. The CO2 -rich solvent is passed to the stripper, where, by heating the CO2 -rich solvent solution, the CO2 is stripped off and the CO2 -lean solvent is regenerated. The regenerated CO2 -lean solvent is then recycled back to the absorber and the CO2 is passed to compression processes. The system, especially MEA solvent system, also uses chemicals (such as NaOH) for proposes of solvent

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CO2 depleted Flue Gas

CO 2 H 2O (SO 2) (NOx )

HX

o

T: 50-60 C P: 30-40K Pa

STRIPPER

ABSORBER

Lean solvent

Reboiler o

Filtration

Diluted Flue Gas 3-15% CO2

T: 100-120 C P: 150-175 K Pa

Reclaimer Waste

Rich solvent

Figure 5. A typical chemical absorption CO2 capture unit.

Figure 6. A schematic representation of chemical absorption CO2 capture processes LCI model developed.

reclamation, solid filtration, and a corrosion inhibitor. Sorbent make-up is also required for the compensation of sorbent loss in the absorption/stripping process.

The schematic of the LCI model developed is shown in Fig. 6, which describes the inputs/outputs to be quantified. The inputs/outputs of chemical absorption CO2 capture processes are modelled using engineering calculations. In order to characterise the technological differences of different chemical absorption CO2 capture processes, the LCI model developed accounts for 8 types of solvents. Fig. 7 shows the LCI results of a MEA CO2 capture system applied to a coal-fired power plant with post-combustion configuration.

CASE STUDY: QATAR NATURAL GAS PRODUCTION, LNG TRANSPORT TO THE UK AND USE IN POWER GENERATION The LCA models developed at Imperial College have been applied to an idealised case of natural gas production in Qatar, LNG transport to the UK and use in power generation systems with alternative CO2 capture options and saline aquifer CO2 storage. The whole value chain is illustrated in Fig. 8.

The gas is produced from an offshore platform at the Qatar North Field. The produced gas is transported by undersea pipeline to Ras Laffan, where the gas is processed and is liquefied to LNG. The LNG is shipped to UK South Hook receiving terminal via Suez by advanced Q-Max and Q-Flex LNG ships. The gas received is regasified at South Hook terminal. The regasified gas is transported to power plant by pipeline. Four types of gas power plant configurations have been investigated in the case study. They are conventional natural gas combined cycle (NGCC) plant, NGCC plant with

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Figure 7. LCI results of a MEA CO2 capture system (per 1 MWh electricity generated).

Alternative gas power generation with/without CO2 capture

Qutar North Field offshore natural gas production

Gas processing and LNG plant at Ras Laffan

LNG shipping (Q-Max & Q-Flex): from Qatar to the UK via Suez

CO2 injection into saline aquifer

Receiving terminal at South Hook + onshore gas pipeline to power plant

CO2 pipeline transportation

Figure 8. The value chain of Qatar natural gas production, LNG transport to the UK, power generation.

post-combustion CO2 capture, steam reforming plant with membrane CO2 capture (SMR), and auto-thermal reforming (ATR) plant with pressure swing adsorption (PSA) CO2 capture. The captured CO2 is transported by pipeline to saline aquifer storage site, where CO2 is injected underground.

Tables 1â&#x20AC;&#x201C;4 provide the key parameters or operational parameters of the supply chain, of alternative power plant configurations without or with CO2 capture, CO2 transportation, and of CO2 injection to a saline aquifer. The LCA model developed not only accounts for these key parameters but also the operational parameters at unit processes level. The user can change these parameters in order to apply fully and dynamically the LCA models to a specific case study, allowing for the assessment of operational, technical and geographical differences at unit process level.

With respect to the gas supply chain from the Qatar North Field to South Hook in the UK, the majority of GHG emissions come from natural gas processing, LNG processing, LNG shipping and the LNG receiving terminal as demonstrated in Fig. 9. The GHG emissions from the offshore platform and pipeline transportation are not significant. Fig. 9 also indicates that insignificant GHG emissions are due to the construction and installation of the gas production plants, gas processing plant, LNG plant, LNG receiving terminal and the gas pipelines.

With respect to alternative power plant configurations, Fig. 10 shows that the ATR with CO2 PSA capture has lower plant energy efficiency than SMR with membrane plant and CCGT with MEA

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Table 1. Supply chain parameters/operational parameters.

Qatar North Field Platform

Offshore pipeline: from North Field platform to Ras Laffan Onshore NG processing plant at Ras Laffan Ras Laffan LNG plant LNG shipping

Onshore LNG receiving terminal at South Hook, UK Onshore pipeline: South Hook to Power plant

Natural gas platform production rate Natural gas reservoir life span Platform drilling Number of wells predrilled

1,730 20 3.5 10

MMscf/day years years wells

Distance

80

km

Plant throughput

1,730

MMscf/day

Plant capacity Number of trains CO2 content in NG to be processed Distance Velocity Carrier volume

15.6 2 0.50 11,281 36.12 266,000

MTPA % km km/hour m3

Capacity

1,730

MMscf/day

Distance

100

km

Table 2. Operational parameters of gas power plant without/with alternative CO2 capture routes.

CCGT power plant

CCGT with MEA CO2 capture power plant

ATR with PSA power plant

Steam Methane Reforming with H2 Membrane power plant

Power plant capacity (MW) Atomic ratio of H/C, Fuel to air equivalence ratio Pressure drop rate in the combustor, 1pc /pc (%) Combustor inlet pressure/reference pressure, Pc /Pref Combustor inlet temperature/reference temperature, Tc /Tref combustor inlet pressure, pc (Pa) Steam/fuel ratio Power plant capacity (MW) Atomic ratio of H/C, Fuel to air equivalence ratio, 8 Combustor inlet pressure, pc (MPa) Flue gas bypass rate Gas turbine plant thermal efficiency (%) Power plant capacity (MW) Natural gas hydrogen/carbon ratio, HC Steam/Carbon ratio, SC O2 /Carbon ratio, OC H2 recovery ratio, HR (%) H2 to electricity efficiency, HE (%) Power plant capacity, MW Natural gas hydrogen/carbon ratio H/C SMR + Membrane temperature (K) SMR + Membrane pressure (bar) Steam/carbon ratio H2 to electricity efficiency (%)

500 3.886 0.85 3 15.8 1.8 1,600,000 0 500 3.886 0.85 1.6 0 55 500 3.886 2 0.5 95 60 500 3.8862 1,075 10 3 60

Table 3. CO2 transportation operational parameters.

Mass flow rate of CO2 product in pipeline (kg/s) Length of the pipeline (km) CO2 velocity in pipeline (m/s) CO2 inlet pressure (MPa) CO2 outlet pressure (MPa) CO2 temperature ( C)

44.84 150 2 15 15 25

CO2 capture. This also results in the highest GHG emissions per MW generated, compared to the other power plants with CO2 capture. ATR with CO2 PSA capture power plant has low energy efficiency. This is due to the fact that the configuration of ATR with CO2 PSA capture requires pure O2 from the Air Separation Unit, which consumes energy. On the other hand, the concentration of H2 in the offgas exiting from PSA unit is high. The H2 in the offgas is combusted, rather than being converted to electricity. This also reduces the whole plant energy efficiency.

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Table 4. CO2 injection operational parameters.

CO2 injection rate (t/hr) Depth of reservoir (m) Reservoir horizontal permeability (mD) Reservoir vertical permeability (mD) Reservoir pressure (MPa) Reservoir Thickness (m) Surface temperature (F) Temperature increase in CO2 heater (F)

161.44 1239 22 22 8.4 171 68 5

Figure 9. GHG emissions per kg NG supplied from North Field (Qatar) to South Hook (UK).

Compared to conventional CCGT plant, the energy penalties of CO2 capture for SMR with H2 membrane plant, CCGT with MEA CO2 capture plant and ATR with CO2 PSA capture plant are 3.51%, 6.09% and 11.75% respectively. The energy penalties of CO2 capture by SMR with H2 membrane plant and CCGT with MEA CO2 capture plant are lower than energy penalties of CO2 capture from coal based plant, which are normally great than 10% [4,6].

Figure 11 shows that gas power plants with CO2 capture can reduce life cycle GHG emissions by 74%–85%. With respect to gas power plants with CO2 capture, the majority life cycle GHG emissions are from gas processing plant, LNG plant, LNG shipping and power plant. Our operation processes or construction processes account for insignificant GHG emissions in the life-cycle perspective.

CONCLUSIONS This paper described the development of a dynamic LCA framework for the ‘‘cradle-to-grave’’ assessment of alternative CCS technologies in fossil fuel power generation. The functionality of the LCA model developed is demonstrated using natural gas produced in Qatar shipped to the UK by LNG and used in power plant with alternative configurations and CO2 capture routes. The LCI models developed quantify flows of materials, natural resources, energy, intermediate products and emissions at component unit process level, based on fundamental physical/chemical principles or empirical relationships which, to a greater extent, account for the technological, spatial and temporal characteristics of the power generation systems considered. This approach not only addresses the limitations of conventional LCI models that use linear input/output coefficients, but also facilitates the screening of technological options in order to improve the life cycle environmental performance of a power generation system with CCS. The development of the LCI models at component unit process level and the use of fundamental physical/chemical principles in the calculations have improved the ability of the LCI models to handle the complexity of fossil fuel power generation systems and reduced the LCA model uncertainty. The models referred to in the literature address LCA needs of the existing power generation plants.

However, they do not offer solutions for novel systems that are not commercially operational. The LCI methodology developed at Imperial College provides an innovative and robust approach for conducting LCA for novel systems by configuring virtual systems at unit process level.

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Figure 10. Comparison of alternative power plant configurations.

Figure 11. Life cycle of GHG emissions for alternative power plant configurations with gas supplied from Qatar.

The results of the case study suggest that gas-fired power generation with alternative CO2 capture systems can significantly reduce life-cycle GHG emissions by 74%–85%. For gas power plants with alternative CO2 capture routes, the majority life cycle GHG emissions are from the gas supply chain.

This implies that the reduction of GHG emissions from the supply chain has the potential to decrease life-cycle GHG emissions significantly. This also implies that gas power plants with CO2 capture using gas from different supply chains can have considerable variation in their carbon foot print.

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[8] Akai M., Nomura N., Waku H. and Inoue M. Life-cycle analysis of a fossil-fuel power plant with CO2 recovery and a sequestering system. Energy. 1997;22:249–255.

[9] Fiaschi D., Lombardi L. and Manfrida G. Life cycle assessment (LCA) and exergetic life cycle assessment (ELCA) of an innovative energy cycle with zero CO2 emissions. Proc. 5th Int. Conf. Greenhouse Gas Control Technologies, Cairns, 2000.

[10] Doctor R.D., Molburg J.C., Brockmeier N.F., Lynn M., Victor G., Massood R. and Gary J.S. Life-cycle analysis of a shell gasification-based multi-product system with CO2 recovery. Proc. 1st Nat. Conf. Carbon Sequestration, Washington, D.C., USA, 2001.

[11] Lombardi L. Life cycle assessment comparison of technical solutions for CO2 emission reduction in power generation. Energy Convers. Manage. 2003;44:93–108.

[12] Koornneef J., Keulen T.V., Faaij A. and Turkenburg W. Life cycle assessment of a pulverized coal power plant with postcombustion capture, transport and storage of CO2 . Int. J. Greenhouse Gas Control. 2008;2:4, 448–467.

[13] Pehnt M. and Henkel J. Life cycle assessment of carbon dioxide capture and storage from lignite power plants. Int. J. Greenhouse Gas Control. 2009;3:1, 49–66.

[14] Corti A. and Lombardi L. Biomass integrated gasification combined cycle with reduced CO2 emissions: Performance analysis and life cycle assessment (LCA). Energy. 2004;29:12–15, 2109–2124.

[15] Singh B., Strømman A.H. and Hertwich E. Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture, transport and storage. Int. J. Greenhouse Gas Control. 2010. doi:10.1016/j.ijggc.2010.03.006.

[16] Coal in sustainable society (CISS), 2003, Case study B17: electricity from CO2 recovery type IGCC. Available at: www.ciss.com.au. Assessed 6 December 2004.

[17] ISO 14040 (E), 2006. Environmental Management – Life Cycle Assessment – Principles and Framework.

International Organization for Standardization, Geneva.

[18] Guine’e J.B., Gorre’e M., Heijungs R., Huppes G., Kleijn R. and Koning A. 2001, Life cycle assessment: An operational guide to the ISO standards, Final report, Centre of Environmental Science – Leiden University (CML), May 2001.

[19] Goedkoop M. and Spriensma R. The Eco-indicator 99 A Damage Oriented Method for Life Cycle Impact Assessment: Methodology Report, no. 1999/36A. 3rd ed., Pre Consultants b.v, Amersfoort, the Netherlands.

2001.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Gas turbine related technologies for carbon capture R. Peter Lindstedt* Department of Mechanical Engineering, Imperial College, Exhibition Road, London SW7 2AZ, UK * p.lindstedt@imperial.ac.uk

ABSTRACT Combustion modes in gas turbines are evolving in order to meet requirements related to lower emissions and greater thermodynamic efficiency. Such demands can be contradictory and the additional complication of fuel flexibility comes to the fore with potential new fuel stream opportunities arising. The latter may include hydrogen and carbon monoxide rich streams as well as blends with significant amounts of carbon dioxide arising from certain types of syngas (e.g. bio-derived). The matter is further complicated by the impact of combustion stability related issues that arise in the context of the ubiquitous transition to lean pre-vapourised premixed (LPP) combustion for power generation applications. Post-combustion carbon capture is generally considered the leading candidate in the context of LPP based technologies. Significant capture related issues arise in terms of parasitic losses associated with CO2 separation and transportation technologies (e.g. compression). The former is typically the major contributor and the relatively low concentration of CO2 in flue gases, combined with excess oxygen resulting from LPP based operation, does impact separation technologies. It hence appears natural to consider the operating mode of the gas turbine and the impact of the fuel composition on the flue gas characteristics alongside the development of efficient and novel separation technologies.

Keywords: Gas turbines, Combustion modes, CCS, CO2 separation

http://dx.doi.org/ 10.5339/stsp.2012.ccs.12 Published: 19 December 2012 c 2012 Lindstedt, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Lindstedt RP. Gas turbine related technologies for carbon capture, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:12 http://dx.doi.org/10.5339/stsp.2012.ccs.12

Page 2 of 5 Lindstedt, Sustainable Technologies, Systems and Policies 2012.CCS.12

INTRODUCTION The use of carbon capture and storage (CCS) has been identified as a potentially significant contributor in the quest for reduced CO2 emissions with the IEA suggesting [1] that deployment in the context of industrial and power generation applications can make a 19% contribution towards meeting the Blue Map Scenario. The potential success of carbon capture (CC) technologies depends to a significant extent on the ability to maintain a high overall efficiency of the process cycle and, by implication, a reduction in parasitic losses associated with CO2 separation technologies. Such losses have been estimated to range from 6 to 8% depending on the process used [2] with a corresponding impact on fuel consumption and cost of operation. By means of comparison, the move to advanced gas turbine based combined cycle plants from older gas-fired boilers can be expected to increase the efficiency [3] from around 39% to above 58% depending on the specific technology options applied.

Accordingly, the parasitic losses associated with carbon capture cannot be considered modest and the need for improved technologies and process optimization arises. In order to achieve optimal performance it appears natural for the gas turbine component to be considered alongside the development of (novel) separation processes. Hence, it is argued that, in addition to achieving optimum gas turbine efficiencies and low emissions, consideration should also be given to the exploration of combustion modes that permit subsequent separation processes to operate at maximum efficiency and vice versa. In other words, an additional constraint arises alongside current challenges associated with demands for fuel flexibility and the generalization of the combustion mode transition to lean pre-vapourised premixed operation.

TECHNOLOGY CHALLENGES The brief summaries provided below are primarily intended to provide a background for discussion and the identification of technology needs.

Capture options Post-combustion capture has the key advantages that retro-fit is possible and that power generation can continue in the absence of capture should an outage occur. It can readily be argued that the alternatives of oxy-fuel combustion and pre-combustion capture are not suitable options. The use of oxy-fuel combustion has the advantage of providing CO2 rich flue gases. However, the impact on combustion stability, combustion temperatures and emissions in a gas turbine context is likely to prove prohibitive. It is possible to speculate that a vitiated (CO2 rich) environment can be used [4] though the process complications will be significant. Nevertheless, it can readily be recognized that syngas related fuel streams, typically associated with integrated coal gasification combined cycle (IGCC) plants, may also arise in other related (e.g. process plant) contexts, and may provide suitable fuel streams. In addition, H2 rich fuel streams will arise in the context IGCC plants and can in principle be used in gas turbines subject to the applied combustion mode.

Gas turbine technologies The challenges associated with the transition to LPP based combustion modes for power generation are well known and have been the subject of intensive research programs in the EU and the US. It is not the intention to review these extensive efforts as part of the current paper, though it is relevant to point out that more reactive fuels (e.g. hydrogen rich streams) present greater challenges. It may also be noted that active and passive control strategies have been explored as well as efforts aimed at creating more intrinsically stable combustors. Some of the guidelines that can be followed have been outlined [5] and solutions that permit the use of combustion regime independent calculation methods have been developed jointly with gas turbine manufacturers [6]. The design ideas summarised by Milosavljevic et al. [5], based on targeted near field aerodynamics, contributed to the commercial launch of the Siemens SGT-750. The novel stabilization and design approach used for the burner resulted in the filing of a large number of patent applications and provide a pointer towards development directions and targets. The baseline configuration, operating on natural gas, demonstrated ultra low emissions over a wide temperature range, less than 10 ppm NOx at flame temperatures in the range 1550â&#x20AC;&#x201C;1850 K during piloted operation, less than 1 ppm CO at flame temperatures above 1450 K, reduced issues pertaining to combustion dynamics and stable combustion over a wide range of temperatures. The use of a rich pilot combustor (RPC) stabilised the

Page 3 of 5 Lindstedt, Sustainable Technologies, Systems and Policies 2012.CCS.12

flame for both rich and lean conditions, with the main flame stability not reliant on the RPC at high loads and shallow slopes in the NOx curve at the design flame temperature were observed.

Results obtained using prototype burners with different RPC configurations are exemplified in Fig. 1, which show the joint emissions of NOx and CO for different operating points.

9.0

NOx (15% O2)

8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0

0.0

10.0

20.0 CO ppm

30.0

Figure 1. Combined CO and NO emissions for different configurations of the RPC component of prototype LPP burners (courtesy of Dr Milosavljevic).

Further challenges of relevance to the effectiveness of carbon capture include the efficient use of hydrogen rich mixtures and, in general, fuel flexibility. It may also be noted that the development of combustion technologies operating at overall lower temperatures in a distributed reaction mode is also likely to be beneficial.

Fuel blends Conventional fuel blends used in the context of gas turbines for propulsion devices have received much attention as part of world-wide research efforts and summaries are available [7,8] along with increasingly accurate chemical kinetic mechanisms [9]. It is, however, notable that while Fischer-Tropsch based fuels show significant potential for reductions of emissions of particulates, their chemistry has received comparatively little attention to the point where the inclusion of chemical kinetics into design calculations is often not possible. The knowledge of the corresponding lower hydrocarbon chemistry is much further advanced and for hydrogen and methane progress has been made to the point where properties of both laminar and turbulent systems can be computed with good accuracy [10,11]. There are, however, gaps in our understanding of the behavior of hydrogen rich fuel blends as may arise, for example, in the context of refinery gas and syngas from different sources. Issues that remain to be addressed also include the impact of smaller quantities of more reactive hydrocarbons upon the combustion characteristics of such mixtures in the context of gas turbines operating in a LPP mode.

Pollutants in flue gases Combustion generated oxides of nitrogen and sulphur may have an impact on subsequent CO2 separation technologies. The problems associated with oxides of sulphur can be expected to be insignificant as compared to cases featuring the use of solid or heavy liquid fuels. Nevertheless, oxides of nitrogen will form and need to be taken into account as part of post-combustion CO2 removal. The amount of NOx formed is strongly dependent upon the gas turbine combustion technology and the sensitivity of subsequent processes can be expected to influence technology options. The inter-conversion of oxides of nitrogen and sulphur in flue gases resulting from oxy-coal combustion has been studied computationally [12â&#x20AC;&#x201C;14] using detailed chemical kinetic modeling.

The gas phase chemistry was based on a comprehensively validated C/H/N/S kinetic model featuring 75 chemical species and 406 reversible reactions. A novel aqueous phase extension, featuring 13 chemical species and 20 reversible reactions, was also implemented along with mass transfer between both phases. Missing or outdated thermodynamic data was calculated using G3B3 quantum mechanical methods and the chemistry extended to include low temperature pathways using RRKM/ME based methods [15]. Computed results were compared with experimental data obtained from a Doosan Babcock 160 kW coal-fired oxy-fuel rig as exemplified in Fig. 2.

Page 4 of 5 Lindstedt, Sustainable Technologies, Systems and Policies 2012.CCS.12

% Conversion

100% 75% 50% SO2 NOx Experimental SO2 Experimental NOx

25% 0%

0

50

100

150

200

250

300

350

400

Time (s)

Figure 2. Computed conversion of SO2 and NOx against time for experimental data [7]. Initial conditions: 761 ppm of SO2 , 332 ppm of NOx , 300 K and 7 Atm.

The results obtained suggest that detailed chemical kinetic modeling can provide useful information with respect to the evolution of pollutants in flue gases and that such computations are likely to assist in the process optimization of gas turbine based CC technologies.

CONCLUSIONS The following directions for future research are suggested: 1. The interface between gas turbine and CO2 separation technologies can usefully be considered much further in order to provide a basis for future process optimization.

2. The impact of fuel blends on the flue gas composition and on the potential of separation technologies can be considered in greater detail. This includes the role of potential pollutants such as oxides of nitrogen.

3. The issue fuel flexibility in relation to suitable combustion modes for gas turbines is likely to be of significant, perhaps even dominant, importance. It is also notable that further work is required on the characterization of the chemistry and turbulent burning characteristics of alternative (e.g. Fischer-Tropsch) derived fuels.

4. The safety aspects associated with hydrogen rich mixtures will need to be better defined given the likelihood of their increased use.

It is, of course, possible to define further research and development directions and to provide a more fine-grained breakdown of the above. Nevertheless, it is notable that the above topics are likely to be of significant importance to the success of CC technologies.

REFERENCES

[1] International Energy Agency, Energy Technology Perspectives 2008, Scenarios and Strategies to 2050, ISBN 978-92-64-04142-4 (2008), pp. 1–650.

[2] International Energy Agency, Improvement in Power Generation with Post-Combusiton Capture of CO2 , Report Number PH4/33 (2004), pp. 1–272.

