carbon capture & storage

SPECIAL ISSUE ISSN: 2220 - 2765

Capture & StorageWorkshop held at Texas A&MUniversity at Qatar, April 2012

Guest Editor: Howard JM Hanley

CARBON

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

Qatar National Research Fund

Sponsored by:

Editor:

Howard J.M. HanleyTexas A&M University at Qatar, Doha, Qatar

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http://dx.doi.org/10.5339/stsp.2012.ccs.1

Published: 17 December 2012c� 2012 Hanley, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.

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

Editorial

Preface and overviewHoward JM Hanley

Texas A&M University at Qatar, Doha,Qatar 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 recentlyattracted 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 QatarPetroleum. The seed was the opening of the November 2010 First Annual Doha Carbon and EnergyForum at which Qatar Petroleum announced that it had officially submitted a proposal to the UnitedNations for a new methodology that could enable carbon dioxide capture and storage in geologicalformations 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 technicalinnovations in the field. But we wanted the program to provide more than concrete information; wewanted a forum for debate, even controversy. The format was thus set up to juxtapose the industrialand academic viewpoints and to emphasize the questions and comments triggered by the invitedtalks. 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 thisapproach 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 EnergyAgency and the Global CCS Institute. Yet the results of this workshop showed that several questionsdid not always have definitive answers because the situation is often unclear; it is certainly in a stateof flux. This is not a negative comment; rather it reflects the challenges to be overcome if CCS is goingto 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, theinterface between research and technical innovation with commercial cost and investment risk was arecurring theme throughout the two days. There is a long way to go. An example of how far, and atwhat cost, is typified by the discussions related to the Canadian SaskPower Boundary Dam CCSproject 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 about2500 coal-fired power stations (7000–10000 units) operating in the world. Clearly the cost ofretrofitting and/or replacing these would be staggering. [Parenthetically, as several speakersremarked, there are only eight commercial integrated CCS facilities currently active, none of whichdirectly 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 theunderstandable 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 areconcerned about the environmental impact of carbon dioxide storage, and are very suspicious thatthe costs associated with CCS will filter down to them.

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

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

Overall, then, the issues surrounding carbon capture and storage are indeed challenging butfascinating, presenting exciting opportunities for a smorgasbord of disciplines—basic chemistry,thermodynamics, chemical engineering, geology, economics, politics, and more. As speaker Zhouremarked at the close of the Workshop: ‘‘There are a lot of experts out there and lots was learned overthese 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, whorealized that Doha was an ideal venue for a CCS workshop. His suggested topics were the basis forthe program, and he coordinated the speakers from Imperial College who played such an importantrole 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 atQatar (TAMUQ) was greatly appreciated, as was the considerable administrative help offered by thestaff of that Office. I am most grateful to Carol Nader, Brady Creel, and their colleagues for organizingthe logistics of the Workshop. Iain and I owe a very special debt of gratitude to Rola Abou Ghaida, ofthe TAMUQ Department of Research and Graduate Studies, whose efficiency and enthusiasm inhandling the overwhelming number of inquires, formatting the program details, and helping in somany ways, made our task manageable. And, of course, the Workshop could not have taken placewithout 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 ofthis important workshop and are always keen to support such initiatives that share ideas andhighlight 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 NationalVision 2030, and the strides taken to advance sustainability practices.’’ We owe Dolphin Energymuch.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 Workshopfrom a concept to completion. Dr. Omar el Farouk Boukhris has remarked: ‘‘We, at the Qatar NationalResearch Fund, recognized immediately the relevance of this workshop and were pleased tounderwrite the workshop from its conception. The Qatar National Research Fund is the sole nationalresearch funding agency in the state of Qatar. By supporting competitive research in all class ofsociety and in many scientific disciplines, the QNRF is an arm of the Qatar Vision 2030. Clearly, thenational priorities are of paramount importance. Since Qatar is classified among the very highest, ifnot the highest, per capita emission countries, it is natural that we need to discover and implementnew ideas targeting carbon capture and storage with a focus on environmental impact and costreduction. We truly believe that future research will be driven by cross-disciplinary efforts such as youare 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 Universityat Qatar and Imperial College London are so critical because they help highlight the importance ofadvancements in technology, in this case carbon capture,’’ said Bart Cahir, President and GeneralManager. ‘‘At ExxonMobil, we have been active in developing and applying carbon capture andstorage component technologies since the 1980s with the understanding that breakthroughtechnologies can help keep pace with rising global energy demand while also reducing theenvironmental 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 involvedin the program. Philippe Julien, Director, Total Research Center Qatar, had these kind words to say: ‘‘Ithas been a pleasure for Total to be a sponsor of this workshop organized by TAMUQ and ImperialCollege London on such an important subject. Carbon Capture constitutes a real stake for the wholepetroleum industry in general and for Qatar in particular. Total is committed to reducing the impact ofits activities on the environment, and especially its greenhouse gas emissions in the atmosphere. AtTotal, we have been developing a fully integrated research CCS pilot project in France, and it has beena pleasure for us to share what we have learn from this interesting project with our academic andindustrial Qatari partners.’’


We are very appreciative of the considerable help offered by QScience.com, who monitored theprogramme and changed the drafts into a publishable product. We are proud to have made acontribution to this innovative and enterprising organization which has been heralded by OutsellOutlook as one of the top 31 information industry ‘‘companies to watch’’ in 2012; a list of 31 whichincludes Adobe, Google, and Apple.Again, to all these individuals and institutions, my grateful thanks.

ORGANIZING COMMITTEEDr. 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 QatarDr. Patrick Linke, Chemical Engineering Program, Texas A&M University at Qatar

DISCUSSION REPORTERSDr. Apostolos Georgiadis, Imperial College, LondonMahmoud Abouseada, Texas A&M University at QatarHicham El Hajj, Texas A&M University at QatarSeifullah El Haraki, Texas A&M University at QatarAna Rodriguez, Texas A&M University at QatarMohamed Ajmal Abdul Salam, Texas A&M University at QatarMakram Sarieddine, Texas A&M University at Qatar

OPEN ACCESS


Published: 17 December 2012c� 2012 Hanley, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Meeting report

Carbon capture: An introductionChair: Howard JM Hanley

Texas A&M University at Qatar, Doha,Qatar

INTRODUCTIONMr. Khalid Mohammed Al-Hitmi (Qatar Petroleum), and Dr. Omar el Farouk Boukhris (Qatar NationalResearch Fund) gave the introduction and set the stage for what followed by emphasizing a crucialconclusion of the Workshop: that the Carbon Capture Storage (CCS) issue cannot be resolved withoutserious 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 morningthat I participate in this Carbon Capture Workshop organized by two of the academic and researchorganizations engaged here in Qatar in the area of carbon capture and storage. Indeed, the issue ofcarbon capture and sequestration has been an area of focus for us in Qatar Petroleum, along withsome of our partners here in Qatar, for some time now, as evidenced in our support of governmentalefforts at 2010 COP (United Nations Climate Change Conference) 16 in Cancun, Mexico and at 2011COP17 in Durban, South Africa, for inclusion of carbon capture and storage in geologic formation asan approved technology under the ‘‘Clean Development Mechanism’’; as well as our efforts in ouroperations to move forward in planning some of the necessary steps required for the future carboncapture and storage activities. As Qatar will be hosting the upcoming COP18, it is very timely to behere 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 technologicalchallenges and opportunities, which will be highlighted by the next speaker. But to emphasis themagnitude of the problem and the size of the opportunity that this technology can address, I wouldlike to just mention that, by some estimates, human activities in the first 20 years of this century willbe 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 ofclimate change and carbon release, the time will come when this issue will be firmly back as anurgent 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 implementrequired changes and establish new operational norms which meet both new regulatory andenvironmental 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 concentratedefforts by all stakeholders, we will be able to face the challenges ahead and address what will berequired of our industry in the future. Therefore, I look forward to the successful start of this workshopand wish you all the best. Thank you! ’’

Dr. Omar el Farouk Boukhris introduced the Executive Director of the Qatar National ResearchFund, 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 sponsorof this carbon capture workshop, it is my pleasure to be here today to contribute to the success of theendeavor.’’ He outlined the major role the Qatar Foundation’s Research Funding agency (QNRF) hasCite this article as: Hanley HJM. Carbon capture: An introduction, Sustainable Technologies,Systems and Policies 2012 Carbon Capture and Storage Workshop:2http://dx.doi.org/10.5339/stsp.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 lastthree years on financing and sponsoring research projects related to carbon capture. He listed only asample of the topics that the NPRP has supported:

1. capture of carbon dioxide from natural and effluent gas streams and its conversion2. theoretical and experimental study of asphaltene deposition during CO2 injection in Qatar’s oil

reservoirs3. CO2 capture and photo-conversion to a renewable fuel4. emission free co-production of carbon nanotubes and hydrogen via concentrated solar energy5. CO2 mineralization and reject brine management through chemical reaction6. 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 researchon Carbon Capture and Storage, and Boukhris answered several questions on the operation of theProgram.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 researchefforts. He told the audience that while sixty-five percent of the funds awarded for a given project isrequired 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 asImperial College, University of Toronto, Colorado School of Mines, Arizona State University, Universityof 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 thecarbon capture and storage problem.’’

PRESENTATION

Carbon Capture and Storage—The Way AheadGeoffrey C. MaitlandDepartment of Chemical Engineering, Imperial College, London, UKThe 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 thewaste gas streams of power plants and industrial processes. This stage accounts forabout 80% of the overall cost of the CCS process so is the area where efficiency andcost improvements will have the greatest future impact. The major drivers for continuingto use fossil fuels for most of this century are first considered and the need toimplement CCS as one of many measures to mitigate carbon emissions. Current targetswill require a commercial CCS capacity to remove about 10Gte CO2 pa by 2050. Theoverall features of CCS processes are described – capture, compression and transport,sub-surface storage – covering the main capture options and the three main types ofstorage site (deep saline aquifers, depleted oil and gas reservoirs and unmineable coalseams). The current status of large-scale CCS demonstration projects is reviewed. Themain classes of carbon capture technologies are then described, both those currentlycapable of large-scale deployment and those in development for the future. Finally themain challenges facing CCS, to make it a globally-deployed commercially viabletechnology, are summarised and suggestions made for future developments in the cleanrecovery and use of fossil fuels which combine CCS with sub-surface processing.

PRESENTATION

Carbon Capture and Storage: An Industry ViewpointMarcus SchwanderInnovation R&D Manager—Qatar Shell Service Companies


A brief overview of the current status of the carbon capture and storage (CCS) issue ispresented from the industrial viewpoint. It is pointed out that it is estimated that fossilfuels will still meet at least 65% of world energy demand in 2050 to supplement theanticipated deployment of alternative lower-CO2 producing sources of energy: efficientand economic methods for CCS are therefore essential if the generally accepted requiredreductions 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 theirsolution is outlined. For instance, Shell’s work through its subsidiary CansolvTechnologies is discussed: Shell is involved in the 2012 piloting of its 2nd generationpost-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 costreduction, lower amines emissions and energy efficiency breakthroughs.

DISCUSSIONThe talks ofMaitland and Schwander outlined the background of the carbon capture and storagetopic from both an academic and an industrial viewpoint, and touched on most of the points raisedand expanded throughout the sessions that followed. In particular, the audience were introduced tothe 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 wasexcluded merely because he wished to emphasize the problems with respect to the hydrocarbonindustries, but Al-Kuwari’s remark did remind the attendees that CCS is a pervasive issue whichimpacts most industries, those related to iron and steel and cement production – each of whichcontribute 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 andMaitland responded as follows:

‘‘ I think the efforts for commercialisation have been quite so far have been quite poor inthat little has changed in the last decade, especially since any progress would not haverequired any major technological changes. As an example, the Sleipner North Seaproject, largely driven by the carbon tax implemented by Norwegian government, wasinitiated in 1996, and thus has been around for sixteen years.

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

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

Niall Mac Dowell, Paul Fennell and N. Shah (Imperial College) submitted additional material toexpand on Maitland’s comment.

‘‘This (lack of progress) is odd in light of the fact that the technology for one of the mostpromising CO2 capture technologies, amine scrubbing, was first patented in the 1920s.Further, the concept of injecting (or sequestering) captured CO2 in partially depleted oilwells was extensively practiced in the 1960s–1970s, as part of enhanced oil recovery(EOR) operations, and several commercial CO2 capture plants were constructed in theUS by the late 1970s and early 1980s.’’