[3] Alstom Press Release, Essent Combined Cycle Plant Announcent, December 2008, http://www.alstom.com/press-centre/2008/12/alstoms-orders-from-essent-confirmed-in-the-netherlandspaving-the-way-for-major-combined-cycle-power-plant/.

[4] Wall T.F. Combustion processes for carbon capture. Proc. Combust. Inst. 2007. doi:10.1016/j.proci.2006.08.123.

[5] Milosavljevic V.D., Lindstedt R.P., Cornwell M.D., Gutmark E.J. and Vaos E.M. Combustion instabilities near the lean extinction limit. Advances in Combustion and Noise Control. Roy G., Yu K.H., Whitelaw J.H. and Witton J.J. eds., 2006; 149–165.

[6] Lindstedt R.P., Milosavljevic V.D. and Persson M. Turbulent burning velocity predictions using transported PDF methods. Proc. Combust. Inst. 2010. http://dx.doi.org/10.1016/j.proci.2010.05.092 [7] Colket M., Edwards T., William S., Cernansky N., Miller D., Egolfopoulos F., Lindstedt P., Seshadri K., Dryer F., Law C.K., Friend D., Lenhert D.B., Pitsch H., Sarofim A., Smooke M. and Tsang W. Development of an Experimental Database and Kinetic Models for Surrogate Jet Fuels, Paper AIAA-2007-770, Presented at 45th AIAA Aerospace Sciences Meeting, Reno (2007).

[8] Colket M., Edwards T., William S., Cernansky N., Miller D., Egolfopoulos F., Lindstedt P., Seshadri K., Dryer F., Law C.K., Friend D., Lenhert D.B., Pitsch H., Sarofim A., Smooke M. and Tsang W. Identification of Target Validation Data for Development of Surrogate Jet Fuels, Paper AIAA-2008-972, Presented at 46th AIAA Aerospace Sciences Meeting, Reno (2008).

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[9] Wang H., Dames E., Sirjean B., Sheen D.A., Tangko R., Violi A., Lai J.Y.W., Egolfopoulos F.N., Davidson D.F., Hanson R.K., Bowman C.T., Law C.K., Tsang W., Cernansky N.P., Miller D.L. and Lindstedt R.P. A high-temperature chemical kinetic model of n-alkane (up to n-dodecane), cyclohexane, and methyl-, ethyl-, n-propyl and n-butyl-cyclohexane oxidation at high temperatures, JetSurF version 2.0, 2010. ( http://melchior.usc.edu/JetSurF/JetSurF2.0).

[10] Gkagkas K. and Lindstedt R.P. Transported PDF modelling with detailed chemistry of pre- and auto-ignition in CH4 /air mixtures. Proc. Combust. Inst. 2007;31:1559–1566.

[11] Gkagkas K. and Lindstedt R.P. The impact of reduced chemistry on auto-ignition of H2 in turbulent flows. Combust.

Theory Model. 2009;13:607–643.

[12] Cerru F.G., Kronenburg A. and Lindstedt R.P. Systematically reduced chemical mechanisms for sulphur oxidation and pyrolysis. Combust. Flame. 2006;146:437–455.

[13] Lindstedt R.P., Lockwood F.C. and Selim A. Detailed kinetic study of ammonia oxidation. Combust. Sci. Technol.

1995;108:231–254.

[14] Lindstedt R.P. and Robinson R.K. Detailed chemical kinetic modeling of pollutant conversion in flue gases from oxycoal plant, Proceedings First Oxyfuel Combustion Conference, Dresden, September 2009.

[15] Robinson R.K. and Lindstedt R.P. On the chemical kinetics of cyclopentadiene oxidation. Combust. Flame.

2011;158:666–686.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

An overview of carbon capture technology Bruce R. Palmer* Chemical Engineering Program, Texas A&M University at Qatar, Doha, Qatar * Email:

bruce.palmer@qatar.tamu.edu

CARBON CAPTURE FROM NATURAL GAS Natural gas produced from gas and/or petroleum reservoirs could contain substantial amount of hydrogen sulfide and carbon dioxide, known as ‘‘acid gas.’’ The presence of small concentrations of H2 S (ppm levels) in natural gas results in a sour gas with a drastically-reduced market price and hampered wide utilization. Additionally, the presence of CO2 in the natural gas could decrease its calorific value and increase its transportation cost. Therefore, natural gas desulfurization, or sweetening processes for treating natural gas, are an integral part of natural gas cleanup. After H2 S is captured chemically using a base solvent such as aqueous amines, the concentrated H2 S streams are sent to the Claus sulfur plants to produce elemental sulfur or can be used to produce sulfur oxides which are converted ultimately into sulfuric acid or used to produce gypsum [14].

The amines frequently used to capture H2 S for natural gas can also react and remove carbon dioxide. The carbon dioxide co-extracted in the desulfurization of natural gas can be emitted into the atmosphere after hydrogen sulfide is converted to sulfur or can be captured and sent to sequestration sites, depleted petroleum, and or/natural gas reservoirs or saline aquifers for disposal. The CO2 captured from natural gas streams can also be used for enhanced oil recovery (EOR) to produce oil from petroleum reservoirs (see Fig. 1).

Coalbed methane production

Injection of CO2 in to geologic reservoirs

Pipeline transporting CO2 from power plants to injection site

Offshore natural gas production with CO2 separation and sequestration

Deep coal seam

Deep brine formation

http://dx.doi.org/ 10.5339/stsp.2012.ccs.13 Published: 18 December 2012 c 2012 Palmer, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Depleted hydrocarbon reservoir

Reservoir trap/seal

Natural gas reservoir

Brine formation

Original illustration by Eric.A. Morissdey. U.S. Geological Survey illustration modified by sean Brennan. U.S. Geological Srvey

Figure 1. Geologic disposal options for acid gases. Source: Burruss and Brennan [2].

The CO2 captured from natural gas is usually near atmospheric pressure and contains significant amounts of water so that its injection in a geologic formation requires multistage high-pressure compressors with intercooling. Based on the depth and conditions of the geologic formation, the injection is frequently carried out at about 150 bars. If the CO2 to be sequestered still contains a small fraction of H2 S, this acid gas can be also injected in the geologic formation without major Cite this article as: Palmer BR. An overview of carbon capture technology, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:13 http://dx.doi.org/10.5339/stsp.2012.ccs.13

Page 2 of 6 Palmer, Sustainable Technologies, Systems and Policies 2012.CCS.13

difficulties. The only problem would be that wet H2 S is highly corrosive to carbon steel so stainless steel facilities are required after the compression station. The compression plant is shown in Fig. 2.

Dew point control Captured CO2

Dehydration CO2 Pipeline

1st Stage

2nd Stage

3rd Stage

4th Stage

Figure 2. Compression of carbon dioxide for sequestration. Source: KBR.org 1 [10].

The first industrial-scale carbon dioxide storage project was implemented at the Sleipner gas field in Norway. The produced natural gas contains about 9% CO2 . In this North Sea field, one million tons/year of liquefied carbon dioxide is injected into a saline aquifer in the Utsira sandstone formation as shown in Fig. 3. Injection depth is one kilometer. The sandstone formation has a storage capacity of about 600 billion tons of carbon dioxide. The project economics are very favorable, based on avoidance of the European carbon tax.

Figure 3. Sequestration of carbon dioxide in the Utsira sandstone formation.

Source: Energy-pedia.org [3].

The Middle East has the potential to produce large amounts of acid gas as reservoirs of increasingly higher sulfur content must be tapped. This natural gas will be required to meet the considerable natural gas demands of the Middle East and the natural gas customers of this region. Acid–gas injection is being considered in the Middle East as a means to dispose of the tremendous amounts of CO2 that will be produced in the future.

CARBON CAPTURE FROM FLUE GAS (POST-COMBUSTION) The largest carbon dioxide source is combustion of coal for power generation. The flue gas produced from power generation facilities contains particulates and about 15% by volume carbon dioxide. A typical process for treating combustion products, including carbon dioxide removal, is shown in Fig. 4. The flue gas cleanup techniques involve (1) injection of ammonia followed by catalytic reaction to remove NOx (2) removal of particulates by electrostatic precipitation (3) removal of sulfur dioxide with calcium oxide, and (4) recovery of carbon dioxide capture by amine solvents.

The most common post-combustion carbon-capture process uses alkyl amines to chemically capture carbon dioxide from combustion gases [14]. Typical amines and concentrations for carbon dioxide removal are monoethanolamine (32%), diethanolamine (20–25%), methyldiethanolamine (30–55%) and diglycolamine (50%). In the capture process, the aqueous amine, which is a weak base, reacts with acidic CO2 , to form water-based aminated products. This is illustrated below for reaction with monoethanolamine [12,17]: 2RNH2(aq) + CO2(g) + H2 O(l) ! RNHCOO(aq) + RH+ 3 (aq) .

(1)

Page 3 of 6 Palmer, Sustainable Technologies, Systems and Policies 2012.CCS.13

CO2

NH3

Selective catalytic reactor (SCR)

Air heater

Boiler Electrostatic precipitator (ESP)

Flue gas desulphurization (FGD)

CO2 recovery

Stack

Figure 4. Post-combustion processing of combustion gas.

Source: KBR.org 1 [10].

The aminated product is then stripped thermally to yield carbon dioxide at a high concentration and near atmospheric pressure.

Some gas streams contain both CO2 and H2 S. This is the case in processing natural gas, for example. The sulfur-bearing H2 S is also acidic and is extracted by amines as indicated below, RNH2(aq) + H2 S(g) $ RNH3 HS(aq) .

(2)

The amine extraction process is shown in more detail in Fig. 5. Extraction and stripping are operated counter currently. Extraction of hydrogen sulfide is equilibrium limited whereas carbon dioxide extraction is kinetically limited which could facilitate capturing each gas in different steps [16]. For sequestration by injection, carbon dioxide from the amine unit, which likely contains some hydrogen sulfide, is compressed as described above.

Condenser

Sweet gas

cw

(H2S + CO2) Acid gas

Makeup water

Top tray

Rich amine

Reflux Top tray Pump

cw

Absorber

Sour Gas

Lean amine

Reflux drum

Bottom tray

Regenerator

Bottom tray

Vapour

Steam Reboiler

Rich amine

Typical operating ranges

Liquid Condensate

Lean amine Pump

Absorber : 35 to 50°C and 5 to 205 atm of absolute pressure Regenerator : 115 to 126°C and 1.4 to 1.7 atm of absolute pressure at tower bottom

Figure 5. Amine processing for acid–gas removal.

Source: Wikipedia.org 1 [17].

In 1976, Kerr-McGee Chemical (now North American Chemical) built an MEA amine unit for carbon dioxide capture at an electric generation utility at the Searles Valley, California, chemical plant. The plant ran for several decades, and the technology was licensed to the Shady Point Power Plant in Oklahoma in 1991 [1].

Page 4 of 6 Palmer, Sustainable Technologies, Systems and Policies 2012.CCS.13

While acid–gas treatment and carbon dioxide capture with amines are similar, there are substantial differences in the two processes. The pressures in the extractors are substantially different.

Desulfurization pressures in the range of 20–60 bars are typical [4,16]. Conversely, carbon dioxide capture from combustion gases operates near atmospheric pressure. Additionally the volume of gas from combustion processes is substantially greater than the amount of natural gas processed in amine units, and accordingly the equipment for combustion processing is substantially larger than the equipment required for natural gas processing.

CARBON CAPTURE FROM FUEL GAS (PRE-COMBUSTION) These processes involve integrated gasification combined cycle (IGCC). In this process, coal is gasified in gasifiers under controlled conditions using steam and oxygen (or air) to produce raw synthesis gas (syngas) which consists mainly of (CO and H2 ). The processes are advantageous to flue gas capture because the CO2 concentration is much greater and the pressure is elevated above atmospheric, greatly facilitating CO2 removal [9].

In IGCC, initially the raw syngas is cleaned from particulates and sulfur containing-compounds (H2 S, SOx ) and then is subjected to a water-gas-shift (WGS) reaction where CO reacts with water in the presence of catalysts in two stages in order to increase the hydrogen content of the syngas.

Unfortunately, for every mole of H2 produced one mole of CO2 is produced in the WGS reaction as shown below: CO(g) + H2 O(g) ! CO2(g) + H2(g)

(3)

At high temperatures, 350 C, iron oxide promoted with chromium oxide iron oxide promoted with chromium oxide is employed. As the temperature drops to 190–210 C, copper supported by a mixture of zinc oxide and aluminum oxide is employed [18].

Conventionally, acid gas is removed from the shifted syngas after cooling it to near ambient or sub-ambient temperature. This technology is well established. Korens et al. [11] lists 44 commercial-scale gasification units. A number of acid–gas treatment options are employed as described below.

Methyl diethanolamine (MDEA) has been used for the removal of acid gases from syngas for decades. It is still a strong contender as an acid–gas removal option because it is effective and there is a wide range of experience in application of this extractant. Additionally, it has been formulated with proprietary additives to increase sulfur selectivity over carbon dioxide.

The Selexol process employs a physical solvent for removal of acid gases. Selexol comprises mixed dimethylethers of polyetheleneglycol as the physical solvent and is a competitor to MDEA. Selexol removes hydrogen sulfide preferentially to carbon dioxide so these gases can be separated, if required. However, this may not be necessary for sequestration as acid gas can be injected directly.

The Selexol solvent is stripped with steam or with inert gases to remove hydrogen sulfide and carbon dioxide.

One advantage of Selexol is that, since acid–gas extraction does not employ chemical reactions, the energy consumption is typically lower than the energy demand for amine processing. Accordingly, the Selexol process is a solid contender for IGCC carbon dioxide capture and sequestration. If desired two-stage removal of acid gas can be carried out, hydrogen sulfide is removed first followed by carbon dioxide. High concentration gases are produced in stripping, reducing subsequent sequestration costs. Reduction in the solvent temperature increases removal of hydrogen sulfide and carbon dioxide in Selexol acid–gas processing.

The Rectisol process employs refrigerated methanol as the physical solvent. This process is employed for production of high-purity syngas for chemical synthesis. Rectisol is considered to be the most costly process for treating acid gas. Accordingly, the Rectisol process probably is of limited application in carbon capture from power plants.

More recently use of fluorinated solvents has been examined because of the high solubility of CO2 in these solvents [13,6]. Additionally these solvents dissolve CO2 preferentially to N2 , H2 , CO and CH4 . The use of an ionic liquid, a quaternary ammonium polyether, was also investigated for capture of CO2 [7,8]. This work paves the way for cleanup of syngas under warm conditions, allowing elimination of refrigeration in the sorption process.

Page 5 of 6 Palmer, Sustainable Technologies, Systems and Policies 2012.CCS.13

Production of carbonyl sulfide, COS, can pose a problem in both IGCC and Claus sulfur recovery units, because this species does not react with amine solvents. Carbonyl sulfide removal can be effected by hydrolysis; the reaction is as follows: COS(g) + H2 O(g) ! CO(g) + H2 S(g) .

(4)

This reaction is facilitated with an activated alumina-based catalyst and is normally designed to operate at 175 to 200 C. Hydrolysis thermodynamics become more favorable as the temperature is reduced so the operating temperature is a balance between the kinetic and thermodynamic considerations. Typically, the hydrolysis product gas is cooled using the sensible heat to generate steam before the acid gas removal stage(s) [5].

Most IGCC units use carbonyl sulfide hydrolysis prior to acid–gas removal. One exception is the Rectisol process. Carbonyl sulfide hydrolysis is required to obtain sufficient total sulfur removal when the MDEA and Selexol processes are employed. Conversely, very high extractions of hydrogen sulfide and carbonyl sulfide are possible with the Rectisol process.

The IGCC units employing oxygen as the oxidant is particularly suitable for nearly total carbon dioxide removal from the syngas for carbon dioxide sequestration. This application employs a carbon monoxide shift reactor followed by acid–gas absorption. In this instance, hydrogen sulfide can be removed in one acid–gas removal process (absorber and stripper), and carbon dioxide is removed in the subsequent acid gas removal step (absorber and stripper). The WGS may be carried out prior to acid–gas absorption with a catalyst that can tolerate sulfur. This process is illustrated in Fig. 6.

TO METHANATOR

VENT

TO CLAUS

H2S ABSORBER

FEED

H2S STRIPPER

CO2 ABSORBER

CO2 STRIPPER

AIR

STEAM

SULPHUR REMOVAL CO2 REMOVAL

Figure 6. Flow diagram of Selexol process for acid gas Removal from coal-derived synthesis gas.

Source: Korens et al. [11].

CARBON CAPTURE FROM OXY-FUEL COMBUSTION This process involves combustion of coal in oxygen. The products of combustion are water and carbon dioxide. Early work by Argonne National laboratory is reported by Kumar et al. [20]. The adiabatic flame temperature in oxy-fuel combustion is very high so that the flame temperature is moderated by dilution of oxygen with the carbon dioxide produced in combustion. Carbon dioxide is cooled before utilization as the diluent. Water is removed from the gases produced in combustion by condensation, and the resulting carbon dioxide is nearly pure. This technique has a number of attributes; the product is nearly pure carbon dioxide which minimizes sequestration costs.

Additionally it is possible that this process might be employed in existing power plants. The attributes are moderated by the high cost of producing high-purity oxygen [19].

One of the first demonstration plants is Callide-A Oxyfuel, which is a joint venture of several firms from Australia and Japan. The first phase is a 30 MW demonstration. The second phase will produce 150,000 tonnes/year of CO2 for about four years. The injection of CO2 into the Northern Denison Trough and sites in southeast Queensland also will be examined [15]. There is little experience in application of this technique so it is likely that the development costs will be substantial and the risk in building the first plants will be high.

Page 6 of 6 Palmer, Sustainable Technologies, Systems and Policies 2012.CCS.13

ACKNOWLEDGEMENT The author wishes to acknowledge the assistance of Professor Badie I. Morsi, Department of Chemical Engineering, University of Pittsburgh, in preparation of this manuscript.

REFERENCES

[1] Baldwin R.A. and Surtees L. personal communication, 15 March 2012.

[2] Burruss R.C. and Brennan S.T. Geologic Sequestration of Carbon Dioxide—An Energy Resource Perspective, US Geological Survey Fact Sheet 2003–026, 2 p.

[3] Energy-pedia.org. Norway Statoil Hydro’s Sleipner Carbon Capture and Storage Project Proceeding Successfully, Page last modified 9 March 2009, accessed 23 March 2012.

[4] Gary J.H. and Handwerk G.E. Petroleum Refining Technology and Economics. 2nd ed., Marcel Dekker, Inc. 1984.

[5] Gasifipedia.org. Gasification Systems, National Energy Technology Laboratory (NETL), Page accessed 12 March 2012.

[6] Heintz Y.J., Sehabiague L., Morsi B.I., Jones K.L. and Pennline H.W. Novel physical solvents for selective CO2 capture from fuel gas streams at elevated pressures and temperatures. Energy & Fuels. 2008;22:3824–3837.

[7] Heintz Y.J., Sehabiague L., Morsi B.I., Jones K.L., Luebke D.R. and Pennline H.W. Hydrogen sulfide and carbon dioxide removal from dry fuel gas streams using an ionic liquid as a physical solvent. Energy Fuels. 2009;23:4822–4830.

[8] Heintz Y.J., Morsi B.I., Luebke D., Keller M.J. and Resnik K.P. A conceptual process for selective capture of CO2 from Fuel Gas Streams, Annual Meeting, AIChE, 2010.

[9] KBR.org 2. Post Combustion Carbon Capture, Page last modified 2011, accessed 23 March 2012.

[10] kBR org 1. CO2 Compression & Sequestration, Page last modified 2011, accessed 23 March 2012.

[11] Korens N., Simbeck D.R. and Wilhelm D.J. Process for Screening Analysis of Alternative Treating and Sulfur Removal for Gasification, Final Report. SFA Pacific, Inc. Prepared for the U.S. Department of Energy, National Energy Technology Laboratory, 2002 [12] Kohl A. and Nielson R. Gas Purification. 5th ed., Gulf Publishing. 1997.

[13] Morsi B.I., White C. and Pennline H. Development and testing of fluorinated oligomers as CO2 solvents for high-temperature and high-pressure applications. Gasification Merit Review. National Energy Technology Laboratory, 2003 [14] Natural gas.org. Processing Natural Gas, Page accessed 14 March 2012.

[15] Sequesteration mit.edu. Callide-A Oxyfuel Fact Sheet: Carbon Dioxide Capture and Storage Project, Page last modified 23 November 2011, accessed 27 March 2012.

[16] Weiland R. and Hatcher N. Sour gas treatment and effective management, workshop at the 2011 Sour Oil and Gas Advanced technology Meeting, Abu Dhabi, UAE. [17] Wikipedia.org 1. Amine Gas Treating; Page last modified 1 March 2012, accessed 23 March 2012.

[18] Wikipedia.org 2. Water Gas Shift Reaction, Page last modified 23 January 2012, accessed 23 March 2012.

[19] Wikipedia.org 3. Oxy-fuel combustion process, Page last modified 15 January 2012, accessed 27 March 2012.

[20] Kumar R., Fuller T., Koeourek R., Teats G., Young J., Myles K. and Wolsky A. Tests to Produce and Recover Carbon Dioxide by Burning Coal in Oxygen and Recycled Flue Gas, Black Hills Power and Light Company Customer Service Center Boiler No. 2, Rapid City, South Dakota, Argonne National Laboratory Report ANL/CNSV-61, 1987.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

The Lacq industrial CCS reference project (France) Jacques Monne* Lacq Pilot, Total E&P, France * Email:

jacques.monne@total.com

http://dx.doi.org/ 10.5339/stsp.2012.ccs.14 Published: 18 December 2012 c 2012 Monne, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

SUMMARY Total is committed to reducing the impact of its activities on the environment, especially its greenhouse gas emissions. The group’s priorities are to improve the energy efficiency of its industrial facilities, to invest in the development of complementary energy sources (biomass, solar, clean coal) and to participate in many operational and R&D programs on CO2 capture and geological storage (CCS). Total has been involved in CO2 injection and geological storage for over 15 years, in Canada (Weyburn oil field) for EOR and Norway (Sleipner, Snohvit) in aquifer. In 2006, Total decided to invest e60 million in the Lacq basin for experimenting in a complete industrial chain from CO2 capture to transportation and injection in a depleted gas field.

This first French CCS pilot project is unique in several respects; by its size, capturing carbon from a 30 MWth oxycombustion gas boiler (size unprecedented worldwide), by the choice of a deep onshore depleted gas reservoir (unprecedented in Europe) located 5 km south of Pau and its suburbs (around 140,000 inhabitants) and by operating a whole industrial chain (extraction, treatment, combustion of natural gas, high-pressure steam production, CO2 capture, transport and injection) fully integrated in the Lacq industrial complex.

The permitting process was also a first in Europe because at that time (from 2007 up to 2009), the Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide was not issued and the French authorities decided to apply the ‘‘mining law’’ for the subsurface facilities, and the environmental code for surface facilities. This permitting process has included two months of official public hearing. In parallel to this official process, Total decided to be proactive in the stakeholder involvement. Public information meetings were held since the start of the project in early 2007 and a public consultation and dialog phase has been organized. That led to the creation of a permanent local information and surveillance commission (CLIS). From the beginning of this project, public acceptance has been a major concern.

Total’s approach is to set-up a high level of transparency and open dialog with all stakeholders.

Sharing data with academics though a scientific follow-up committee and achieving specific scientific collaboration programs are also part of our objectives.

This project entails the conversion of an existing air steam gas-boiler into an oxy-gas combustion boiler, oxygen delivered by an air separation unit is used for combustion rather than air to obtain a more concentrated CO2 stream in the flue gas, easier to be captured. The 30 MWth oxy-boiler can deliver up to 40 t/h of steam to the high pressure steam network of the Lacq sour gas production and treatment plant. After a quench of the flue gas, the rich CO2 stream is compressed (up to 27 barg), dehydrated and transported via a pipeline to a depleted gas field, 30 km away, where it is injected in the deep Rousse reservoir. Over 3 and half years, up to 90,000 tons of CO2 will be injected.

The project (Fig. 1) was launched in 2006 and, after commissioning and fine-tuning the individual operation of each piece of equipment, the whole CCS pilot plant started-up the 8th January 2010.

Globally, the operation of the pilot plant has proven to be very satisfactory. The oxy-boiler start-up in air mode, switching from air to oxy mode and load variations up to full capacity have been Cite this article as: Monne J. The Lacq industrial CCS reference project (France), Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:14 http://dx.doi.org/10.5339/stsp.2012.ccs.14

Page 2 of 2 Monne, Sustainable Technologies, Systems and Policies 2012.CCS.14

Industrial scale:

30MWth oxycombustion Integrated within existing facilities

Figure 1. Overview of Lacq project.

demonstrated to be robust, in line with the predicted behavior. The flue gas treatment, which mainly consists of cooling the flue gas stream to remove condensed water and concentrate CO2 up to 95% v, is also working in accordance with the design. The molecular sieve dryersâ&#x20AC;&#x2122; role consists of drastically lowering the CO2 rich stream dew point to protect the carbon steel transportation pipeline against corrosion. The unique equipment in the whole CCS pilot plant, which has proven to be more challenging to operate, is the Lacq CO2 rich stream compressor. The suction chamber of the 3rd stage cylinder was rapidly and severely attacked by acid corrosion. On the other hand, the carbon steel transportation pipeline, and one stage reciprocating compressor, located in Rousse, which is built with the same materials, does not suffer corrosion as they are located downstream of the molecular sieve dryers.

A huge monitoring program was designed in accordance with the specific configuration of the storage site and with the risk assessment studies. It covers full subsurface and surface monitoring aspects: a part of this program has been imposed by the French administration an additional part has been defined for R&D purposes.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Ionic liquids as novel materials for energy efficient CO2 separations Richard D. Noble*, Douglas L. Gin University of Colorado, Boulder, CO 80309, USA * Email:

nobler@colorado.edu

ABSTRACT Large improvements in separations technology will require novel materials with enhanced properties and performance. The fundamental interlinks for success in merging synthesis and process incorporation are the structure, relevant physical/chemical properties, and performance of new materials. Specific materials with these interlinks are room-temperature ionic liquids (RTILs) and their polymers and composites. As a chemical platform, RTILs have an enormous range of structural variation that can provide the ability to ‘‘tune’’ their properties and morphology for a given application. Introduction of chemical specificity into the structure of RTIL-based materials is an additional key component. Membrane separation is the focus as a process for implementation. There have not been new materials successfully developed for this process in thirty years. For CO2 capture, the target improvement in productivity is two orders of magnitude or more compared to commercial materials currently available.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.15 Published: 19 December 2012 c 2012 Noble & Gin, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Noble RD & Gin DL. Ionic liquids as novel materials for energy efficient CO2 separations, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:15 http://dx.doi.org/10.5339/stsp.2012.ccs.15

Page 2 of 7 Noble & Gin, Sustainable Technologies, Systems and Policies 2012.CCS.15

FUNDAMENTAL SCIENTIFIC APPROACH Separations are accomplished either by mass separating agents (MSAs) or by energy separating agents (ESAs). Separations employing ESAs consume significant amounts of primary energy. It is estimated that separations processes account for more than 5% of the primary energy consumption in the United States. The fundamental approach we are undertaking is a major shift from the use of energy intensive separations (e.g., heat for distillation, amine scrubbers) to the tailored design of materials for MSAs as a strategy to achieve mass and energy efficient CO2 separations.

The fundamental links that are the basis of the proposed scientific approach is that the structure of an MSA will determine its properties, which in turn will determine its performance in various separation processes. Likewise, the materials performance criteria will be determined by the process in which an MSA will be employed. A fundamental understanding of how materials properties in an MSA affects its performance can then provide interaction and feedback to indicate what material properties are necessary for various process configurations. If we know the structure/property relationships for a particular type of MSA material, then we can design new structures and compositions that have the desired separation properties and performance; this is the fundamental connection.

There are two basic focal points for this interactive design of new MSAs for CO2 capture: capacity (or productivity) and selectivity (or specificity). Capacity is directly related to process equipment size.

Higher capacity normally translates to a smaller process footprint and related capital and operating costs. Selectivity corresponds to the separation efficiency. For CO2 capture, this is important for the subsequent sequestration steps.

The design of new materials is the key scientific theme underlying our research. The creative design and synthesis of new materials with tailored properties will enable advances in performance in targeted applications to be made. The focus is on ‘‘tunable’’ materials, i.e., room-temperature ionic liquids (RTILs)) and polymers and composites based RTILs. GAME-CHANGING WITH RESPECT TO CURRENT TECHNOLOGY Capturing CO2 from mixed-gas feed streams is a first and critical step in carbon sequestration. The effectiveness and efficiency of current technologies for separating CO2 is limited. Amine absorption is the current DOE and industry benchmark technology for CO2 capture from power plant flue gas.

Estimates are that using an amine system to capture 90% of the CO2 from flue gas will require approximately 22–30% of the produced plant power [1–3]. This parasitic load corresponds to a CO2 capture cost of $40–100/ton of CO2 and an increase in the cost of electricity (COE) of 50–90% [1–3]. These values are well above the 2020 DOE NETL Sequestration Program post-combustion capture goal of 90% capture with less than a 35% increase in COE [4].

Using membranes (Fig. 1), a permeance of 10,000 GPU translates to a CO2 capture cost of $10/ton of CO2 . Assuming a minimum reduction factor of 4, this translates to 6–7% usage of the produced plant power. A 500 MW power plant will cost ⇠$1 billion. Using the same permeance value, this power plant will need 75,000 m2 of membrane. At a projected cost of $50/m2 (commercial RO membranes), the installed cost is $3.75 million. Even with the addition of $50 million for compressors, the total membrane cost is less than 10% of the power plant cost.

In contrast to amine scrubbers, polymer-based membrane separations are less energy intensive, requiring no phase change in the process, and typically provide low-maintenance operations.

Commercially available membranes for CO2 separation from air have low CO2 permeance characteristics, ⇠100 GPU (1 GPU = 10 6 cm3 cm 2 s 1 cmHg 1 ). The membrane area required for a given application usually scales linearly with the permeance for a given gas flux through the membrane. A ten-fold increase in permeance equates to a ten-fold decrease in membrane area required to achieve the same productivity. Reduced membrane area requirements also translate into smaller membrane footprint requirements and correspondingly better system economics.

Membrane permeability, typically defined in barrer (1 barrer = 10 10 cm3 (STP) cm/(cm2 s cmHg)), is a material property measure that is a function of both the diffusive and solubility-driven transport of a gas through that material. Permeance, i.e., the pressure-normalized flux thru a membrane, is in simple terms, the transport of a gas through that material taking the thickness of the membrane into account. For example, a 0.1-µm thick membrane with a permeability of 1000 barrer would have a permeance of 10,000 GPU. Thus, a combination of a thin film selective layer and very high permeability membrane materials is necessary to achieve 10,000 GPU permeance and

Page 3 of 7 Noble & Gin, Sustainable Technologies, Systems and Policies 2012.CCS.15

50

Capture cost ($/ton CO2)

40

Base case membrane

CO2 permeance 1,000 gpu

30

2,000 gpu 20 4,000 gpu 10 90% CO2 capture Pressure ratio = 5.5 0

0

20

40 60 80 Membrane CO2/N2 selectivity

100

Figure 1. Effect of membrane CO2 permeance and CO2 /N2 selectivity on the cost of capturing 90% of the CO2 from flue gas at a fixed pressure ratio of 5.5 [7].

correspondingly, unprecedented potential for achieving carbon capture costs of $10/ton CO2 (see Fig. 1). It has been demonstrated experimentally that it is possible to obtain a facilitation effect (increase in CO2 permeance) of ⇠5 at a CO2 pressure of 0.15 atm. This equates to a CO2 permeance of ⇠50,000 GPUs with a CO2 /N2 selectivity of >100.

Recently published systems analysis and feasibility studies demonstrate that membranes are a technically and economically viable option for CO2 capture from flue gas exhaust in coal-fired power plants [5]. Merkel et al. have shown that the optimal membrane selectivity for separation of CO2 from flue gas is in the range of 20 to 40 and that increasing membrane permeance is the critical factor in reducing capture costs [6]. They show that for a given process scheme, a system comprised of a membrane with a selectivity in the aforementioned range and CO2 permeance of 1000 GPU results in a cost per ton of CO2 captured of ⇠$32 (Fig. 1). A 4-fold increase in CO2 permeance to 4000 GPU decreases this cost by nearly 50% to ⇠$16. In their analysis, Merkel et al. [7] assumed a membrane skid cost of $50/m2 (including membrane modules, housings, frame, valves and piping) and include the cost of compression. While the reduction of separation cost versus gas permeance is nonlinear, extrapolating these COE data to a permeance of 10,000 GPU, the minimal target of this proposed effort, would result in a cost per ton of CO2 captured of less than $10. This is a significant reduction compared to both the benchmark amine technology and the current membranes under development for this application. As a basis of comparison, commercially available polymer membranes for this application typically have a permeance of 100 GPUs and a CO2 /N2 selectivity of approximately 30.

The data presented in Fig. 1 can be used to estimate the increase in Cost of Electricity (COE) with the installation of carbon capture. Assuming an electricity cost of $0.425/kWh, the permeance values can be extrapolated to 10,000 GPU. Figure 2 illustrates that achievement of this permenace would result in an increase in COE of approximately 15%, well below the 2020 DOE target of 35%.

DESCRIPTION OF ROOM TEMPERATURE IONIC LIQUIDS (RTILS) RTILs are salts that exist in the molten state at or below ambient temperature. Typically, an RTIL is a neat liquid composed solely of a bulky organic cation and a smaller organic or inorganic anion, without any added molecular co-solvent. Most RTILs have delocalized charge across the anion and/or the cation [8]. In addition, RTILs have a unique combination of physiochemical properties, such as negligible vapor pressure, high thermal stability, low flammability, high ionic conductivity, and intrinsic solubility for certain gases, all of which make them unusual in terms of organic liquids and solvents [8]. Because of this combination of properties, RTILs have attracted a great deal of interest as new liquid materials for a number of important chemical and engineering applications.

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50

40

35 30

35 30

25

25

20

20

15

15

10

10

5

5 0

Increase in COE, %

Cost of Capture, $/ton CO2

40

Cost of Capture - Merkel et. al.

Cost of Capture - Extrapolated Increase in COE - Estimated

45

0

2000

4000 6000 8000 Membrane Permeance, GPU

10000

0 12000

Figure 2. Estimated COE increase based on increases in membrane permeance to 10,000 GPU. Solid line is power law fit to the calculated cost of capture taken from Merkel et al. [7]. The dotted line represents extrapolated cost of capture.

The most common classes of RTILs contain imidazolium, ammonium, phosphonium, and pyridinium cations [8]. Imidazolium-based RTILs (Fig. 3) are the most ubiquitous because they are the most modular in terms of chemical synthesis. Using imidazole as a starting material, two different groups can be attached to the imidazole ring via nucleophilic substitution reactions using the two ring N atoms, which can be easily differentiated in terms of their reaction order (Fig. 3). In addition, the type and chemical nature of the anion can be easily changed via anion exchange to incorporate additional properties or to introduce other functional groups. This broad synthetic versatility allows the physical and chemical properties of imidazolium-based RTILs to be readily tuned via inclusion of specific functional groups on the cation unit, or by the judicious choice of the anion. In addition, solid and semi-solid materials based on RTILs can also be prepared by polymerizing reactive RTILs into ionic polymers (i.e., poly(RTIL)s) [9–11], gelling RTILs with small molecule gelator additives to form soft solids [12], or combining different poly(RTIL) (solid) and RTIL (liquid) components to form soft composites [13]. These materials retain many of the desired properties of the parent RTILs, and are important for materials or device applications requiring more mechanical robustness.

N

N

1) NaH H 2) R-X

N

N R

R'-X

R' N

N R

M Y M X s

X Imidazole

N R

R' N Y

Imidazolium (Anion Exchange) RTIL

Figure 3. Transformation of imidazole to a functionalized RTIL.

The design and synthesis of several new types of imidazolium-based RTILs, poly(RTIL)s, and RTIL-based composite materials from our research groups for use in the area of targeted CO2 separations from N2 incorporates a fundamental materials advance. It is extremely desirable to have new membrane and sorbent materials that provide better selective transport or capture.

Materials based on imidazolium-based RTILs represent a promising new separations platform for achieving these goals because of their unique properties and their chemical and morphological modularity.

These gas separation areas and the design of better materials to accomplish them are related by the fact that they involve the differential transport of gaseous substrates through a dense material. In dense solid membranes (e.g., polymers), gas separation is typically afforded by differences in the thermodynamic solubility (S) of each gas in the polymer and/or differences in diffusivity (D) of each gas through the membrane material [14]. In this solution–diffusion (S–D) mechanism, the permeability (P = S · D) is the pressure gradient-normalized flux of each gas through the membrane material, and gauges how easily each gas moves through a dense material to separate it from other

Page 5 of 7 Noble & Gin, Sustainable Technologies, Systems and Policies 2012.CCS.15

gases in the same mixture. In order to achieve good separation of two gas components (a and b), membrane materials must be designed that either have a much higher S value for one gas over the other, and/or a much higher D value for one gas over the other. This gives a large permselectivity factor [ a´ = (Pa /Pb ) = (Sa /Sb ) · (Da /Db )] for the separation process.

Unfortunately, there is typically a trade-off between high gas flux and high separation selectivity for dense polymeric membranes. Polymeric membranes usually separate by diffusion differences. As the permeability increases, the diffusion difference decreases, which reduces selectivity. Even though it is possible to design membrane materials with good solubility selectivity for certain gases, it is also important to have high overall diffusivity through them or the productivity (i.e., through-put) of the entire process will be too low to be useful [14]. A fundamental difference with the use of RTILs as membrane materials is that they separate based on solubility selectivity. Thus, a composite consisting of an RTIL incorporated into an RTIL polymer will increase the permeability due to the liquid within the polymer but the selectivity remains relatively constant since the chemical structure of both components can be the same.

NEW FUNCTIONALIZED RTILS FOR CO2 SEPARATIONS Previous research has demonstrated the viability of simple, alkylimidazolium-based RTILs as CO2 -selective solvents for light gas separations (e.g., CO2 /N2 , CO2 /CH4 , and CO2 /H2 ) [15]. Since this initial work, there has been a considerable interest in functionalizing these ‘‘tailorable’’ RTIL solvents to improve CO2 solubility and/or solubility selectivity. The effect of polar and fluorinated substituents in place of simple alkyl units on the imidazolium ring was investigated by our research group with this goal in mind [16–19], and results indicate that alkylnitrile-, oligo(ethylene glycol)-, and fluoroalkyl-substituted imidazolium RTILs exhibit significantly better CO2 solubility selectivity than analogous alkyl-functionalized imidazolium RTILs [16–19]. The structures of some of these functionalized and non-functionalized RTILs synthesized by our groups are shown in Fig. 4.

N

N NTf2

n = 1, 3, 5

n

N

N

N

N

m

NTf2

N

O

NTf2

m = 1, 3, 5

N

N p

CF2

NTf2

p = 1, 2, 3

CF3 q

q = 1, 3

Figure 4. Representative functionalized and non-functionalized RTILs.

POLY(RTIL)S AND COMPOSITE MEMBRANES FOR CO2 SEPARATIONS Poly(RTIL)s are dense, cationic polymer films that are solid-state analogues of the functional RTILs. Several examples of monomers synthesized by our groups that can be polymerized into poly(RTIL)s are presented in Fig. 5. The introduction of a polymerizable group on the imidazolium ring allows for (photo-initiated) radical chain-addition polymerization of the RTIL monomer, affording a straightforward method to produce ‘‘solid’’ RTIL membranes. Various novel poly(RTIL) monomers have been designed and synthesized based on promising (i.e., CO2 -selective), non-polymerizable RTIL analogues. For example, oligo(ethylene glycol)- and nitrile-functionalized poly(RTIL)s were found to have enhanced CO2 permeability selectivity compared to analogous alkyl-functionalized

N

N

N

n

NTf2 n = 1, 3, 5

N

N

O

NTf2

p

p = 1, 2, 3

N NTf2

m = 1, 3, 5

N m

N

N NTf2

CF2

CF3 q

q = 1, 3

Figure 5. Examples of monomers synthesized by our group that can be polymerized into poly(RTIL)s.

Page 6 of 7 Noble & Gin, Sustainable Technologies, Systems and Policies 2012.CCS.15

poly(RTIL)s [20]. These poly(RTIL)s present all of their CO2 -selective functional groups as pendant side groups on the polymer chains.

Separately, main-chain cationic polymers based on RTIL moieties have also been developed and investigated in our group [21]. An example of a main-chain poly(imidazolium) that has been synthesized is shown in Fig. 6. Unlike the previous poly(RTIL)s discussed, all of the CO2 -selective functionality is located in the main polymer backbone (instead of within the side groups), and thus, offers a fundamentally different polymer architecture compared to the previous photo-polymerizable poly(RTIL)s. In many cases, the side-chain poly(RTIL) or main-chain poly(imidazolium) membranes performed comparably or better than the liquid-state, functionalized RTIL analogues in terms of CO2 selectivity performance. However, these dense, solid-state polymer films have inherently lower CO2 diffusivity and cannot attain the large CO2 fluxes obtainable with Supported Ionic Liquid Membranes (SILMs), where the active membrane material is a liquid.

N

N n

NTf2

Figure 6. Example of a main-chain poly(imidazolium) that has been synthesized by the Noble and Gin groups.

Poly(RTIL): 80 mole %

RTIL: 20 mole %

n

N N

N

O

NTf2

NTf2

N n

N

N

N NTf2

N NTf2

Figure 7. Examples of composite RTIL-based membranes containing liquid and solid components.

Poly(RTIL)-RTIL solid–liquid composite films produced and tested by our group have consistently exhibited enhanced overall permeability compared to the neat, ‘‘parent’’ solid poly(RTIL) films [13,21]. Several examples of these composite RTIL-based membrane mixtures are shown in Fig. 7.

The non-volatility of the RTIL component and its compatibility with the poly(RTIL) matrix are two major advantages to this approach. The RTIL will not evaporate from these solid–liquid composite

(b) 100 P(CO2)/P(CH4)

P(CO2)/P(N2)

(a) 100

10

1

10

100 1000 P(CO2) (barrer)

10000

10

1

10

100 P(CO2) (barrer)

1000

Figure 8. Comparative CO2 separation performance of several poly(RTIL)s, poly(RTIL)-RTIL composites, and SILMs represented by ‘‘Robeson Plots.’’ Left: CO2 vs N2; Right: CO2 vs CH4.

Some additional references have been added to provide more details for the reader [22–27].

Page 7 of 7 Noble & Gin, Sustainable Technologies, Systems and Policies 2012.CCS.15

films, and no evidence of the RTIL ‘‘bursting’’ from of the membrane under applied gas pressure has been observed, which is a significant limitation with SILMs. The most important consequence of blending a free liquid RTIL into an solid poly(RTIL) matrix is that there is little, if no, sacrifice in CO2 permeability selectivity [13,21]. The incorporation of varying amounts of the RTIL component (i.e., from 10 to 75 wt % RTIL) was investigated, and compositions afforded stable, supported membranes. Not surprisingly, it was observed that as the RTIL loading of the membrane increases, the separation performance of the solid–liquid composite approaches that of the analogous liquid-based membrane and deviates further from the parent solid poly(RTIL). Figure 8 shows the comparative CO2 separation performance of several poly(RTIL)s, poly(RTIL)-RTIL composites, and SILMs as summarized in ‘‘Robeson Plots’’.

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[17] Carlisle T.K., Bara J.E., Gabriel C.J., Noble R.D. and Gin D.L. Interpretation of CO2 solubility and selectivity in nitrile-functionalized room-temperature ionic liquids using a group contribution approach. Ind. Eng. Chem. Res. 2008;47:7005.

[18] Bara J.E., Gabriel C.J., Carlisle T.K., Camper D.E., Finotello A., Gin D.L. and Noble R.D. Gas separations in fluoroalkyl-functionalized room-temperature ionic liquids using supported liquid membranes. Chem. Eng. J. 2009;147:43.

[19] Muldoon M.J., Aki S.N.V.K., Anderson J.L., Dixon J.K. and Brennecke JF. Improving carbon dioxide solubility in ionic liquids. J. Phys. Chem. B. 2007;111:9001.

[20] Bara J.E., Gabriel C.J., Hatakeyama E.S., Carlisle T.K., Lessmann S., Noble R.D. and Gin D.L. Improving CO2 selectivity in polymerized room-temperature ionic liquid gas separation membranes through incorporation of polar substituents. J. Membr. Sci. 2008;321:3.

[21] Carlisle T.K., Bara J.E., Lafrate A.L., Gin D.L. and Noble R.D. Main-chain imidazolium polymer membranes for CO2 separations: An initial study of a new ionic liquid-inspired platform. J. Membr. Sci. 2010;359:37.

[22] Bara J.E., Camper D.E., Gin D.L. and Noble R.D. Room-temperature ionic liquids and composite materials: platform technologies for CO2 capture. Accounts Chem. Res. 2010;43:1, 152.

[23] Hudiono Y.C., Carlisle T.K., Bara J.E., Zhang Y., Gin D.L. and Noble R.D. A three-component mixed-matrix membrane with enhanced CO2 separation properties based on zeolites and ionic liquid materials. J. Membr. Sci. 2010;350:1–2, 117.

[24] Simons K., Niemeijer K., Bara J.E., Noble R.D. and Wessling M. How do polymerized room-temperature ionic liquid membranes plasticize during high pressure CO2 permeation?. J. Membr. Sci. 2010;360:1–2, 202.

[25] Noble R.D. Perspectives on ionic liquids and ionic liquid membranes. J. Membr. Sci. 2011;369:1–2, 1.

[26] Gin D.L. and Noble R.D. Designing next-generation membranes for chemical separations. Science. May 6, 2011;332:674–676.

[27] Bara J.E., Carlisle T.K., Gabriel C.J., Camper D., Finotello A., Gin D.L. and Noble R.D. A guide to CO2 separations in imidazolium-based room-temperature ionic liquids. Ind. Eng. Chem. Res. 2009;48:6, 2739.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Metal-organic frameworks and porous polymer networks for carbon capture Julian Patrick Sculley*, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe Zhou Chemistry Department, Texas A&M University, College Station, TX, USA * Email:

Zhou@chem.tamu.edu

ABSTRACT The ability to rationally design materials for specific applications and synthesize materials to these exact specifications at the molecular level makes it possible to make a huge impact in carbon dioxide capture applications. Recently, advanced porous materials, in particular metal-organic frameworks (MOFs) and porous polymer networks (PPNs) have shown tremendous potential for this and related applications because they have high adsorption selectivities and record breaking gas uptake capacities. By appending chemical functional groups to the surface of these materials it is possible to tune gas molecule specific interactions. The results presented herein are a summary of the fundamentals of synthesizing several MOF and PPN series through applying structure property relationships.

Keywords: porous materials, metal-organic frameworks, carbon dioxide capture, gas separation

http://dx.doi.org/ 10.5339/stsp.2012.ccs.16 Published: 19 December 2012 c 2012 Sculley, Li, Park, Lu, Zhou, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Sculley JP, Li JR, Park J, Lu W, Zhou HCJ. Metal-organic frameworks and porous polymer networks for carbon capture, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:16 http://dx.doi.org/10.5339/stsp.2012.ccs.16

Page 2 of 5 Sculley, Li, Park, Lu, Zhou, Sustainable Technologies, Systems and Policies 2012.CCS.16

INTRODUCTION Carbon capture and sequestration (CCS) is a topic that has received a considerable amount of attention in the last few years because of the importance of reducing anthropogenic carbon dioxide emissions [1–3]. The scientific investigation of porous solid materials has traditionally involved a broad spectrum ranging from chemists to materials scientists to engineers in large part due to the industrial importance of these materials for separations [4]. Over the last three decades there has been resurgence in the chemical arena with the development of metal-organic frameworks (MOF) as advanced porous materials [4–6]. These materials self-assemble from inorganic metal ions or clusters and organic bridging ligands. Due to the modular construction using molecular building blocks, it is possible to design a MOF to have precise structural characteristics and physical properties. Through the power of organic synthesis it is also possible to add functional groups to the organic linker without changing the final framework topology [7].

The current, amine-scrubbing technology survives because it drastically reduces CO2 output from coal fired power plants, but it crushes the economic pillar because of the enormous parasitic power demands imposed during the solution’s regeneration process. MEA solutions (approximately 30 wt% monoethanolamine (MEA) in water) work by chemically bonding CO2 to form carbamates, but to regenerate them, the water solutions must be heated up, which can account for about 30 percent of a power plant’s energy output [8,9]. In order to reduce the energy penalty that coal or natural gas fired power plants incur during the process of scrubbing CO2 from flue gas, new methods and materials must be investigated. Some of the major technical challenges are that flue gas is usually plagued with contaminants (SOx , NOx , and fine particulates), it is hot (typically 40–60 C) and only contains approximately 14–16% CO2 (translates to a partial pressure in the gas stream of about 0.15 bar) [10]. Physisorptive materials such as MOFs work in regions of much lower sorption enthalpies than chemical absorption and can therefore be used to mitigate energy costs because regenerations are energetically favorable. Another aspect of MEA scrubbing is the highly corrosive property of aqueous amine solutions. To deal with this problem specially designed tanks are needed and the solutions must be handled cautiously [10].

METAL-ORGANIC FRAMEWORKS MOP construction As the building units of MOFs, the design and construction of the metal-organic polyhedra (MOPs) is a prerequisite. A great example of the modularity in design is shown in Fig. 1. By choosing a simple secondary building unit such as the dicopper paddlewheel (in the center of the figure), and mixing it in solution with a variety of linkers, numerous MOPs can be synthesized [11]. Each MOP has different physical properties that are related to the bridging linker. Structure property relationships can be established between the functional group and a desired physical property, such as high CO2 uptake at low pressure, which can be used to increase selectivity of CO2 over N2 or CH4 (natural gas purification). The metal cluster can also be replaced with other metals such as molybdenum to generate isostructural MOPs with different physical properties [12]. These polyhedra can be bridged into three dimensional structures, using ditopic moieties such as 4,4’-bipyridine, [13] or by designing ligands which will form polyhedral pores that are covalently linked such as the PCN-6x series developed by us [14,15].

Polyhedra-based frameworks A hierarchical approach can be used to connect these polyhedra into 3D networks, by carefully designing linkers with topologies that will generate polyhedra-based networks (Fig. 2). All of the PCN-6x series MOFs have the same topology with identical cuboctahedral cages, but increasingly larger mesocavities by increasing the ligand length. This leads to increasing BET surface areas of 3350, 4000 and 5109 m2 /g for PCN-61, 66, and 68 respectively. An important trend that is observed for this series is the proportional increase in CO2 uptake capacities at 35 bar, from 23.5 to 26.3 to 30.4 mmol/g. In terms of volumetric uptake this translates to a storage capacity that is between 7.3 and 8.2 times the amount of CO2 stores in an empty container. Similar trends are observed for other gases stored at high pressure for energy applications, primarily H2 and CH4 [15].

Page 3 of 5 Sculley, Li, Park, Lu, Zhou, Sustainable Technologies, Systems and Policies 2012.CCS.16

DEF

DEF

MeOH/DMA

MeOH/DMA MeOH/DEF

MeOH/DMA MeOH/DEF

MeOH MeOH/DEF

DMA

Figure 1. Synthetic scheme of metal-organic polyhedra (MOPs).

(b)

(a)

PCN-61

(c)

PCN-66

PCN-68

(d)

Figure 2. (a) Ligands used in the construction of PCN-6x series; (b) Simplified structure showing the cuboctahedral cages; (c) hierarchical assembly of cages; (d) simplified network topology.

Stimuli-responsive MOFs MOFs can further be modified with pendant functional groups. These functional groups can be attached to the periphery of MOPs (as shown in Fig. 1) or to the interior of channels creating gate type environments as with the mesh-adjustable molecular sieves (MAMS) shown in Fig. 3(a) [16]. The MAMS structure has 1D channels with gated chambers, which are controlled by temperature responsive functional groups. By increasing or decreasing the temperature the pore size is slightly altered, leading to temperature dependent selective gas adsorption. This idea of smart materials can be further extended to include other stimuli responsive materials, where light responsive groups control gate opening. For carbon capture applications, one of the main concerns is to reduce the amount of energy required to capture CO2 . By switching from temperature controlled materials to optically sensitive materials, one can easily imagine simply opening the material up to sunlight to regenerate the sorbent. In the first example of this new class of materials, shining UV light onto the sample reduced the CO2 uptake capacity at 1 bar from 22.9 cm3 /g to 10.5 cm3 /g. Because this process is entirely reversible it can be used to regenerate the material to readsorb more CO2 in purification applications [17].

Page 4 of 5 Sculley, Li, Park, Lu, Zhou, Sustainable Technologies, Systems and Policies 2012.CCS.16

(a)

(b)

Gate

uv Heat

Chamber Channels

0

40 20 0

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CH4 C2H4

143 K

50 40

vads/cm3g–1

vads/cm3g–1

60 50 40 30 20 10 0

C2H4 C3H6

(c)

195 K

30 20 10 0

0.0 0.2 0.4 0.6 0.8 1.0

0.0 0.2 0.4 0.6 0.8 1.0

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P/P0

pristine right after the first UV 5 hrs after the first UV after the first heating

25

P/P0

P/P0

(b)

30

113 K

0.0 0.2 0.4 0.6 0.8 1.0

0.0 0.2 0.4 0.6 0.8 1.0

0.0 0.2 0.4 0.6 0.8 1.0

(a)

N2 CO

CH4

CO2 uptake (cm3/g)

20

60

87 K

O2 N2 CO

vads/cm3g–1

80

231 K

CH

vads/cm3g–1

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77 K

H2 O2 CO N2

vads/cm3g–1

vads/cm3g–1

60

3 6 50 ISO-C4H10 40 30 20 10 0 0.0 0.2 0.4 0.6 0.8 1.0

20 15 10 5 0

0

200

400

600

800

Pressure (mmHg)

P/P0

Figure 3. (a) Schematic illustration of Mesh-adjustable molecular sieves schematic and selective gas adsorption; (b) Optically and thermally responsive MOF and CO2 adsorption showing reversibility.

POROUS POLYMER NETWORKS The benefits of stability lead Zhou’s group to investigate Porous Polymer Networks (PPNs) [18,19].

These hypercrosslinked polymers add additional merits to the adsorbents family due to their low cost, ease of processing, and high thermal and chemical stability. Initial publications showed that these covalently bonded materials were indeed very stable and had similar surface areas and pore volumes (both of primary importance to high pressure gas storage application) compared to MOFs. The silane network (PPN-4) has the highest BET surface area of any material with 6461 m2 /g and a remarkable pore volume of 3.04 cm3 /g. This tremendous porosity is directly related to the amount of gas stored at high pressures (50 bar) of H2 (140 mg/g), CH4 (360 mg/g) and CO2 (2121 mg/g). To increase low pressure CO2 adsorption however, we introduced polar functional groups (SO3 H and SO3 Li) as can be seen in Fig. 4. By raising CO2 specific interactions in these materials, it is possible to tune gas-framework interactions thereby creating highly selective materials. As an example, PPN-6 was synthesized by an optimized Yamamoto homo-coupling reaction [19] using tetrakis(4-bromophenyl)methane and has a BET surface area of 4023 m2 /g. The first attempt at functionalizing a PPN for this targeted application was by stirring it in chlorosulfonic acid (followed by lithium hydroxide), as shown in Fig. 4. Both modified PPNs have exceptionally high CO2 uptake capacities at pressures relevant to flue gas separations. Using the approximate partial pressures of CO2 and N2 in flue gas (0.15 and 0.85 bar respectively) Ideal Adsorption Solution Theory (IAST) selectivities were calculated for each material using experimental pure gas isotherms.

PPN-6-SO3 Li has a selectivity that compares favorably to NaX zeolite at about 150. The higher CO2 adsorption capacity and lower N2 capacity of PPN-6-SO3 H lead to a record high IAST selectivity of 414. Additionally, these materials are thermally stable to above 400 C, can be stirred in boiling water as well as strong acids and bases without losing any of their adsorptive properties. This

PPN-6-SO3Li PPN-6-SO3H PPN-6

14

295 K CO2 uptake (wt%)

(b)

(a)

12

Br

10

C

Br

Ni(COD)2

PPN-6

CISO3H

RO3S

Br Br LiOH

PPN-6-xSO3H (R = H) PPN-6-xSO3Li (R = Li)

8 6 4

N2

2 0 0.0

0.2

0.4

0.6

0.8

1.0

1.2

P (bar)

Figure 4. Synthesis and postsynthetic modification of PPN-6 and gas adsorption properties showing highly selective adsorption of CO2 over N2 .

Page 5 of 5 Sculley, Li, Park, Lu, Zhou, Sustainable Technologies, Systems and Policies 2012.CCS.16

stability is important for real industrial applications to ensure that the material will not degrade under the conditions it is exposed to and be useful over a long period of time [20].

CONCLUSIONS Porous materials such as MOFs and PPNs can have a tremendous impact in carbon dioxide capture technologies because we can rationally design smarter materials to achieve the properties necessary while lowering the overall energy consumption. We have demonstrated that these materials can achieve record-breaking selectivities and storage capacities. Additionally new, stimuli responsive materials will significantly reduce energy consumption during the regeneration step.

REFERENCES [1] [2] [3] [4] [5] [6]

[7] [8] [9] [10] [11] [12] [13] [14] [15] [16] [17] [18] [19] [20]

Pradier J.P.C.-M. ed., Carbon Dioxide Chemistry: Environmental Issues. The Royal Society of Chemistry. 1994.

Wang Q., Luo J., Zhong Z. and Borgna A. Energy & Environmental Science. 2011;4:42–55.

Chu S. Science. 2009;325:1599.

Li J.R., Sculley J. and Zhou H.C. Chem. Rev. 2012;112:869–932.

D’Alessandro D.M., Smit B. and Long J.R. Angewandte Chemie International Edition. 2010;49:6058–6082.

Li J.-R., Ma Y.-G., McCarthy M.C., Sculley J., Yu J.-M., Jeong H.-K., Balbuena P.B. and Zhou H.-C. Coord. Chem. Rev. 2011;255:1791–1823.

Zhao D., Timmons D.J., Yuan D. and Zhou H.-C. Accounts Chem. Res. 2010;44:123–133.

Rochelle G.T. Science. 2009;325:1652–1654.

Ciferno J.P., Fout T.E., Jones A.P. and Murphy J.T. Chem. Eng. Progress. 2009;105:33–41.

Ciferno J.P., Marano J.J. and Munson R.K. Chem. Eng. Progress. 2011;107:34–44.

Li J.R. and Zhou H.C. Nature Chem. 2010;2:893–898.

Li J.R., Yakovenko A.A., Lu W.G., Timmons D.J., Zhuang W.J., Yuan D.Q. and Zhou H.C. J. Am. Chem. Soc. 2010;132:17599–17610.

Li J.R., Timmons D.J. and Zhou H.C. J. Am. Chem. Soc. 2009;131:6368–6369.

Zhao D., Yuan D., Sun D. and Zhou H.-C. J. Am. Chem. Soc. 2009;131:9186–9188.

Yuan D., Zhao D., Sun D. and Zhou H.-C. Angewandte Chemie International Edition. 2010;49:5357–5361.

Ma S.Q., Sun D.F., Yuan D.Q., Wang X.S. and Zhou H.C. J. Am. Chem. Soc. 2009;131:6445–6451.

Park J., Yuan D., Pham K.T., Li J.-R., Yakovenko A. and Zhou H.-C. J. Am. Chem. Soc. 2011;134:99–102.

Lu W., Yuan D., Zhao D., Schilling C.I., Plietzsch O., Muller T., Bräse S., Guenther J., Blümel J., Krishna R., Li Z. and Zhou H.-C. Chem. Mater. 2010;22:5964–5972.

Yuan D., Lu W., Zhao D. and Zhou H.-C. Adv. Mater. 2011;23:3723–3725.

Lu W., Yuan D., Sculley J., Zhao D., Krishna R. and Zhou H.C. J. Am. Chem. Soc. 2011;133:18126–18129.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

CCS from industrial sources Paul S. Fennell1, *, Nick Florin1 , Tamaryn Napp2 , Thomas Hills1,2 1 Department

of Chemical Engineering, Imperial College, London, SW7 2AZ 2 Grantham Institute for Climate Change,

Imperial College London, SW7 2AZ * Email:

p.fennell@imperial.ac.uk

ABSTRACT The literature concerning the application of CCS to industry is reviewed. Costs are presented for different sectors including ‘‘high purity’’ (processes which inherently produce a high concentration of CO2 ), cement, iron and steel, refinery and biomass. The application of CCS to industry is a field which has had much less attention than its application to the electricity production sector. Costs range from less than $2011 10/tCO2 up to above $2011 100/tCO2 . In the words of a synthesis report from the United Nations Industrial Development Organisation (UNIDO) ‘‘This area has so far not been the focus of discussions and therefore much attention needs to be paid to the application of CCS to industrial sources if the full potential of CCS is to be unlocked’’.

Keywords: CCS, industry, cement, iron, steel

http://dx.doi.org/ 10.5339/stsp.2012.ccs.17 Published: 18 December 2012 c 2012 Fennell, Florin, Napp, Hills, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Fennell PS, Florin N, Napp T, Hills T. CCS from industrial sources, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:17 http://dx.doi.org/10.5339/stsp.2012.ccs.17

Page 2 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

INTRODUCTION Carbon capture and storage (CCS) is frequently associated with coal-fired electricity generation, and to an increasing extent with gas-fired generation. However, there are many other sources of CO2 which can also benefit from the technology and many of these are substantially easier to retrofit with CCS than are power stations. Due to rising energy costs, many energy intensive industrial processes have made significant advancements in energy efficiency over the past 40 years and are now operating close to their thermodynamic limits. The options for further reduction are highly limited. Furthermore, for process-related emissions (those inherent to the process itself, such as the emission of CO2 during the calcination of limestone for lime or cement manufacture) there is little choice other than to apply CCS if the industry is to be substantially decarbonized. In light of this, it is surprising that the power industry, where technologies such as wind, tidal and hydropower offer serious alternatives to the application of CCS (through clearly there are issues with intermittent generation) has dominated the research and development agenda.

A synthesis report for the United Nations Industrial Development Organisation (UNIDO) [1] states that ‘‘This area has so far not been the focus of discussions and therefore much attention needs to be paid to the application of CCS to industrial sources if the full potential of CCS is to be unlocked’’. In this paper, the major classes of industrial CO2 -emitting processes are discussed, the most suitable types of carbon capture equipment for each of them, and the likely costs of implementing the technology. One thing which is immediately apparent is that there is a very much reduced set of literature pertaining to industrial emissions when compared with the large and growing literature on the application of CCS to power stations. Much of the literature refers back to a small number of IEA studies [2,3], there is much less independent validation of costs by different researchers. This is most likely owing to the breadth of different processes in the industrial CCS arena, and the proprietary nature of many of the processes leading to a paucity of freely-available knowledge.

The extent of future reductions in CO2 emission attributable to CCS in the industrial sector could be very large. The IEA blue map scenario [4] attributes 19% of total global CO2 emission reductions vs the ‘‘business as usual’’ scenario to CCS, and this is roughly split 55:45 between power generation and industrial emissions applications. The share of total direct (i.e. excluding process emissions and indirect emissions from electricity production) industrial emissions of CO2 from the major CO2 -emitting sectors is shown in Fig. 1.

UNIDO classifies [4] the industrial sector into five different sub-sectors; ‘‘high purity’’ (natural gas processing and the production of hydrogen, ethylene oxide or ammonia); cement; iron and steel; refinery; and ‘‘biomass’’, and we will use the same classifications here. It is important to note that the partial pressures of CO2 in the exhausts of different industrial processes vary greatly (see Fig. 2), with

Total direct CO2 emissions from industry in 2007 was 7.6 Gt, globally

Chemicals and petrochemicals 17% Pulp and paper 2%

Iron and steel 30% Cement 26% other 23%

Aluminium 2% Figure 1. Share of direct industrial CO2 emissions attributable to the major industrial sectors [5]. Adapted from [6].

Page 3 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

Figure 2. Partial pressures of CO2 from a variety of industrial and power generation sectors. After [13].

consequent effects on the cost of separation and compression (CO2 will in general be injected at a pressure of 100 bar or more [7]).

The costs of separating CO2 from the other gases in a power plant exhaust vary depending on the partial pressure of the CO2 , the technology chosen and a number of other factors. However, for reference, the estimated costs of CCS range between around $29–$107 for CO2 capture from coal or natural gas-fired power stations [4,8–10]. Some care is necessary though, given the recent significant increases in capital cost indices. The costs of separation currently outweigh the costs of transport and storage, with transport costs estimated at 0–$16/t, depending upon the distance transported, with storage costs at $2–3/tCO2 [11]. All costs in this paper are expressed in 2011 USD and escalated using the Power Capital Costs Index (PCCI) where appropriate [12]. A word of caution is necessary at this stage—academic estimates of costs are generally a little lower than industrial estimates, so care is necessary in comparing them.

The size of the plant also has an impact on cost. A single large blast furnace (Annual steel production of around 3 Mt) typically emits about 3.5 Mt of CO2 per year. A large steel plant can often consist of up to five large blast furnaces on one site, emitting a total of 17.5 Mt CO2 per year and making it one of the largest stationary sources of CO2 emissions in the world. Table 1 compares the size of a variety of stationary point sources of emissions.

Table 1. Comparison of the size and quantity of a variety of point sources of CO2 emissions (Adapted from [8]).

Source

Power station flue and fuel gas - Natural gas fired boilers - Gas turbines - Coal fired boilers Chemical and petrochemical - Refineries - Ammonia - Ethylene oxide Iron and steel Cement

Average emissions/source

No. of sources in 2005

1.01 0.77 3.94

743 985 2025

1.25 0.58 0.15 3.5 0.79

638 194 17 180 1175

In the power generation sector, CO2 capture processes can be classified into three different schemes: 1) pre-combustion capture, 2) post-combustion capture and 3) oxy-firing. Owing to the heterogeneity of industrial processes, capture from industrial sources is more complex; however some similarities can be drawn. The different capture processes from industrial sources are discussed in more detail in the next section.

Page 4 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

SECTORAL ASSESSMENTS High purity This is a classification based on the output concentration of CO2 from the process (30–100%), rather than a particular industrial sector. There are a number of processes which currently separate CO2 from process streams for the purposes of product quality or because a required reaction produces CO2 as an outlet gas. This sector includes natural gas processing. Clearly, the opportunities for CCS are significant in this sector, because the most difficult job of separating the CO2 from the remaining streams has already been accomplished. Unfortunately, the emissions of high purity CO2 are relatively small, at [1] only 426 Mt/yr, only 6% of the total industrial emissions. However, the opportunities for demonstration of the technology are large, with a number of significant projects already up and running, as discussed below. The industry is well developed, with solvent-based CO2 capture already utilized to improve natural gas quality.

Costs in this area are generally low, essentially being those associated with removal of minor contaminants, compression and storage alone [1], leading to a price per tonne of CO2 of between $9 for retrofit to an existing LNG plant, $15–8 for an onshore natural gas plant, $17–20 for an offshore natural gas plant in shallow waters and rising to $29 for a deep water installation [1]. Early work in this area [14] suggested a mitigation cost of $30/tCO2 for fertilizer production and $34/tCO2 for ethylene oxide production (note that these costs were estimated in 1990, so that the capital cost escalation factor and hence the potential error caused is large).

Cement Cement manufacture contributes over 5% of global CO2 emissions [15], and with the total demand for cement expected to double by 2050 [16] it will continue to be a large source of CO2 for many years. There are two major sources of CO2 in the cement production process—from the calcination of limestone (CaCO3 ) to form CaO (around 60% of the total emissions, excluding the fuel used to effect the calcination [17]), the major constituent of ordinary Portland cement, and from the fuel used to raise the temperature in the cement kiln and to effect the calcination (approximately 40% of the total emissions) to effect the chemical reactions necessary to produce cement [18]. These figures agree with recent ones presented by Cemex [19], the world’s third largest cement manufacturer.

Interestingly, Bosoaga et al. [20] present a different split of CO2 emissions (50% for calcination including fuel use in the calciner, 40% for fuel combustion in the kiln, 5% for electricity use and 5% from transportation). Whilst the fuel used can and is frequently biogenic waste-derived material (at least in part), the calcination produces CO2 which cannot be decarbonized in any other way than CCS. To date, most of the research on CCS applied to the cement industry has been theoretical modeling and costing of potential processes. The European Cement Research Academy (ECRA) began research on the application of CCS technology to the cement industry in 2007 and recently begun Phase III (laboratory scale and small research activities) of its five-phase project timeline [21]. One pilot study currently in the pipeline is based at a NORCEM cement plant in Brevik, Norway. A post-combustion capture unit will be retrofitted to an existing cement kiln and is intended to start operation by 2018, capturing around 10 kt of CO2 per year. The estimated cost of this project was 1.7 million Euros [22] in 2010.

Post-combustion capture of CO2 from the cement industry uses the same capture technologies as those in the power sector (e.g. MEA scrubbing) and has the advantage that it can easily be applied as retrofit to existing plants at low technical risk [23]. However, unlike power plants, cement plants have limited low-grade waste heat available for solvent regeneration (typically only up to 30% of the total heat required for regeneration can be supplied by waste heat [24]. Thus, additional steam has to be generated or imported from elsewhere, increasing the cost of capture significantly.

Oxy-firing, where the kiln is heated by burning the fuel in oxygen diluted with recycled CO2 , has been shown to be a more cost effective option than post-combustion capture [23]. Oxygen enrichment, where the kiln air is supplemented by short bursts of pure oxygen, has already been applied in the cement industry. Oxygen enrichment has the advantage of creating high value energy through increased kiln temperatures, which increases the kiln capacity. With each percentage point increase in the oxygen concentration, the fuel consumption decreases by 1.4–1.9 kJ/kg clinker [25].

Although, oxy-firing with CO2 capture can be retrofitted to existing plants, it is more suitable for new builds since most of the core units have to be rebuilt. Current research is focused on overcoming three

Page 5 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

major challenges: 1) the effect of a high CO2 concentration on the calcination reaction, 2) limiting damage to the kiln refractory at higher temperatures and 3) prevention of air intake into the kiln.

Pre-combustion capture in the cement industry is generally not considered suitable for the cement industry since CO2 emissions arising from limestone calcination, representing around 50% of the CO2 emissions, would remain uncaptured.

Figure 3 shows the application of another promising technology, the calcium looping cycle [26], to decarbonize a cement plant. The flue gas from the cement plant is passed to a reactor (⇠650 C, the ‘‘carbonator’’) where CO2 from flue gas is reacted in an exothermic reaction with CaO at high temperature to form CaCO3 , which is then regenerated at ⇠950 C (in a ‘‘calciner’’), with the cycle then repeated. A significant purge flow of CaO is necessary to maintain the average sorbent reactivity, but one key aspect of the technology is that this flow can simply be purged into the cement kiln [17].

In addition (and contrary to most other CO2 capture schemes) the energy given out in the exothermic CO2 capture reaction can be profitably used, because of its high temperature, to produce electricity.

Though the technology can be applied to power generation [27], it is a natural fit with cement manufacture because of the integration of the waste products from the cycle with the raw materials for cement manufacture.

flue without CO2 CaO purge + fresh limestone

limestone

CaO purge CO2

coal, air

Cement plant

carbonator flue

CaCO3 calciner

N2

CaO

ASU O2 coal

air

Figure 3. The application of the Ca looping cycle on a cement plant.

However, there is a powerful synergy between electricity production and cement manufacture, in that the cycle can be used to decarbonize a power station, with a purge removed in the form of CaO, which eliminates the requirement to calcine CaCO3 in the cement process. This removes a very substantial fraction of the hard to eliminate process-related emissions and eliminates the requirement for a precalciner for the cement works. Of course, it is also possible to remove the emissions via a standard post-combustion scrubbing route, such as MEA scrubbing. However, the estimated cost of decarbonisation is significantly higher (see below).

One significant area of research is into the fate of trace elements and minor species in cement manufacture when CCS is applied, most particularly in processes which make significant changes to the clinker production process. In the words of Bhatty (Portland cement research association) [28] ‘‘The likely concerns from alternative or new natural sources [of raw materials required for cement production] are the incorporation of trace elements into clinker and their effects on the performance of cement.’’ The cement industry is by nature cautious, which is understandable given the consequences if the cement does not perform to the required standard. Current research at Imperial College [29] is investigating the likely build-up of trace elements during repeated cycles of calcination and carbonation for CO2 capture from cement Fig. 4 demonstrates the steps undertaken during the testing of cement produced from spent sorbent at a laboratory scale.

So far, there have been no significant effects on the cement quality noted by pre-using the CaO to capture CO2 [29]; in fact (and as expected), the ratio of alite to belite in the cement (a crude measure of the cement quality) formed improved with increasing cycles of calcination and carbonation: see Fig. 5, which compares the alite/belite ratio for cases with and without the addition of coal to effect the calcination reaction.

Large pilot-scale demonstrations of the Ca-looping process are underway at two locations (both for power-related applications), the University of Darmstadt (Germany), at a scale of 1 MWth [30] and at

Page 6 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

PRODUCTION OF CYCLED SORBENT

PRODUCTION OF CLINKER

TRACE ELEMENT ANALYSIS OF SORBENT

XRD ANALYSIS OF CLINKER

Figure 4. Stages in the testing of cements produced using spent sorbent from the Ca looping process.

100 90 80

No Fuel

2g / cycle

% Alite

70 60 50 40 30 20 10 0

1

5

10

15

No. Cycles Figure 5. Wt.% alite determined by XRD using the ‘Relative Intensity Ratio’ (RIR) method (Snyder & Bish, Modern Powder Diffraction 1989) (average based on 3 repeats); alite in commercial cement about 50–70%. After [29].

La Pereda (Spain) at the scale of 1.7 MWth [31]. As of March 2012, both are operating as expected.

Cemex also have a pilot-scale carbonator at Monterray, Mexico [32].

The cost for decarbonisation of cement manufacture has been estimated for calcium looping as ⇠$20/tCO2 [18], and for general post-combustion capture using this process of $15–20/tCO2 [26].

Kuramochi et al. [23] quote costs (per tCO2 ) for a variety of short/medium term processes of between $35 for Ca looping precalcination (based on [18]) to $47–67 for advanced solvents (the lower figure is for steam import from a power station, the higher figure for boiler steam import), around $56 for oxyfuel operation and $85–117 for MEA-based scrubbing (again, the lower figure is for power station steam and the higher for boiler steam). The IEA GHG programme [33] has assessed the costs of an oxyfired cement kiln in the UK, and estimated a cost of $54 for decarbonisation of the calciner only, or $29 for an Asian developing country. This was in contrast to their assessment of $138 for post combustion capture using MEA for the entire plant in the UK, or $93 for a developing country.

Iron and steel The manufacture of iron and steel is another sector where the use of carbonaceous fuels is currently intrinsic to the process, leading to significant difficulties in decarbonisation through routes other than CCS. The current primary manufacturing route involves the heating of coke, pulverized coal, bulk iron ore and sinter in a blast furnace, with oxygen injected to produce both high temperatures (1500 C) and a highly reducing environment through partial combustion of the coke. The raw materials pass down the furnace and contact countercurrently with hot reducing gases produced by the combustion

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of the coke (and potentially a small amount of coal), and (potentially O2 -enriched) air. The requirement for coke (which supports the ore as it passes down the furnace and prevents collapse of the bed) is one of the main drawbacks of the blast furnace, since the production of coke is costly in both environmental and monetary terms, and the substitution of coke with coal is a subject of significant research [34]. Research in the area of CCS from iron and steel production is being carried out by the Ultra-Low CO2 Steel (ULCOS) programme [35]; a consortium of 48 EU companies and organisations from 15 EU countries. The programme began in 2004 and has since focused on research and small pilot demonstrations of a number of alternative iron and steel production processes, which enable the capture of CO2 and its subsequent storage. Following good progress, the program now aims to demonstrate the processes on a larger scale.

The gas produced from the blast furnace consists of CO (17–25%) and CO2 (20–28%), H2 (1–5%), N2 (50–55%) [23]. Post-combustion capture using chemical sorbents, such as those proposed in the power sector, could be used to capture CO2 from the blast furnace exit gas stream, however much of the carbon then remains uncaptured in the form of CO. Through reforming and the water–gas shift reaction, the CO2 concentration can be increased to 60% CO2 [3], making physical solvents such as Selexol, which has been developed for IGCC pre-combustion capture, technically and economically feasible.

The TGR process proposed by ULCOS eliminates the N2 content by injecting the blast furnace with oxygen rather than air. The gas exiting the top of the blast furnace consists of concentrated CO2 , which can be separated from the other gases using Vacuum Pressure Swing Adsorption (VPSA) or Pressure Swing Adsorption (PSA) together with cryogenics separation to remove final impurities. The CO2 is transported to underground storage, and the separated CO and H2 are recycled and injected at the bottom of the blast furnace, where they act as reducing agents. This has the additional benefit of decreasing the amount of coke required as a reducing agent.

An alternative (or possible supplement [36]) is the COREX process. The key feature of this process is that iron ore melting is separated from iron ore reduction. This eliminates the need for the stabilizing properties of coke and allows coal or gas to be used instead. The COREX process exports a significant volume of calorifically-rich gas (mainly CO and CO2 ), which can be used for either power generation or (after CO2 removal) as a reducing gas for a conventional blast furnace [37].

Direct reduced iron (DRI) is an alternative raw material to scrap for the electric arc furnace. In the DRI process, the iron ore remains in the solid phase. This means that the furnace can be operated at temperatures below the melting point of iron and either gas or coal can be used as the reducing agent instead of coke. The DRI process offers promising opportunities for CO2 capture. Natural gas, enriched with H2 , is partially oxidised to synthesis gas (CO and H2 ) by reacting it with oxygen. This reducing gas is then fed to the reactor and reacted with the solid iron ore, producing a mixture of CO, CO2 , H2 and H2 O. In order to improve the efficiency of the separation process, the CO2 concentration (and consequently the hydrogen concentration) is increased via the shift reaction and CO2 can then be separated using either physical or chemical sorbents. The resulting hydrogen is recycled.

There are a number of potential changes to iron and steel manufacture to enable the capture of CO2 , some entailing significant changes to the production process, but others such as post combustion capture requiring minimal alterations.

Kuramochi et al. [38] have compared a number of these technologies and estimate that an avoidance cost of less than $64/tCO2 for ⇠50% of the CO2 emissions is achievable in the short term by converting conventional blast furnaces to top gas recycling. Alternatively, it is possible to add conventional solvent scrubbing to remove CO2 from the blast furnace off-gas at a cost of $51–64/tCO2 , though because of the high CO concentration in this gas, it is only possible to remove around 15% of the total CO2 emissions [23].

Again, because of the high temperatures inherent in the iron and steel production processes, coupled with the potential to export significant quantities of energy-rich gas, there are significant potential synergies with the power generation sector.

Refineries/petrochemicals Refineries produce CO2 through both process heating and intrinsic chemical transformations (such as regenerating the catalyst used in a fluid catalytic cracker). Refineries are variable in scale and processes used, leading to a significant challenge when defining the constitution of a ‘‘typical’’ refinery, never mind its optimization. Some 30–50% of the CO2 emissions in a refinery result from

Page 8 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

process heating and utilities, i.e. large volumes available at a small number of locations [39] (n.b. reference [1] appears to misquote this value as 30–60%). Around 5–20% of the emissions are high purity, and the remaining ⇠50% is comprised of a number of small sources. Initial experiments being conducted Petrobras into oxyfiring their FCC regeneration [40] as part of the ‘‘Carbon Capture Project’’ (CCP). Figure 6 shows a breakdown of CO2 emissions from refineries worldwide by source [23].

Figure 6. Typical breakdown of CO2 emissions from refineries worldwide by source, after [23].

Farla [14] conducted one of the first studies into CO2 capture from industry, and concluded that the costs of CO2 abated was ⇠$175/tCO2 for capture from the petrochemical industry. Table 2 (after [1]) contains the estimated costs to decarbonize at a variety of locations within an oil refinery.

Table 2. Estimated costs of decarbonisation from a variety of locations in an oil refinery (after [1]).

Process captured

Utilities, combined cycle gas turbine The Heaters and boilers (UK)

Fluid Catalytic Cracker Hydrogen production SMR

Capture type

Post-combustion Pre-combustion Post-combustion Pre-combustion Oxy-combustion Post-combustion Oxy-combustion Chemical looping combustion Post combustion Oxy-combustion Post-combustion

Retrofit or new build

Cost of CO2 avoided $/tCO2 Low

High

New New Retrofit Retrofit Retrofit New New New

39 38 108 69 62 134 70 46

105 106

New Retrofit New

119 77

59

It is clear from Table 2 that the costs of CO2 capture vary significantly between different parts of the refinery. The major reasons for this are the inherent efficiencies of the capture technologies studied, the sizes of the unit operations being captured from and whether the CCS system is new build or retrofit. Costs appear to be a little higher than for power stations, and significantly higher than for decarbonisation of the cement industry. Similar costs might be expected to those for heaters and boilers for other applications where raising steam is key, such as ‘‘Steam-Assisted Gravity Drainage’’ to produce heavy oils.

Biomass processes This sector is currently very small, but the combination of biomass and CCS allows the possibility of ‘‘negative’’ emissions of CO2 [41]. In the non-power-related sector, the main potential sources of CO2 are from breweries/ethanol production plants (which have the advantage of also yielding high-purity CO2 streams), and potentially in the future from either biomass gasifiers/Fischer-Tropsch reactors to produce hydrocarbon fuels, or the direct production and upgrading of pyrolytic oils [42].

Page 9 of 10 Fennell, Florin, Napp, Hills, Sustainable Technologies, Systems and Policies 2012.CCS.17

The potential for this sector should not be underestimated—there are around 3 billion tonnes of biomass residues (i.e. from farming, timber production, etc.) produced per year [43]. In the UK, the TESBIC project [44] has assessed the commercial potential of the integration of biomass combustion for power generation and CCS as a method to capture CO2 from the atmosphere.

Given the low technology readiness levels (TRLs) of many of the proposed technologies for production of e.g. liquid fuels (excluding ethanol) from biomass (e.g. pyrolysis, gasification + Fischer-Tropsch), combined with the low TRL of CCS and the significant uncertainty regarding the biomass value chain, costs are speculative at best. However, for the case of ethanol production [45], which produces a nearly pure stream of CO2 as a byproduct of the fermentation process, costs are extremely low, being only associated with drying and compressing the CO2 for transport. However, by far the most interesting finding from their paper is that adding CCS to the bioethanol plant (and capturing only 13% of the carbon reduces the cost of carbon avoided from $729 to, figures which probably say more about the value of first generation biomass fuels for the mitigation of global warming than they do about the cost of CCS. UNIDO [1] considers that the application of CCS to biomass processes is an extremely important area for future research. To quote from a workshop to discuss the application of CCS to industry ‘‘More detailed scientific studies are needed on costs, long-term contribution on GHG reduction and early opportunities. Dedicated pilot and demonstration projects should be facilitated.’’

CONCLUSIONS The wide variety of industrial sources of CO2 leads to a large variation in the estimated costs. These range from significantly below the cost of application in the electricity production sector, to much higher. The field is underdeveloped in comparison to the power sector, with fewer studies conducted.

This is for two major reasons: firstly, much of the information relating to industrial processes is proprietary, and secondly the industrial sector as a whole (with the exception of gas processing) has been less forward in embracing the technology.

Future research in the area should focus on developing integrated models with common cost models, in collaboration with industry, and explore the potential synergies between power generation and industry, particularly in the cement and iron and steel sectors. Good economic modelling is important. There are also significant experimental research challenges under investigation in the Iron and Steel and Cement manufacturing sectors. Owing to the high temperatures employed in both of these sectors, there are unique possibilities for both to be integrated with high temperature looping cycles, which are being explored in particular in the cement industry.

ACKNOWLEDGEMENTS The Grantham Institute and Cemex are jointly thanked for funding a studentship for Thomas Hills.

Professor Ben Anthony of Ottawa University is warmly thanked for commenting on an early version of this paper.

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OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Introduction to market challenges in developing second generation carbon capture materials Jason Mathew Ornstein* co2industries LLC d/b/a framergyTM , Suite 2011-A, Building 1904, 800 Raymond Stotzer Parkway, College Station, Texas 77843, USA * Email:

findoutmore@framergy.com

ABSTRACT Absent an economic or social cataclysm, there is no plausible way to meet what will be the world’s unavoidable energy demands without utilizing its vast supply of fossil fuels. One important technology being contemplated to mitigate the negative impact of anthropogenic carbon dioxide loading of the atmosphere is Carbon Capture and Storage (CCS). CCS will play a vital role in least-cost efforts to limit global warming.1 To achieve future least-cost solutions, second generation or ‘2.0’ carbon capture materials are being developed with government support to improve efficiencies over the current applied solution that is ‘‘a very expensive proposition’’2 for the installed energy generation base. One 2.0 material, Metal Organic Frameworks (MOFs), is ‘‘capable of increasing (carbon dioxide) selectivity, improving energy efficiency, and reducing the costs of separation processes’’3 in CCS. Such materials can address CCS utilization outcomes in addition to lowering the carbon capture cost. To support further 2.0 carbon capture material development while CCS faces economic challenges, framergyTM is leveraging alternative usages for MOFs and other 2.0 materials developed for carbon capture.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.18 Published: 19 December 2012 c 2012 Ornstein, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

1 International Energy Association (accessed 2012) [4].

2 Herzog (accessed 2012) [5].

3 Li et al. (2012). Pg. 873 [9].

Cite this article as: Ornstein JM. Introduction to market challenges in developing second generation carbon capture materials, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:18 http://dx.doi.org/10.5339/stsp.2012.ccs.18

Page 2 of 5 Ornstein, Sustainable Technologies, Systems and Policies 2012.CCS.18

INTRODUCTION While anthropogenic carbon dioxide loading of the atmosphere needs to be reduced dramatically to manage the negative effects of global warming,4 more and more people are demanding the comforts and goods provided by the same electricity that sends carbon dioxide into the atmosphere.5 One important technology being contemplated to mitigate these negative trends is Carbon Capture and Storage (CCS), a family of technologies and techniques that enable carbon dioxide to be captured from fuel combustion or industrial processes. While CCS is still an emerging technology, and some significant commercial scale up will be required to rationalize costs, ‘‘IEA (International Energy Association) analysis suggests that CCS will play a vital role in worldwide, least-cost efforts to limit global warming, contributing around one-fifth of required emissions reductions in 2050’’.6 CARBON CAPTURE Post-combustion carbon capture offers numerous advantages to other clean energy solutions because existing combustion technologies can still be used without radical changes to them.

Two-thirds of the global electrical energy generation is sourced from fossil fuels; and with coal representing the largest share,7 there is a concentrated source of anthropogenic carbon dioxide emissions. Beyond coal, carbon capture technology could be applied to other site-specific locations such as natural gas electricity generation, industrial steel and cement plants, and possibly even transportation.

Until recently, much of the analysis of CCS forecasted that efficient carbon capture deployment would be through newly-built power generation facilities. This approach greatly limits CCS’ potential, as very few new facilities are in the planning stages outside of China and India. But engineering improvements in effective thermodynamic integration have changed this forecast and a far greater number of existing power plants are suitable for CCS post combustion retrofits.8 To be effective, carbon dioxide capture technology needs to be highly selective and durable for industrial usages while maintaining realistic cost structures. Amine solutions like monoethanolamine (MEA) have been used in the chemical and refining sector for over 60 years to selectively separate carbon dioxide form other gases.9 However, this chemical bonding process has some significant drawbacks.

Today, the only proven CCS capture technology is amine scrubbing. In some ways it works very well — it is highly selective for CO2 and has recovery rates above 90%...It makes retro-fitting older, less efficient plants very difficult. For example, an existing plant with 35% efficiency when retrofitted with CCS will have its efficiency reduced to 20–25%. This is a very expensive proposition.10 The current costs of first-generation (1.0) materials for carbon capture, based on amine technology, has lead to research to develop second-generation (2.0) materials for carbon capture.

Carbon capture materials It is well accepted that the most targetable CCS economic improvement, the cost delta, will likely be carbon capture and not transport or storage.11 2.0 materials for post combustion carbon capture through adsorption provides the most sensible solution, as post combustion technology will be the first CCS technology deployed. Some companies, like framergyTM , have been formed to leverage the learning from government-supported 2.0 material developments (Fig. 1).

Supported mostly by government funding, 2.0 materials used to capture carbon from the flue gas of energy generation and other locations are being developed to target the high cost of chemical bonding carbon capture. Programs like ARPA-E’s IMPACCT were aggressive in funding advanced materials to absorb carbon dioxide produced by existing coal plants.12 Other programs throughout the world are yielding new materials and hope for CCS. 4 Mathews et al. (2009) [1].

5 CESinfo Forum (2011) [2].

6 International Energy Association (accessed 2012) [4].

7 CESinfo Forum (2011) [2].

8 Lucquiand & Gibbins (2009) [3].

9 International Energy Association (accessed 2012) [4].

10 Herzog. (accessed 2012) [5].

11 McKinsey and Co. (2008) [6].

12 ARPA-E. (accessed 2012) [7].

Page 3 of 5 Ornstein, Sustainable Technologies, Systems and Policies 2012.CCS.18

~1

35 - 50

2020 + early commercial reference case

~1

60 - 90

~30

CAPTURE

TRANSPORT

STORAGE

2015 first demo reference case

Figure 1. The cost delta between demonstration and early commercial reference CCS cases (expressed in e/ton CO2 abated) - Source: McKinsey and Co.

Porous materials, a potential 2.0 material for carbon capture, are applied to many industrial processes; but designing these materials with tunable metrics and defined structures can be challenging.13 Improvements in techniques are allowing porous materials such as zeolites, activated carbon and metal organic frameworks (MOFs) to enter gas separations markets, and are being studied for CCS. Of these materials, MOFs appear to represent the greatest hope in designing a 2.0 material for carbon capture.

By taking advantage of their regularity, rigidity/flexibility, variety, and designability in both structure and properties, MOFs are being regarded as advanced porous materials capable of reaching or surpassing a number of current technologies. As compared to traditional inorganic porous solids and activated carbon, the number of possibilities of combining inorganic and organic moieties to yield a porous material is staggering and is indeed reflected by the prodigious number of papers on this type of compounds in the last 20 years.14 COMMERCIALIZATION Between 2000 and 2010, at least 33 venture capital investments into CCS technology were made with a disclosed value over $380 million.15 As it became apparent that there would be no global price on carbon in 2011, several high profile CCS projects were scaled back or cancelled, and private capital for these technologies dried up.16 The commercialization process for CCS, and in particular 2.0 materials used for carbon capture, has been challenging, as industry de-risked their CCS strategies. framergyTM , founded in early 2011 to commercialize the materials developed at Texas A&M University, is the first incidence of private capital being attracted to the ARPA-E IMPACCT program.17 UTILIZATION The economics of storage, sometimes referred to as sequestration, represents a major obstacle to the development of CCS. Without a better understanding of what would be done with the massive amount of captured carbon dioxide generated through CCS, private capital has shied away from carbon capture improvements. For many years, geological storage was considered a feasible solution,18 but recent announcements suggest that industry is questioning storage’s forecasted feasibility.19 Technical challenges to drill and map a storage site and political challenges to secure regulated underground rights were not part of the press discussion of the cancellation of the American Electric Power Mountaineer CCS II Project in West Virginia, USA20 ; but did impact the final decision.21 Without a storage option, the concept of ‘‘utilization’’ for captured carbon dioxide from CCS has gained popularity. Several key organizations have relabeled CCS, adding ‘‘utilization’’ to the end of the acronym, before storage (CCUS) or sometimes even removing the word storage (CCU).

13 Barton et al. (2009) [8].

14 Li et al. (2012). Pg 873 [9].

15 framergy Company Notes & Bloomberg New Energy Finance (2011) [10].

16 American Electric Power (2012) [11].

17 framergy Company Notes [10].

18 Rubin et al. (2007) [14].

19 American Electric Power (2012) [11].

20 Thomson Reuters (accessed 2012) [12].

21 American Electric Power (2012).

Page 4 of 5 Ornstein, Sustainable Technologies, Systems and Policies 2012.CCS.18

Scientifically, devising a utilization plan for separated carbon dioxide, where the molecule ends up in a new molecule, mimics the development of flue gas sulfur dioxide cleaning which produces industrial products such as sulfur, sulfuric acid and gypsum.22 The most common utilization for carbon dioxide captured from pilot CCS projects is enhanced oil recovery or enhanced natural gas recovery. This usually requires the system to be located near a depleted oil field or natural gas deposit.23 While this provides a bridging option for the early stages of CCS with favorable locations, it is clear that other utilization schemes will need to be developed to compliment advanced carbon capture techniques.

WHY 2.0 MATERIALS? Chemical analysis for many newly designed 2.0 materials for carbon capture, like porous materials, suggest these materials could be effective in addressing the targetable delta in CCS. One reason is that, as sorbents, these materials don’t upset current engineering system of the massive installed base of power generation that has a long amortization horizon. But more importantly: With the large variety of MOFs that are available, one can expect these novel porous materials to be capable of increasing selectivity, improving energy efficiency, and reducing the costs of separation processes.24 In addition, 2.0 materials for carbon capture can be designed to improve utilization options as they may offer better temperature and pressure regeneration outcomes.

The investment in fundamental research for 2.0 materials, such as MOFs, has largely revolved around clean energy and began in earnest with the desire to solve hydrogen storage issues for fuel cells.

These properties, together with the extraordinary degree of variability for both the organic and inorganic components of their structures, make MOFs of interest for potential applications in clean energy, most significantly as storage media for gases such as hydrogen and methane, and as high-capacity adsorbents to meet various separation needs.25 Porous material alternative usages are drawing significant industrial attention as scientists move down the learning curve funded by government’s desire to deploy CCS. Carbon specific usages for 2.0 materials can now be explored, such as natural gas upgrading and low density carbon capture, which may offer more immediate economic return.

CONCLUSION In the 1980’s, many countries struggled with the polluting effects as a result of coal’s emissions of sulfur dioxide and nitrogen oxides. Through regulation, the United States was able to achieve its targeted environmental goals of sulfur dioxide and nitrogen oxides reductions at lower than projected cost.26 Much of this was achieved through technological innovation to post combustion power generation, which scrubs pollutants in the flue gas and provides industrial byproducts for ‘utilization’.

Amine solutions offer no clear path to effective carbon capture for industrial uses. Derivatives of amine solutions which utilize the chemical bonding features of ammonia only forestall the ability of industry to achieve cost-effective carbon capture and put CCS as a solution to global warming at risk of never developing. 2.0 materials for carbon capture, with their design advantages, offer a path to cost-effective carbon capture and improvements to utilization outcomes. Changes in the CCS market will encourage 2.0 material developers to seek alternative commercial usages for their intellectual property. framergyTM , located in Texas, USA, is leveraging the remarkable attributes of metal organic frameworks and other materials to open new business horizons.

22 The World Bank (1998) [13].

23 Rubin et al. (2007) [14].

24 Zhou et al. (2012). Pg. 673 [15].

25 Zhou et al. (2012). Pg. 673 [15].

26 Schmalensee et al. (1998) [16].

Page 5 of 5 Ornstein, Sustainable Technologies, Systems and Policies 2012.CCS.18

REFERENCES

[1] Damon Matthews H., Gillett Nathan P., Stott Peter A. and Zickfeld Kirsten. The proportionality of global warming to cumulative carbon emissions. Nature. 2009, June 11;459:829–832.

[2] Karl Hans-Dieter and Lippelt Jana. Electricity Generation: Cola Use and Cutting CO2 Emissions. CESinfo Forum.

2011, April; April, 68–71.

[3] Lucquiand M. and Gibbins J. Retrofitting CO2 capture ready fossil plants with post – combustion capture. Part 1: requirements for supercritical pulverized coal plants using solvent – based flue gas scrubbing. J Power Energy.

2009, May 1;223:3, 213–226.

[4] ‘‘Carbon Capture and Storage,’’ International Energy Association, accessed March 1, 2012, http://www.iea.org/ccs/.

[5] Herzog Howard. A Research Program for Promising Retrofit Technologies, MIT Symposium on Retro-fitting of Coal-Fired Power Plants for Carbon Capture, accessed January 10, 2012, http://web.mit.edu/mitei/docs/reports/herzog-promising.pdf.

[6] Campbell Warren. Carbon capture and Storage: Assessing the Economics. McKinsey and Company, New York.

2008.

[7] INNOVATIVE MATERIALS & PROCESSES FOR ADVANCED CARBON CAPTURE TECHNOLOGIES (IMPACCT) ARPA-E, accessed March 1, 2012, http://arpa-e.energy.gov/ProgramsProjects/IMPACCT.aspx.

[8] Barton Thomas J., Bull Lucy M., Klemperer Walter G., Loy Douglas A., McEnaney Brian, Misono Makoto, Monson Peter A., Pez Guido, Scherer George W., Vartuli James C. and Yaghi Omar M. Tailored porous materials.

Chem Mater. 1999, October 18;11:10, 2633–2656.

[9] Li Jian-Rong, Sculley Julian and Zhou Hong-Cai. Metal-organic frameworks for seperations. Chem Rev. 2012, February;112:2, 869–932.

[10] Company Notes, Bloomberg New Energy Finance search accessed on June 6, 2011.

[11] Cerimele Guy L. CCS LESSONS LEARNED REPORT - American Electric Power Mountaineer CCS II Project Phase 1.

American Electric Power, Inc, Columbus, Ohio. 2012, 23 January.

[12] ‘‘AEP halts carbon capture plan due climate inaction,’’ Thomson Reuters, accessed March 1, 2012, http://www.reuters.com/article/2011/07/14/us-utilities-aep-carbon-idUSTRE76D34C20110714.

[13] Institutional Authors Sulfur Oxides: Pollution Prevention & Control. Pollution Prevention & Abatement Handbook.

The World Bank, Washington DC. 1998, July.

[14] Rubin Edward S., Chen Chao and Rao Anand B. Cost and Performance of fossil fuel power plants with CO2 capture and storage. Energy Policy. 2007, September;35:9, 4444–4454.

[15] Zhou Hong-Cai, Long Jeffery R. and Yaghi Omar M. Introduction to metal-organic frameworks. Chem Rev. 2012, February;112:2, 673–674.

[16] Schmalensee Richard, Jowskow Paul L., Denny Ellerman A, Montero Juan Pablo and Bailey Elizabeth M. An interim evaluation of sulfur dioxide trading. J Econom Perspectives. 1998;12:3, 53–68.

OPEN ACCESS

Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Shipping and CCS: A systems perspective N. Mac Dowell*, N. Shah** Centre for Process Systems Engineering, Dept. of Chemical Engineering, Imperial College London, London, UK * Email:

nmac-dow@imperial.ac.uk n.shah@imperial.ac.uk

** Email:

ABSTRACT In this contribution, we present an overview of the contribution made by the shipping sector to global CO2 emissions. We review the currently proposed technology options for mitigating these emissions, and propose a new option for the control of greenhouse gas emissions from shipping.

Keywords: CO2 capture, shipping, co-polymerisation, ionic liquids, ammonia, CO2 transport

http://dx.doi.org/ 10.5339/stsp.2012.ccs.19 Published: 19 December 2012 c 2012 Mac Dowell & Shah, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Mac Dowell N & Shah N. Shipping and CCS: A systems perspective, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:19 http://dx.doi.org/10.5339/stsp.2012.ccs.19

Page 2 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

INTRODUCTION Global shipping is a major contributor of CO2 to the atmosphere. In 2007 shipping was responsible for approximately 3.3% of total global CO2 emissions. This corresponds to cumulative emissions of over 1 billion tones [1]. This is illustrated in Fig. 1.

International Shipping 2.7%

International Aviation 1.9%

Domesic Shipping and Fishing 0.6%

Rail 0.5%

Other Transport (Road) 21.3%

Electricity and Heat Production 35.0%

Manufacturing Industries and Construction 18.2%

Other 15.3%

Other Energy Industries 4.6%

Figure 1. Emissions of CO2 from shipping compared with global total emissions.

As is illustrated in Fig. 2, if the global shipping fleet were a nation it would be the sixth largest emitter of carbon dioxide, only emitting less than China, the United States, Russia, India and Japan [2]. In the absence of emission reduction policies, emission scenarios predict a doubling to tripling of 2007 emission levels by 2050 [3]. The significance of this predicted increase becomes more apparent when one considers that many countries, e.g., the United Kingdom have set ambitious targets towards appreciably reducing their CO2 emissions by 2050 [4]. Therefore, if unabated, the CO2 emissions associated with the shipping sector will be of even greater significance. Assuming reductions are achieved by other sources as is necessary to limit climate change to two degrees Celsius, unregulated shipping emissions could come to account for 12 to 18 percent of global carbon dioxide emissions in 2050 [1].

CHINA

USA

RUSSIA

INDIA

JAPAN

GLOBAL FLEET GERMANY

CANADA

UNITED KINGDOM

0

1

2

3

4

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7

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Figure 2. Global shipping is among the worldâ&#x20AC;&#x2122;s top 10 CO2 emitters [3].

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International shipping is a very important model of transportation, which has historically increased at a rate exceeding that of global GDP growth. This phenomenon is illustrated in Fig. 3.

Container transport

1200

Million tons

1000 800 600 400 200

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

0

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Figure 3. Increase in containerized transport to the year ending 2006 [5].

Annual Emissions [Tg (CO2/NO2/SO2)/yr]

It is of interest to compare the impact that shipping has on the climate to that of other transport sectors. It is clear from the data presented in Fig. 4 that international shipping exerts an influence similar to that of aviation in all cases, and in all cases but CO2 emission, ship emissions are significant compared with emissions from road traffic. This is of added importance when one considers that SOx emissions exert a negative radiative forcing (RF), i.e., a cooling effect, on the climate. As there are increasing requirements to mitigate the SOx emissions from shipping, this will serve to increase the potential warming effect associated with residual CO2 emissions, if these are not mitigated in line with the SOx emissions. Further, the emissions of NOx from shipping are substantial and possibly represent up to around 20% of global NOx emissions.

10000 1000

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280

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NO2

SO2

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Figure 4. Transport related annual emissions of CO2 , NOx , SOx , PM10 and fuel consumption for the year 2000 [5].

In this context, it is clear that there is a pressing need to consider a long-term strategy for the cost-effective mitigation of the CO2 emissions originating from international shipping. There are several technology options which are considered to be promising in the near term for the decarbonisation of large-scale, fixed point sources. These have been discussed at length in a previous contribution [6], and in the interest of brevity will not be described in detail again here. One aspect which the majority of CO2 capture technologies have in common is that they have a very large footprint. This is obviously of greater concern in the context of shipping than in the case of a land-based power station. Thus there is a clear need to develop means to mitigate the CO2 emissions from shipping which are both cost effective and are appropriate for space-constrained environments such as shipping.

The remainder of this paper is laid out as follows; in the following section, we present some of the most promising near term options for reducing the carbon footprint of international shipping. We then go on to consider some new chemical conversion-based methods for capturing CO2 emitted from shipping. Finally, we conclude with some considerations of how legislating for decarbonisation of shipping is distinct to that for the decarbonisation of large, fixed point sources.

Page 4 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

TECHNOLOGICAL AND OPERATIONAL POTENTIAL FOR THE MITIGATION OF GREENHOUSE GAS EMISSIONS FROM SHIPPING In principle, there are four fundamental categories of options for reducing emissions from shipping.

Emissions can be reduced by increasing efficiency, using less carbon-intensive fuels, using different power sources, including renewables and using emission reduction technologies, such as chemical conversion. Each of these options will be discussed in detail in the following section.

Improving efficiency means decreasing fuel consumption per tonne-mile, or that the same amount of work is done using less energy. The original design of the ship in part dictates to the ship in part dictates the efficiency [1]. Operational measures can have an almost immediate effect on emissions.

These near-term mitigation measures can help reduce current emissions and prevent the projected extreme growth in emissions. Operational measures should not be the only tool utilized to reduce shipping emissions, but they are the low hanging fruit that can take immediate effect and reduce emission from the current fleet that will continue to be in operation for the coming decades.

Energy efficiency Improved energy efficiency means that the same amount of useful work is done, but using less energy.

This in turn means less fuel burned and reductions in emissions of all exhaust gases. A wide range of options are available for increasing the energy efficiency of ship design and ship operation [7].

Hull and propeller optimization The optimisation of the underwater hull and the propeller is a well known abatement option that is regularly applied to new ship designs.

While the selection of the optimal propeller should occur during construction, it is possible to upgrade a propeller over the vessel’s operational lifetime. Large rotating propellers that turn at a low revolution produce high propulsive efficiency. It is possible to retrofit a vessel with a more efficient propeller. This could decrease fuel consumption by as much as 15 percent, with a range of 5 to 10 percent likely [1]. The loss of propeller energy can also be recovered by measures such as vanes, free rotating vane wheels, pre and post-swirl devices, fins, ducts and high efficiency rudders. These measures can reduce a vessel’s propulsion power by 5 to 10 percent [3].

There are many barriers to focusing solely on hull design to reduce resistance. Examples are the effects of hull optimisation on the amount and type of payload that a vessel can carry, and on the vessel’s overall dimensions which may affect whether it is able to dock at ports and terminals. These barriers will considerably reduce the potential for reduction of resistance and fuel consumption. On single ships, improvements in power requirements of up to 30% have in fact occasionally been achieved on particularly ill-conceived designs that did not allow for these other constraints [1].

Resistance and energy consumption increases when vessels encounter waves. Traditionally ships have been optimised primarily for operation in calm seas, possibly owing to the fact that contracted trial performance measurements are typically performed in still water conditions. However, optimisation for more complex wave patterns is becoming more common. Ships during their life time will more frequently operate in the wave field characterized by the short wavelength, , (small sea states) in comparison to the ship length, L than in the wave field where the ship will experience significant wave-induced motions (e.g. severe storm situation). Therefore, optimisation for waves generally emphasises short wavelength waves [8].

One successful example is development of the so called ‘‘beak bow’’ at Osaka University. This particular bow design was implemented on ships with high block coefficient, Cb , (tankers, bulk carriers) in order to reduce the wave added resistance. The ordinary bow waterline curve is significantly altered with the introduction of a beak bow. The altered bow design has a more pointed (sharp) shape than a conventional bow design. However, the original beak bow design was not satisfactory from a practical point of view since it significantly increases the overall ship length (LOA) which makes the particular ship too long to enter some ports. Therefore, the original beak bow design has been altered to give the more practical axe-bow design—this is illustrated in Fig. 5 [9].

In comparison to the original beak bow design it should be noted that the waterline shape remains the same which means that the power estimates are not influenced by the practical modification.

Page 5 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

Figure 5. Tank model of axe-bow and 172,000DWT Capesize bulk carrier KOHYOHSAN built with axe-bow for Mitsui O.S.K. Lines, Ltd in 2001.

Renewable energy sources Solar Current solar-cell technology is sufficient to meet only a fraction of the auxiliary power requirements of a tanker. Obviously, solar power is by its nature intermittent, thus an appropriate â&#x20AC;&#x201C; likely fossil fuel-based â&#x20AC;&#x201C; backup power source would be required. Consequently, at the current state of the art, solar power is considered to be of interest primarily as a complementary source of energy; with present technology it could be possible to realise only a modest reduction in energy demand, even with extensive use of solar power. Therefore, present-day cost levels and efficiency place solar power towards the lower end of the cost-effectiveness list [10].

Wind Wind technology in the form of traditional sails, kites, solid wings and rotors can be added to current vessels with large reductions in fuel consumption. Wind technology could create fuel savings of about 5 percent for vessels travelling at 15 knots and about 20 percent for vessels traveling at 10 knots.

Kites have been reported to gain a 10 to 35 percent saving in fuel for a single voyage. Kites take up only a small area on the deck and can be relatively easily retrofitted to existing vessels [5]. Drawbacks with the kite systems include complex launch, recovery and control systems.

Despite traditional sails having once been the only source of propulsion, currently sails are considered interesting as additional supplementary power. Use of traditional sails imposes bending moments on the hull, which can cause ships to list. Strength issues could result in a need for masts to run down to the keel, and the presence of the mast and rigging could have significant impacts on cargo handling.

Naturally, it is difficult to simulate such complex systems and currently there are limited real world data against which such a model can be validated. Also, without such experience it is difficult to assess the practical feasibility of the size and number of sails modelled. Nevertheless, sail assisted power does seem to be an interesting opportunity for fuel saving in the medium and long term picture.

Alternative fuels Alternative fuels are a promising option for lowering the lifecycle greenhouse gas emissions associated with international shipping. This option is particularly attractive in that it can be readily implemented, with little or no modification to existing assets.

Marine diesel fuel Heavy fuel oils can be replaced with marine diesel oil (MDO) which is less carbon intensive and allows for more effective fuel combustion, resulting in better efficiency and lower levels of emitted particulate matter. Switching over to MDO can reduce carbon dioxide emissions from vessels by as much as 5 percent [3].

Liquefied natural gas Liquefied natural gas (LNG) is an attractive option for use as an alternative fuel within the shipping industry. The fuel has a higher hydrogen-to-carbon ratio compared with oil-based fuels, which results in lower specific CO2 emissions (kg of CO2 /kg of fuel). This is similar to the rationale of land-based

Page 6 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

natural gas-fired power stations being inherently cleaner than coal-fired power stations. Further, LNG is a clean fuel, containing no sulphur; thus eliminating the SOx emissions and essentially eliminating the emissions of particulate matter. Additionally, the NOx emissions are reduced by up to 90% due to reduced peak temperatures in the combustion process. However, the use of LNG will increase the emissions of methane (CH4 ), and as CH4 is a significantly more potent greenhouse gas than CO2 , this reduces the net global warming benefit from 25% to approximately 15%.

One of the main challenges for the use of LNG as a fuel for ships is to find sufficient space for the on board storage of the fuel. The energy density of LNG is approximately 55% that of diesel oil [1].

Also, LNG must be stored on-board ship at pressure and the storage vessel will in turn require a large space. Thus, the actual volume requirement is in the range of three times that of diesel oil. In addition, the ready availability of LNG fuels in bunkering ports is a challenge which needs to be solved before LNG becomes a practical alternative.

In summary, the present potential for reduction of emissions of CO2 from ships through the use of LNG is somewhat limited, and is mainly relevant for new ships (as opposed to retrofits) and because, at present, LNG bunkering options are limited. The forthcoming NOx and SOx emission control areas (ECAs) will provide significant additional incentives for the use of LNG propulsion in short sea operations, since ECA requirements can easily be met by LNG-propelled ships. The price of LNG is presently significantly lower than that of distillate fuels, making an economic incentive for a move to LNG Biofuels First generation biofuels which are derived from sugar, starch, vegetable oil, or animal fats can readily be used for ship diesels with little or no adaptation of the engine. Depending on source, there are certain technical issues, such as stability during storage, acidity, lack of water-shedding (potentially resulting in increased biological growth in the fuel tank), plugging of filters, formation of waxes, increased engine deposits, etc., which suggest that care must be exercised in selecting the fuel and adapting the engine. Care must be exercised to avoid contamination with water, since biofuels are particularly susceptible to biofouling. Blending bio-derived fuel fractions into diesel fuel or heavy fuel oil is also feasible from the technical perspective; however, compatibility must be checked [11–13].

The net carbon intensity resulting from the utilisation of biofuels is a function of the biomass source used, and how it is transformed from raw biomass to a fuel product. Not all biofuels have a CO2 benefit [11]. A whole-systems analysis of the biofuel production process is vital to assess this.

Biofuels can have different combustion characteristics than traditional diesel, for example the use of biofuels can result in a 7% to 10% increase in NOx emissions. We note, however, that the extent of NOx production is a function of the design and operation of the engine (e.g., fuel injection rate and timing).

Biofuel produced from energy crops and also industry waste such as wood chips may be referred to as ‘‘second-generation’’ biofuels. These fuels are considered more sustainable than those produced from food crops in that they do not compete with food crops. The conversion process that is needed to facilitate production of second-generation biofuel on an industrial scale and economically viable is still in development [1].

Emission reduction technologies While many of the above described emission reduction techniques may seem piecemeal, they will contribute to reducing fuel consumption and hence the carbon intensity of shipping. Incremental decreases in emissions from individual ships can result in large reductions across the entire fleet. In fact, the 2009 International Maritime Organisation study suggests that the fleet can become 25 to 75 percent more efficient than it is currently through both operational and technological measures by 2050. This same study finds that operational measures alone can reduce emissions by 10 to 50 percent [1]. In this section, we present a chemical conversion option which could account for the remaining fraction of CO2 .

As a preamble, it is useful to highlight the main challenges associated with scrubbing CO2 from the flue gases of ships. The CO2 intensity of shipping is approximately 13.9gCO2 .tonne 1 .km 1 with the exhaust gases from ships typically having the following composition: • 5 vol% CO2

• 13 vol% O2

Page 7 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

• 1500 ppm NOx • 600 ppm SOx • 60 ppm CO This corresponds to an exhaust gas flowrate of 30–40 m3 .s 1 emitting between 3 and 4 kg.s 1 of CO2 , leading to an average of 4,500 tonnes of CO2 emitted per trip [14]. It is immediately obvious that this poses a challenging separation problem owing to the relatively dilute nature of the flue gas.

An attractive land-based option for flue gas clean-up is flue gas scrubbing with amine solvents [6].

These processes operate by scrubbing the flue gases with an aqueous solution of amine—typically a 30wt% solution of MEA is used. The CO2 is absorbed into the liquid phase via an exothermic reaction, with a 1Habs = 82 kJ/mol. The reaction scheme is illustrated in Fig. 6. low temp ∆

RNHCO2- RNH3+ carbamate

2RNH2 + CO2

H2O ∆

pH

2RNH3+ CO32carbonate

RNH3+ HCO3- +RNH2 bicarbonate

Figure 6. Reaction scheme for amines with CO2 in aqueous solution. Reproduced from [15].

It may be observed from Fig. 6 that maximum absorption of CO2 occurs when all of the absorbed CO2 exists as a bicarbonate salt. However, in the case of MEA, the prevalent salt at equilibrium is a carbamate salt, thus limiting the capacity of MEA to absorb CO2 to approximately 0.5 moles of CO2 per mole of MEA [16].

The rich solvent is subsequently regenerated by boiling off the CO2 , allowing the solvent to be recycled. This is a significant energy cost. The CO2 is then dehydrated, and compressed to approximately 110 bar in preparation for transport and subsequent storage. It is interesting to note that this type of technology has historically been deployed on board submarines for the removal of CO2 from the ambient air [17,18,15].

In the case of submarines, the captured CO2 is expelled from the vessel. At sufficient depth, this could result in the CO2 being absorbed into the ocean. However, if the CO2 is expelled at or near the surface, this obviously results in the CO2 entering the atmosphere. However, in the case of surface shipping, we are interested in reducing the emission of CO2 to atmosphere, thus simply venting the CO2 is not an appropriate approach. This requires the proposal of some suitable mechanism to store the captured CO2 on board ship. One could envisage a scenario wherein the captured CO2 is compressed and stored on-board ship. However this would entail significant extra cost both in terms of energy required to compress the CO2 and space required to store it on board. Further, one should consider the hazard associated with storing large quantities of a pressurized asphyxiant gas.

Moreover, amine solvents, such as monoethanolamine (MEA), are degraded by acid gases such as SOx and NOx in addition to reacting irreversibly with oxygen. The relatively high concentration of O2 in ship exhaust gases thus poses an especially interesting challenge. The degradation products can be hazardous to human health in addition to potentially reducing the efficiency of the capture process (reduced capture rates, equipment corrosion). The issue of corrosion has the effect of limiting the concentration of MEA to a maximum of 30wt%. Thus, in land-based applications, replacement solvent costs are an appreciable part of the operational costs of the capture process. A further issue is the volatility of MEA—leading to solvent losses and the creation of a fire hazard. This is obviously of particular importance in shipping applications.

Thus, the principal challenges associated with CO2 capture from ships can be summarized as: 1. Energy penalty associated with solvent regeneration 2. Solvent degradation by SOx , NOx and O2 3. Solvent and CO2 storage

Page 8 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

In addressing points 1 and 2 above, astute selection of the solvent is the key. The solvent used in chemical absorption processes such as this one effective defines the thermodynamic and kinetic limits of a given process. Thus it is desirable that we identify sorbent materials with 1.

2.

3.

4.

High capacity to absorb CO2 – minimize equipment size High thermal and chemical stability, i.e., resistant to thermal and chemical degradation Low volatility – avoid solvent losses and the generation of a fire hazard Bond weakly with CO2 – minimize cost of sorbent regeneration

Thus we propose two sorbent options which have these desired properties: Ammonia Ammonia-based absorption processes have been proposed and extensively studied for application to land-based CO2 emission sources. Ammonia (NH3 ) has the advantage that it is chemically very stable – it is not degraded by O2 , and is capable of simultaneously removing CO2 , NOx and SOx in addition to any HCl and/or HF that might exist in the flue gas [19]. The robust nature of this sorbent is of particular interest in light of the nature of the fuels typically used in marine applications.

Further, at the thermodynamic conditions of interest, NH3 reacts with CO2 to form a bicarbonate salt, thus increasing its capacity to carry CO2 to approximately 1 mole of CO2 per mole of NH3 . This reaction follows the form [20,21]: NH3(l) + CO2(g) + H2 O(l)

! NH4 HCO3 .

Further, it has been reported that the energy consumption for CO2 regeneration using an ammonia-based solvent could be at least 75% less than a comparable MEA-based solvent [19]. Thus, the solvent regeneration could well be carried out via heat integration between the existing engine and the CO2 capture plant, minimizing the efficiency penalty on the ship’s engines.

One area where there are significant complications in using an ammonia-based solvent is the volatility of this compound. However, this problem can easily be addressed by operating the capture process as a closed-loop system at low temperatures. A key advantage of on-ship CO2 capture is the ready availability of an infinite heat sink.

Ionic liquids Ionic liquids (ILs) are a family of compounds with a very wide variety of properties due to their particular physicochemical characteristics. In particular, their extremely low volatility marks them as environmentally benign alternatives to volatile organic solvents for separation processes. This non-volatility also leads to most ionic liquids being non-flammable under ambient conditions. In addition, ionic liquids are typically both thermally and chemically stable, and therefore are suitable for the simultaneous capture of CO2 and other acid gas pollutants [22]. Further, ionic liquids have been trialed for capturing CO2 and have been observed to offer up to a 16% saving on the energy consumption when compared to MEA-based processes [23]. Crucially, the mechanism through which CO2 is absorbed is thought to be entropically-driven (rather than enthalpically-driven) – this is what appears to reduce the energy of absorption. One outstanding issue associated with using ILs for CO2 capture is the low density of the IL. This will tend to increase the footprint associated with the capture process.

On-board storage of captured CO2 In the previous sections, we have outlined some new technology options which can address the issue of CO2 emissions from shipping. However, we have not, as yet, considered the issue of what to do with the CO2 once it has been captured. We suggest that the option of on-board compression and storage of captured CO2 is inappropriate.

One key advantage of the ammonia-base process described in the previous subsection is that the reaction product – ammonium bicarbonate – can be sold as a fertilizer [19]; a commodity which can be expected to increase in value in coming decades.

Page 9 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

Another option is the concept of using CO2 as an environmentally benign C1 building block for the production of biodegradable polymers [6]. In particular, Kember et al. [24] have suggested using a dizinc catalyst for the copolymerization of CO2 and cyclohexene to produce polycarbonates and polyurethanes. Importantly, this reaction proceeds at low pressure (1 atm) and low temperature (343 K). This process would replace the current process which is uses phosgene – which is also used as a chemical weapon – so there are obvious advantages in replacing this process. The concept of storing captured CO2 on board ship as a solid material with a resale value has obvious commercial and operational advantages. Another advantage is the mechanism through which it may be offloaded. Offloading a compressed fluid is substantially more complex than offloading a solid material, thus the processes outlined here are attractive from this perspective also.

SHIP-BASED TRANSPORT OF CAPTURED CO2 Another area in which shipping is considered to be of interest in the context of mitigating anthropogenic CO2 emissions is in the area of transporting captured CO2 . It is possible to envisage a scenario in which CO2 is captured from a diffuse range of point sources, transported to shore via pipe-line. However, rather than extending the transport network along the ocean bed, the CO2 could be loaded onto ships, and then it is transported to an appropriate injection site. Owing to its low density, it is inefficient to transport CO2 in the gas phase. Liquefaction before shipping is therefore necessary for volume reduction. It is common to liquefy gas for ship transport, as experienced commercially for LNG, LPG and other chemical materials. Another requirement before shipping is the temporary storage and the loading to the ship, and similar one when necessary for after shipping. It is envisaged that a ship-based CO2 transport can move approximately 20,000 m3 liquid-phase CO2 .

This could be particularly attractive when there are several small streams of relatively impure CO2 available, which are not suitable for combined pipeline transport, but are suitable for injection [25]. CO2 capture is a continuous process but the cycle of ship transport is not, so buffering capacity at the port and at the storage site is required. This scheme is illustrated in a flowsheet in Fig. 8. It is interesting to note, however, that as long as the distance of the injection site from shore is relatively small, i.e., less than 1000 km, there is relatively little merrit in having larger ships with which to transport CO2 [25,26]. This is illustrated in Fig. 7.

60 50

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0

20000

40000

60000

ship size [ton]

Figure 7. Influence of ship size and transport distance on cost, adapted from [25].

CONCLUSIONS International shipping is an important transport mechanism, and is predicted to grow in importance over the coming decades. This will increase the importance of reducing the CO2 emissions from this source, particularly as other sources are themselves mitigated. In this paper, we have outlined several options – some near term, some longer term – which can be used to reduce the greenhouse gas footprint of the shipping sector. As the current shipping fleet is likely to be in service for several decades yet to come, the chemical conversion options are likely only to be applied closer to 2050.

Page 10 of 11 Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

CO2 capture CO2 source compression

pipeline

(transport to port)

liquefaction

port

temporary storage loading

CO2 ship

marine transport

(unloading)

storage site

(temporary storage)

CO2 injection

Figure 8. General diagram of CO2 capture, ship transport and offshore geological storage, adapted from [25].

REFERENCES [1] Buhaug Ø. et al. Second IMO GHG Study. International Maritine Organisation (IM), London. 2009.

[2] Harrould-Kolieb E. Shipping impacts on climate: a source with solutions. Oceana. 2008.

[3] Harrould-Kolieb E. and Savitz J. Shipping solutions: Technological and operational methods available to reduce CO2 . Oceana. 2010.

[4] DECC. http://www.theccc.org.uk/carbon-budgets/path-to-2050. [Online] [Cited: 15 March 2012].

[5] Kollamthodi S. Greenhouse gas emissions from shipping: trends, projections and abatement potential. AEA Energy and Environment. 2008.

[6] Mac Dowell N., Florin N., Buchard A., Hallett J.P., Galindo A., Jackson G., Adjiman C.S., Williams C.K., Shah N. and Fennell P.S. An overview of CO2 capture technologies. Energy and Environmental Science, 2010;3:1645–1669.

[7] Green Erin H., Winebreak James J. and Corbett J.J. Opportunities for Reducing Greenhouse Gas Emissions from Ships. Clean Air Task Force, Boston. 2008.

[8] Faltinsen O.M. et al. Prediction of resistance and propulsion of a ship in a seaway. Proceedings of the 13th Symposium on Naval Hydrodynamics. 2005; Tokyo, Japan. 505–529.

[9] Matsumoto K. et al. BEAK-BOW to reduce the wave added resistance at sea. Proceedings of the 7th Int. Symp. on Practical Design of Ships and Mobile Units. 1998. The Hague, The Netherlands.

[10] Green M.A. Third generation photovoltaics: Solar cells for 2020 and beyond. Physica E. 2002;14:65–70.

[11] Opdal O.A. and Fjell Hojem J. Biofuels in ships: A project report and feasibility study into the use of biofuels. ZERO report. 2007.

[12] Ollus R. and Juoperi K. Alternative fuels experiences for medium-speed diesel engines. Proceedings of the 25th CIMAC World Congress on Combustion Engine Technology. 2007. Vienna, Austria.

[13] Matsuzaki S. The application of the waste oil as a bio-fuel in a high-speed diesel engine. Proceedings of the 24th CIMAC World Congress on Combustion Engine Technology. 2004. Kyoto, Japan.

[14] Well-to-wheels analysis of future automotive fuels and powertrains in the Eurpoean Context. 2009.

[15] Hook R.J. An investigation of some sterically hindered amines as potential carbon dioxide scrubbing compounds.

Ind. Eng. Chem. Res. 1997;36:1779–1790.

[16] Mac Dowell N., Llovell F., Adjiman C.S., Jackson G. and Galindo A. Modelling the fluid phase behaviour of carbon dioxide in aqueous solutions of monoethanolamine using transferable parameters with the SAFT-VR approach.

Ind. Eng. Chem. Res. 2010;49:4, 1883–1899.

[17] Ravner H. and Blachly C.H. Studies on Monoethanolamine (MEA). The present status of chemical research in atmospherepurification and control on nuclear-powered submarines. Naval Research Laboratory, Washington, DC. 1962.

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[18] Gustafson P.R., Miller R.R. and Piatt V.R. eds., CO2 Absorption Properties of Some New Amines. The Present Status of Chemical Research in Atmosphere Purification and Control on Nuclear-Powered Submarines. 1968.

[19] Resnik K.P., Yeh J.T. and Pennline H.W. Aqua ammonia process for simultaneous remocal of CO2 , SO2 and NOx . Int. J. Environ. Tech. Manag. 2004;4:1/2, 89–104.

[20] Yeh A.C. and Bai H. Comparison of ammonia and monoethanolamine solvents to reduce CO2 greenhouse gas emissions. The Science of the Total Environment. 1999;228:121–133.

[21] Mac Dowell N. et al. Transferable SAFT-VR Models for the Calculation of the Fluid Phase Equilibria in Reactive Mixtures of Carbon Dioxide, Water, and n-Alkylamines in the Context of Carbon Capture. J. Phys. Chem. B. 2011;115:8155–8168.

[22] Llovell F. et al. Modelling the absorption of weak electrilytes and acid gases with ionic liquids using the soft-SAFT approach. J. Phys. Chem. B. 2012. (submitted) [23] Shiflett M.B. et al. Carbon dioxide capture using ionic liquid 1-butyl-3-methylimidazolium acetate. Energy Fuels.

24:5781–5789.

[24] Kember M.R. et al. Highly active dizinc catalyst for the copolymerization of carbon dioxide and cyclohexene oxide at one atmosphere pressure. Angew. Chem. Int. Ed. 48:5, 931–933.

[25] Ozaki M. and Ohsumi T. CCS from multiple sources to offshore storage site complex via ship transport, 2011;4, 2992–2999.

[26] Ship Transport of CO2 . IEA Greenhouse Gas R&D Programme, 2004. Report No.PH4/30.

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

Green shipping Talal Al-Tamimi RasGas Company Limited, Doha, Qatar

SUMMARY The state-of-the-art facilities of RasGas and QatarGas process natural gas from Qatar’s North Field, the world’s largest non-associated gas field. At the Ras Laffan site, gas is liquefied to LNG and then loaded to tankers for transportation. But along with the objective of supplying LNG to customers as efficiently as possible, comes the responsibility to be environmentally aware and, in particular, to ensure that any carbon emissions during the loading and transportation are minimised. The presentation outlines RasGas’s approach.

The transportation of LNG by the giant tankers designated Q-Flex and Q-Max – vessels with cargo capacities of the order of 215,000 m3 and 266,000 m3 , respectively – is discussed. A key point is that, although these vessels are much larger than the conventional carriers, the fuel consumption is almost the same, with obvious economic and environmental advantages. It is emphasised that carbon dioxide emissions to the atmosphere from the LNG cargo itself are minimal since the carriers are fitted with on-board facilities to liquefy the boil-off gas and return the LNG to the cargo tanks.

A proposal to retro-fit systems so that natural gas can be delivered to the existing diesel main engines is mentioned: LNG from the vessel’s cargo tanks will be vaporized and the gas used as the fuel. The benefits of replacing marine diesel fuel with gas are delineated, not only with respect to carbon emission reduction, but also to ensure that the legal restrictions on the sulphur content of a marine fuel are satisfied.

Finally, the Jetty Boil-off Gas Recovery Project (JBOG) is discussed. The project is a major attempt to reduce the BOG generated and flared at the Ras Laffan LNG terminal. It is remarked that greenhouse gas emissions can be substantially reduced and the recovered gas can be used to generate a significant percentage of the power required by the State of Qatar.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.20 Published: 19 December 2012 c 2012 Al-Tamimi, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Al-Tamimi T. Green shipping, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:20 http://dx.doi.org/10.5339/stsp.2012.ccs.20

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

The carbon conundrum: GCC perspectives Farid Benyahia* Department of Chemical Engineering, Qatar University, Doha, Qatar * farid.benyahia@qu.edu.qa

ABSTRACT The solution to the carbon conundrum does not seem to be within reach in the short or medium term, despite significant advances and knowledge gains in demonstration scale CCS facilities. This stems from the fact that currently carbon management has no binding policies and legal framework.

Without this legislation, it is unlikely that international cooperation in carbon trade and management would flourish. The situation is also exacerbated by doubts about the suitability of sites and global capacity to store captured CO2 . Sophisticated cost models have been developed for carbon capture and storage, and these indicate that cost reduction in the complete carbon value chain should be focused on the capture phase as this is the most energy intensive. However, there are uncertainties about properly costing carbon storage as this should involve search for suitable site location costs.

The GCC states have characteristics that make them one of the largest consumers of fresh water and energy in the world, and by default emitters of CO2 per capita. There are currently no demonstration or commercial scale CCS facilities in the GCC and in the short term, it is unlikely to be the case given that current carbon capture technologies favor coal rather than natural gas as fuel in power plants. It is also unlikely that underground carbon storage be considered in the short term, given the risk of CO2 plume migration that may displace brine in saline formations into strata containing hydrocarbon resources or potable. It is therefore imperative that substantial research be conducted to identify storage sites, reduce energy consumption in carbon capture and develop alternatives to CCS in the form of carbon conversion into useful products or minerals with low environmental impact. The GCC have tremendous opportunities to lead the world in carbon management given their strong experience in hydrocarbon processing. However, this may only be successful if agreed policies and legal frameworks are in place to facilitate a robust carbon pricing.

Keywords: carbon management, GCC perspectives in CCS, hydrocarbon economy, liability and risk, economics of CCS

http://dx.doi.org/ 10.5339/stsp.2012.ccs.21 Published: 20 December 2012 c 2012 Benyahia F, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Benyahia F. The carbon conundrum: GCC perspectives, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:21 http://dx.doi.org/10.5339/stsp.2012.ccs.21

Page 2 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

INTRODUCTION The GCC states are characterized by a number of unique features that make them quite distinct compared to other countries in the Middles East and North Africa (MENA) and indeed any other parts of the world. These features may be broadly defined as permanent and non-permanent. The permanent features include hot climate, fresh water scarcity and arid land and poor soil nutrients. The non-permanent features include vast hydrocarbon reserves and carbon based economies.

Over the next twenty years the countries of the GCC are likely to experience some of the fastest economic and energy-consumption growth rates anywhere in the world [1].

The GCC energy consumption has grown 74 percent since 2000, and is projected to nearly double its current levels by 2020 [2]. The current sources of energy mix for electricity generation is shown in Table 1.

Table 1. Sources of energy for domestic 1 consumption in the GCC. State

Natural gas

Oil

Bahrain Kuwait Oman Qatar K.S.A U.A.E

84.2% 37.4% 69.3% 75.3% 37.6% 82.4%

15.8% 62.6% 30.7% 24.7% 62.4% 17.6%

1 2

For electricity generation Source: International Energy Agency (2008)

Despite the Middle East and North Africa (MENA) region seeming energy-rich and holding 56% of the world proven oil reserves, it is on a downward trend in terms of energy security. MENA countries are approximately 60% more energy-intensive than OECD countries. Environmental degradation, resource depletion, limited conversion capacities and unbalanced regional distribution of fossil fuel resources, have had strong constraining effects on MENA economies. This has been exacerbated with the regionâ&#x20AC;&#x2122;s fresh water supply because of heavy reliance on desalination, in turn, imposing increasingly tough choices on resource allocation [3].

Despite an increase in population in the GCC states (made up of a significant expatriate manpower to drive the booming economies), the carbon emissions per capita are amongst the highest in the world. Tables 2 and 3 show recent trends in carbon emissions arising from energy consumption.

Table 2. Per capita carbon dioxide emissions from the consumption of energy (metric tons of carbon dioxide per person).

State/Year

2005

2006

2007

2008

2009

Bahrain Kuwait Oman Qatar K.S.A U.A.E

36 33 12 67 17 34

40 32 13 70 17 36

41 30 14 72 16 39

43 31 16 74 17 42

43 31 17 76 17 41

Source: US energy information administration (2010)

Table 3. Total carbon dioxide emissions from the consumption of energy (million metric tons).

State/Year

2005

2006

2007

2008

2009

Bahrain Kuwait Oman Qatar K.S.A U.A.E

25 77 31 52 405 140

28 77 36 56 406 155

29 75 38 59 396 172

31 79 44 61 426 196

31 84 49 64 438 194

Source: US energy information administration (2010)

The energy intensity of the GCC states includes a significant contribution from desalination plants that are typically coupled with power generation. When water consumption increases (which is

Page 3 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

currently the case), demand for power also increases and the carbon emissions naturally follow. It is instructive to notice that a great deal of the fresh water produced in the GCC is used for agricultural purposes.

The GCC nations became well aware of the challenges facing them as a result of the unique permanent and non-permanent features highlighted above and embarked on ambitious sustainability exercises. The best known examples of these were articulated in the Qatar National Development Strategy 2011–2016 and the Qatar National Vision 2030, where rational use of hydrocarbon resources and environmental protection constituted essential ingredients. Amongst these, carbon emission reduction is given particular attention. The global carbon conundrum is perhaps more complex in the GCC region given its excessive dependency on hydrocarbons to drive the economy and provide essential power for fresh water supplies and air conditioning during the hot months of the year. This paper attempts to highlight and explain the current outstanding issues preventing the full deployment of carbon capture and storage, and the GCC specific barriers and opportunities.

CARBON CAPTURE AND STORAGE: STATE OF THE ART AND GLOBAL HORIZONS State of the art in carbon capture There has been significant progress in technology development and costing models for carbon capture for power plants ahead of full deployment in the future, pending similar progress being made in underground storage and legal frameworks. The carbon capture technologies explored include post-combustion, pre-combustion and oxyfuel combustion. Sophisticated cost models were developed depending on the type of fossil fuel used and the degree of carbon capture integration within the plant. This progress has been largely led by industry given its vast experience in power plant systems and gas processing [4]. In summary, economics of carbon capture favor coal fueled power plants because more carbon is emitted from such facilities compared to gas driven power plants. It has been suggested that the capture and transport cost of CO2 from coal fired plants would be around 50 USD compared to 100 USD for natural gas [4]. Obviously this cost range needs regional adjustments. The cost of the full carbon value chain seems to be dominated by the cost of capture and compression accounting for as much as 80% of the total carbon capture and storage (CCS) cost despite uncertainties in the cost of underground storage. Extensive details of such models, as well as comprehensive details of the state of the art in carbon capture technologies, may be found in [4]. In general, it is the lack of carbon capture and storage (CCS) policy that makes it difficult to ‘‘price’’ accurately CO2 in the market place. It is well known that international money markets are very sensitive to policies and regulations.

Carbon storage state of the art The inter-governmental panel on climate change (IPCC) produced several useful documents aimed at helping decision makers on carbon matters. An important report by the IPCC includes a survey on global potential underground storage capacity for captured CO2 [5]. It can be seen from Fig. 1 that promising storage sites (shown as dark areas) are not uniformly distributed, that these sedimentary basins are not always close to power plants (usually located at close proximity to large metropoles).

Figure 1 shows that many parts of the globe completely lack suitable or even potential carbon storage sites, making it hard for the international community to exert any form of pressure on them to store CO2 from power plants, simply because they do not have such facility. The absence of policies and legal frameworks makes it practically impossible to reach agreements with countries that do have storage capacity.

In underground reservoirs, CO2 can be stored in porous rocks at a depth of more than 800 m in supercritical form under an impermeable caprock, in the top part of a water-filled reservoir. According to the international energy agency, deep saline aquifers offer potentially decades or hundreds of years’ worth of storage capacity with estimated 1,000-10,000 Gt of capacity available. This is currently the single most important underground storage potential. Around 920 Gt of CO2 could be stored in depleted oil and gas fields. Small leakages of CO2 may occur over an extended period of time, which may reduce the effectiveness of CCS as an emission mitigation option. This so-called ‘permanence problem’ is currently dealt with through field tests and through modeling studies.

Depleted oil and gas fields have contained hydrocarbons for millions of years and this makes them a relatively safe place to store CO2 provided exploration work did not entail excessive fracturing and

Page 4 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

Figure 1. Global prospectivity for captured CO2 storage [5].

other forceful forms of enhancing hydrocarbons extraction. The problem for such reservoirs is therefore if the extraction activity has created leakage pathways, and if abandoned boreholes can be plugged properly so the CO2 cannot escape. Many projects for natural gas storage and acid gas storage have worked well. Progress in modeling allows increasingly accurate forecasts of the long-term fate of the CO2 , which cannot be tested in practice.

Several natural phenomena, such as CO2 dissolution in the aquifer water, will reduce the long-term risk of leakage. The understanding of these phenomena is improving gradually, especially after successful operations of commercial scale facilities (in Salah, Algeria; Sleipner, Norway) and demonstration scale facilities (Frio, USA; Ketzin, Germany and Nagaoka, Japan).

CCS economics: not such a bright short term prospect Constraints for the full deployment of CCS remain. CCS for power generation has yet to reach the stage of commercialization, and is a long-term prospect rather than a short-term option. This is especially true for CCS from natural gas power generation; nearly all existing or planned CCS power plants worldwide are coal-fired. Moreover, because natural gas generation is 50 percent less carbon intensive than electricity from coal, there is less carbon to be captured from natural gas power plants.

Assuming a carbon price that provides an incentive for capture, the economic returns of carbon capture from natural gas plants, the predominant means of power generation in the GCC, are limited in comparison with those from coal power plants elsewhere. Anyhow, even in those markets that do have a price on carbon, the financial incentive is currently nowhere near adequate to justify investment in CCS for power-generation facilities.

One of the most significant uncertainties to the cost of CCS on a project level is the cost of CO2 storage. This is naturally due to the uncertainties associated with finding and appraising a suitable site to prove that CO2 can be safely stored in the required quantities. As experience in the oil and gas industry has shown, these activities can incur significant costs with no guarantees of reaching injection targets. In the same manner, for CO2 storage, significant investments can be made in finding and appraising a potential storage site only to find that it is unsuitable for any number of reasons, not limited to technical unsuitability. The costs associated with finding and appraising potential storage sites, whether they are successful or not, is referred to as the ‘‘finding cost’’, parallel with the ‘‘exploration and appraisal costs’’ for an oil and gas exploration venture.

These ‘‘finding costs’’ are site specific, and will vary widely between sites if they are: • Saline reservoirs or depleted hydrocarbon fields • Close to population centres • Rural onshore • Deep or shallow water offshore Critically, the economics of CO2 storage is driven by the fundamental geologic characteristic of the site under consideration, and emphasizes:

Page 5 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

• Containment (safety/security of storage); • Injectivity (rate at which CO2 can be injected into the reservoir) • Capacity (volume of CO2 that can be stored).

One of the main observations of current CCS-related work is that the issue of capture and compression has received a great deal of attention in the CCS value chain. However, the finding and appraisal of CO2 storage sites is the critical path technology in the CCS value chain, and can potentially be the key to proceed or not in early projects.

As far as depleted oil and gas reservoirs are concerned, the primary attraction is that they are usually well understood. They potentially offer early commercial viable storage. However, like all sites, they have their own challenges. Depleted oil and gas reservoirs may have both active and abandoned wells that could potentially act as leakage pathways to the surface. Detailed well integrity studies and risk assessment are required on a field-by-field basis, as with geology, no generalisation is possible.

Furthermore, the space available in depleted fields remains limited (compared to aquifers of a similar area) due to the presence of residual, un-produced hydrocarbons and likely pressure limitations caused by the field setting and complex depletion history. The primary advantage, as stated before, comes from the amount of upfront characterisation work that has been done on these formations during the asset’s life. This reduces a project ‘‘finding’’ costs quite considerably.

CCS economics gap The primary economic gaps to the implementation of CCS can be summarized by the following important points: • Insufficient financial incentive to implement CCS • High capital and operating costs and minimal experience with integrated operation on a large scale to reduce these costs • Availability of infrastructure to implement the technology • Limited geologic information for CO2 injection and its long-term safe storage A more effective financial incentive for the adoption of CCS among GCC nations is its potential application in enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Currently, many of the countries in the GCC increase the productivity of mature oil and gas fields by pumping in natural gas to increase well pressure. Given the projected spike in electricity demand in the region, and the corresponding increase in the use of natural gas supplies for power generation, the use of gas for oil recovery may become economically unfeasible. By pumping CO2 into declining oil wells in place of natural gas, the countries of the GCC can free up valuable volumes of hydrocarbons. The gas saved can then be used either for domestic power generation or for export, earning additional income. It is important to recognize that EOR/EGR is not long term CCS. Given the status of CCS described in the previous sections, what are the specific challenges and perspectives in the GCC? CARBON MANAGEMENT CHALLENGES AND PERSPECTIVES IN THE GCC Status of carbon capture and geological storage sites in the GCC region So far no public announcement has been made on an identified geological site in the GCC region for CO2 storage for a demonstration or commercial scale facility. Furthermore, no significant investment has been made to develop CO2 capture technologies from gas or oil fueled power plants. The plausible reasons for this lack of progress in CCS in the GCC region stems from the fact that the majority of power plants are fueled by natural gas, considered as a clean fuel and having considerably less carbon emissions than coal. In addition, carbon capture studies elsewhere have shown that economics are more favorable for coal than for natural gas as more CO2 is emitted from the former than from the latter. This is seen as a serious setback and negative incentive. Hence, if carbon capture has no incentive for development and investment, it is highly unlikely that carbon storage demonstration units would even be considered. However, as was pointed out in the introduction section of this paper, there is a genuine intention in the GCC region to promote sustainability and

Page 6 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

environmental protection. This was for example articulated in the Qatar National Development Strategy 2011–2016. However, the pace of future CCS deployment in the GCC region may be hindered by insufficient understanding of sequestration resource potential and infrastructure. Just like elsewhere in the world, the GCC states currently have no policies or legal frameworks to regulate future CCS operations. This makes it difficult to ‘‘price’’ CO2 in the market place.

Real challenges in the GCC region The GCC permanent characteristics cited in the introduction indicate that these countries will need to continue to consume considerable amounts of energy to maintain the standard of living currently enjoyed, regardless of the source of energy. In the short term, it is likely that these sources will continue to be oil and natural gas. Hence it is quite understandable to accept the feeling of discomfort at prospects that injected CO2 plumes in underground saline formations may displace brine into strata containing resources like hydrocarbons or potable water. Furthermore the known rock acidification and fracturing practices to enhance production only add to the risks associated with CO2 leakage in the future, especially for carbonate formation known to prevail in the GCC region.

On the societal side, the GCC nations currently enjoy one of the highest and most lavish standard of living in the world with all the environmental consequences that ensue. For instances, in some GCC states citizens do not pay for the electrical power or water consumed, thus eliminating any incentive to reduce waste in these precious resources. It is well known that water consumption in the GCC is amongst the highest in the world despite water being produced in energy intensive desalination plants. The notion of global climate change does not seem to be a major concern in the GCC as most people think that in an arid region, the climate cannot get any worse. Other aspects of climate change consequences are hardly discussed or even understood in general terms.

Carbon management opportunities in the GCC The GCC region has accumulated considerable oil and gas exploration and processing experience in the past four decades that can be put into useful practice in CCS development. For instance, post-combustion carbon capture is very similar to natural gas sweetening and acid gas removal, and may be an area where GCC states can make impressive efforts in cost reduction. In addition, several GCC nations including the United Arab Emirates, Saudi Arabia and Qatar have pledged substantial financial support for research on sustainability and environmental protection.

Energy efficiency, renewable sources and lifestyle The GCC countries enjoy one of the world’s most abundant solar resources. Estimates of the solar potential in the GCC put the region’s annual average global radiation available to photovoltaic cells at about 6 kWh/m2 /day. Estimates of the direct normal irradiance (DNI, available to solar concentrating technology) are around 4.5 kWh/ m2 /day [6]. These figures indicate that a land area of approximately 1,000 km2 , representing about 0.2 percent of the GCC may be covered with photovoltaic cells at 20 percent efficiency, could produce 438 TWh every year which is more than the 400 TWh typically consumed by the region [6]. Nations of the GCC have either initiated, or committed to, investments in solar projects, with solar photovoltaic (PV) and concentrated solar power (CSP) being the main technologies of choice. Other potential solar-related applications applicable to the region include solar derived bioenergy and solar-generated hydrogen.

There is a need to sustain campaigns for energy and water saving in the GCC as the consumption of these ranks amongst the highest in the world. Whilst PV solar energy may not be immediately useful for large oil and gas industries, it certainly has an outstanding potential for homes, especially for lighting and small electrical appliances. In remote housing compounds, solar energy (both PV and CSP) may prove to be not only economic in the long term, but actually essential. The massive expansion of oil and gas industries in the GCC was also accompanied by a substantial release of low grade heat into the environment. There is a need to evaluate both quantities and useful applications of such waste heat, especially in water desalination.

Carbon conversion opportunities Carbon conversion is gaining more and more attention as an alternative to underground storage where this is not feasible in the short or medium term or at all. Given that the CO2 molecule is quite

Page 7 of 8 Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

stable, it is anticipated that a limited but effective number of processes to convert CO2 into a useful or harmless form be considered. The literature already identified biofixation [7], catalytic conversion [8] and low temperature mineralization [9] as promising ways to usefully convert CO2 into a valuable product or into a harmless solid form. Given that the GCC countries enjoy sunshine for most of the days in the year, there are opportunities to exploit this free energy source to convert captured CO2 into hydrocarbons through microalgae growth. The process engineering experience accumulated in the past three decades in the GCC’s gas processing industries can also be put into action for the development of selective catalysts to activate and convert CO2 into hydrocarbons. This new industry can be fully integrated with existing petrochemical industries to enhance energy efficiency.

CONCLUSIONS The final solution to the carbon conundrum seems to be out of reach in the short term mainly because of the lack of policies and legal framework. A great deal of knowledge has been gained from demonstration CCS facilities in some countries. However, cost, risk management and liability prevent full CCS deployment. In addition, there are doubts about the global storage capacities to absorb all potential captured CO2 from power plants worldwide. In the GCC states, no geological sites have been identified for demonstration or commercial CO2 storage. Some of the reasons for this lack of initiative include the cost of CO2 capture that currently favors coal as fuel compared to natural gas, and the reluctance to experiment in operational oil/gas fields that are mainly well away from depletion. There are indeed genuine risks that need evaluating. At some point in the future, the GCC nations will need to rely on their capacity to address the carbon conundrum given their specific characteristics. The following recommendations may be put forward to assist in gaining experience ahead of future CCS deployment or application of alternative carbon management schemes in the GCC: CCS related • Geological potential for sequestration • Capture technologies • Site characterization • Monitoring and verification • Risks and risk management • Remediation and mitigation • Economic consideration • Regulatory and statutory issues Alternative carbon management related • Energy efficiency gains in process plants • Utilization of low grade waste heat • Carbon conversion into useful products • Low temperature mineralization of carbon • Solar energy as concentrated and photovoltaic • Citizen education on minimizing energy and water consumption ACKNOWLEDGEMENT This publication was made possible by an NPRP award [NPRP 08-336-2-123] from the Qatar National Research Fund (a member of Qatar Foundation). The statements made herein are solely the responsibility of the author

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REFERENCES

[1] Ebinger C., Hultman N., Massy K., Avasarola G. and Rebois D. Options for low carbon development in countries of Gulf Cooperation Council. Energy security initiatives at Brookings: Policy brief. 2011;11-02: [2] Kinninmont J. The GCC in 2020: Resources for the Future, Economist Intelligence Unit. 2010.

[3] Schwab K. The middles east and north africa at risk 2010, World Economic Forum GlobalRisks, Marrakesh, Morroco, 2010.

[4] Global CCS Institute. Strategic Analysis of the Global Status of Carbon Capture and Storage, report 2: Economic Assessment of Carbon Capture and Storage Technologies, 2009.

[5] IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge University Press. 2005.

[6] Al-Naser W.E. Solar and wind energy potential in GCC countries and some related projects. J Renewable Sustainable Energy. 2009;1: [7] Lam M.K. and Lee K.T. Microalgae biofuels: A critical review of issues, problems and the way forward. Biotech Adv. 2012;30:673â&#x20AC;&#x201C;690.

[8] Omae I. Aspects of carbon dioxide utilization. Catalysis Today. 2006;115:33â&#x20AC;&#x201C;52.

[9] Benyahia F. The Carbon Conundrum: Challenges and opportunities in the Gulf region, Downstream Technology Conference, Kuwait (Feb 2012).

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Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012 Guest editor: Howard JM Hanley

Review article

QAFAC: Carbon dioxide recovery plant Khalid Mubarak Rashid Al-Hitmi Qatar Fuel Additives Co, Ltd., Doha, Qatar

ABSTRACT This short report outlines Qatar Fuel Additives Company (QAFAC) plan to reuse the carbon dioxide emitted from their methanol plant. It is estimated that 500 tn/day of CO2 will be recovered from its Methanol Reformer stack which will be injected into the Methanol Synthesis unit to enhance the production capacity. The Recovery Unit will be constructed under license from MHI (Mitsubishi Heavy Industries, Japan) and will be a specific and novel application of CO2 recovery focused to optimize methanol production. Overall, since operations are designed to produce 982,350 tonnes per annum of methanol and 610,000 tonnes per annum of MTBE, the QAFAC Plant will be one of the worldâ&#x20AC;&#x2122;s largest commercial-scale CO2 capture facilities.

http://dx.doi.org/ 10.5339/stsp.2012.ccs.22 Published: 19 December 2012 c 2012 Al-Hitmi, licensee Bloomsbury Qatar Foundation Journals. This is an open access article distributed under the terms of the Creative Commons Attribution License CC BY 3.0 which permits unrestricted use, distribution and reproduction in any medium, provided the original work is properly cited.

Cite this article as: Al-Hitmi KMR. QAFAC: Carbon dioxide recovery plant, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:22 http://dx.doi.org/10.5339/stsp.2012.ccs.22

Page 2 of 3 Al-Hitmi, Sustainable Technologies, Systems and Policies 2012.CCS.22

THE METHANOL PLANT A schematic of the methanol production from natural gas feedstock is shown in Fig. 1.

METHANOL PLANT BLOCK DIAGRAM Inlet Hg Removal Compression Vessel Natural Gas from QP-NGL

Metering Station

Feed Preparation

Hydrodesulfurization

Fuel Gas

Flue Gas

Steam

CDR Plant

Steam Reformer

Saturator

Waste Heat Section

Methanol Synthesis

De-Saturator

Fuel Gas

Reformed Gas Synthesis Gas

MeOH Catch Pot Crude Tank

Recirculator Compressor

Crude MeOH

Syn Gas Compressor

Condensate

ARC Convertor

CO2 Gas Check Tanks

Flare

Pure MeOH

MeOH

Heavy End Column Light End Column

Steam Reforming

Fusel Oil

Distillation

Water

Slop Tank MeOH Storage Tanks

To Export Product Storage Tanks

To MTBE To QAFCO

Figure 1. A schematic of the methanol production from natural gas feedstock.

Shown are four stages. In outline: • Feed Purification: The hydrocarbon feed contains mercury, which is completely removed at the inlet of the plant. Sulphur is completely removed in the desulphurization section.

• Reforming Section: The desulphurized hydrocarbon is reformed together with steam to produce the synthesis gas containing hydrogen, carbon monoxide, and carbon dioxide.

• Methanol Synthesis Section: The synthesis gas is, after compression to a pressure of about 7,700 kPaG, converted into methanol by a catalytic reaction. Finally, dissolved gases and impurities are removed from the methanol by distillation.

• Distillation Section: The crude methanol is distilled to separate the product methanol from dissolved gas and the impurities.

This procedure is standard and based on the reversible reaction at the reforming stage: CH4 + H2 O ! CO + 3H2 .

And, for the methanol synthesis, one has, 2H2 + CO ! CH3 OH. Further, however, carbon monoxide will react with water in the reforming process to yield carbon dioxide and hydrogen: CO + H2 O ! CO2 + H2 .

At the synthesis stage, the CO2 reacts with excess hydrogen to synthesize methanol, CO2 + 3H2 ! CH3 OH + H2 O. It turns out that about 50% of the carbon oxides contained in the synthesis gas is converted into methanol per pass under the condition of excessive hydrogen. Hence, the unconverted synthesis gas is recycled as indicated in the figure.

Page 3 of 3 Al-Hitmi, Sustainable Technologies, Systems and Policies 2012.CCS.22

THE CO2 RECOVERY PLANT The flue gases from the reformer are vented to the atmosphere at a rate of ⇠600 to 620 tn/hr. Since the flue gas composition during normal plant operation on a volume/mol percent basis is CO2 -5.49%, O2 -1.83%, N2 -65.90% and H2 O-26.78%, approximately 55 tonnes of CO2 are emitted per hour. But, the chemistry indicates that adding CO2 to the synthesis gas mixture can increase the capacity of the methanol plant due to excess hydrogen available in the synthesis loop. Clearly, then, it would be advantageous to recover and use a significant proportion of the waste CO2 . This is the described project.

MHI’s CO2 recovery technology is known as the KM CDR Process R . It uses MHI’s proprietary KS-1 solvent for CO2 absorption and desorption which MHI jointly developed with Kansai Electric Power Co., Inc. MHI’s technology features considerably lower energy consumption compared with other processes and has won high evaluations for its performance. It is noted that, following the first plant in Malaysia in 1999, MHI has licensed and delivered its CO2 recovery technology to nine commercial CO2 recovery plants around the world with another plant under construction.

As indicated in the figure, the flue gas will be transferred from the Reformer Stack to the CO2 Recovery Plant. As the flue gas temperature is ⇠230 C, and thus too hot for feeding to the CO2 absorber, it is quenched by water then mixed with the KS-1 solvent on a packed bed. The CO2 free gas is washed and emitted to the atmosphere. The CO2 rich gas is then sent to a packed column regenerator where the solvent is heated and the CO2 is stripped from the column. The regenerated CO2 is washed to remove any traces of solvent, compressed, and send back to the Methanol plant to mix with the synthesis gas.

The key result is that, not only is the capacity of the Methanol Plant increased, the atmospheric CO2 emission is reduced from the approximately 55 tn/hr to about 34 tn/hr, a reduction of 38%.

SUMMARY Established in 1991, QAFAC is a joint venture between Industries Qatar, OPIC Middle East Corporation, International Octane LLC and LCY Middle East Corp. The Company commenced operations in 1999.

With the initiation of this project – targeted for completion in October 2014 – QAFAC aims to optimize the utilization of the country’s vast hydrocarbon resources. Furthermore, the project demonstrates the intent to be a leader in cutting industrial greenhouse gas pollution, and to play a front line role as an environmentally conscious company.

[continued from back cover] CCS from industrial sources Paul S Fennell, Nick Florin, Tamaryn Napp, Thomas Hills

Introduction to market challenges in developing second-generation carbon capture materials Jason Matthew Ornstein

Shipping and CCS: A systems perspective N Mac Dowell, N Shah

Green shipping Talal Al-Tamimi

The carbon conundrum: GCC perspectives Farid Benyahia

QAFAC: Carbon dioxide recovery plant Khalid Mubarack Rashid Al-Hitmi

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We hope you enjoy this issue and spread the word of the journal to your colleagues. Regular article submissions can be made to this open access journal at http://www.editorialmanager.com/stsp Chris Leonard Editorial Director QScience.com

TABLE OF CONTENTS: SPECIAL ISSUE ON CARBON CAPTURE AND STORAGE (2012) Preface and overview Howard JM Hanley

Carbon capture: An introduction Howard JM Hanley

Industrial requirements Patrick Linke

Pre- and post-combustion Fedaa Ali

Industrial procedures and problems Fedaa Ali

Alternatives to amine-based capture & new technologies Farid Benyahia

Transport Farid Benyahia

Economic and social issues Iain Macdonald

Carbon capture and storage: The way ahead Geoffrey C Maitland

Carbon capture and storage: The industry viewpoint Marcus Schwander

Life Cycle Assessment of the natural gas supply chain and power generation options with CO2 capture and storage: Assessment of Qatar natural gas production, LNG transport and power generation in the UK Anne Korre, Zhenggang Nie, Sevket Duncan

Gas turbine related technologies for carbon capture R Peter Lindstedt

An overview of carbon capture technology Bruce R Palmer

The Lacq industrial CCS reference project (France) Jacques Monne

Ionic liquids as novel materials for energy efficient CO2 separations Richard D Noble, Douglas L Gin

Metal-organic frameworks and porous polymer networks for carbon capture Julian Patrick Sculley, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe Zhou

[continued on inside back cover]