[see, for example, the comments in the presentation of Bruce Palmer (Texas A&M University atQatar ) later in this volume.]Adel Ahmed Albuainain (Dolphin Energy, Qatar ) remarked that there are many current initiatives

in renewable energy, and askedMaitland if he thought they have been taken into considerationhere.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 energysupplied from renewable sources. This, however, may very well change by more acceleratedinnovation, 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 inMaitland’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 until2050, the ‘‘Blue’’ lower limit assumes the goal of a 50% carbon reduction is achieved.) Theprojections are speculative but the key point is made: namely, that CCS alone will not be enough toreduce levels of atmospheric carbon to the acceptable level. The target is 20% of the optimalreduction – 10Gt pa – but, as pointed out byMaitland, even this will be a tough challenge given thecurrent rate of progress. One can, however, say with certainty that fuel and feedstock switching willplay a major role—in fact there is already evidence that the increased use of natural gas has alreadyhad an impact on atmospheric carbon reduction. Related to this, Patrick Linke (Texas A&M Univ. atQatar ) 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 themore efficient use of energy. For the foreseeable future, fossil fuel is envisioned to be byfar the major energy source. Energy efficiency will obviously reduce carbon emissionsfrom fossil fuel use directly. Looking into the future, utilizing energy more efficiently willalso benefit the introduction of alternative energy sources, the inefficient use of whichtypically proves rather costly.A major energy user is the industrial sector. Here, energy efficiency gains can beachieved by developing and installing more efficient technology components andequipment. More importantly, industrial energy efficiency can be enhanced significantlythrough better planning and policy to stimulate energy recovery and reuse at asystems-wide level. Hence, integrated planning of facilities, both at the level of anindividual process or plant, but also at a wider level leading to realization of theconcepts of eco-industrial parks will be vital activities in the future. Such approaches tointegrated design hold significant promise to reduce emissions at a relatively low cost


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

Maitland again emphasised that we need a portfolio of carbon mitigation measures over the next50 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’ssurface (as discussed during his talk on Day 2). Those parts of the world not blessed with suitablestorage sites will have to emphasise CO2 conversion procedures and one can expect that only afraction of their total emissions can be so converted. Thus, there should be a particular pressure onthose countries that do not have suitable geological sites to diversify their portfolio of energygeneration: improvements in energy efficiency, system integration, and a substantial switch torenewable 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 combinedwith financial incentives and legislative requirements to encourage improvedtechnologies. The cost of CO2 mitigation associated with such an emphasis can beexpected to be very competitive in sectors where a significant infrastructure investmentwould be required in order to derive true benefits from more speculative efforts. In asense, it is disappointing that the projected dominant contributor to carbon emissionreduction has not been given due attention in a way similar to what the currentworkshop seeks to achieve for CCS.’’

Maitland showed a slide (Fig. 2) which lead to several remarks:

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 dayHuge volumes – so not likely to be the whole story but could contribute 1-3 Gt carbon/yr...or ~10 Gt CO2 paCosts: 2-3 cents/KWh for electricity for capture and storage;$40-100 per tonne CO2 removed – shackley and Gough, 2006

Some numbers...

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 wereinjected, would be equivalent to 700 million barrels of oil a day, especially if that number iscompared to the current daily oil production of around 85 million barrels.Hanley (Texas A&M Univ. at Qatar ) submitted a question toMaitland 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). Doyou have comments relating these costs to the Carbon Taxes either in place, or proposedby 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 beequivalent 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 figuresquoted cover both capital and running costs for the overall CCS process. He noted that carbon tradingprices have fluctuated wildly—for instance the EU trading price was close to 20 euros per tonneCO2 in mid-2011 but has recently plummeted to 7 euros. In its 2012 annual GHG Market SentimentSurvey of EU regulators, Price Waterhouse Cooper found that 80 percent of respondents were infavour of cutting the supply of trading permits in a bid to boost carbon prices to a level thatencourages firms to invest in clean technology, including CCS. They estimated that European carbon


prices could treble from the current levels to 20 euros ($25) over the next eight years if Europeangovernments 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 thetax rate to $35 per tonne in June 2012 in an attempt to encourage companies to invest in CCS andother carbon mitigation technologies. This combination of upward trends in carbon charges suggeststhe gap between clean technology costs and financial incentives/charges will close over the next5–10 years. A major increase in commercial scale implementation, however, still requires majortechnological advances to bring the capture/compression costs down significantly to make CCSroutine at $30–40 per tonne. Schwander’s reply was:

‘‘At this stage, industrial capture and storage costs are still high whilst CO2 prices arevery uncertain, thus making CCS business cases very difficult to quantify. CCS projectsrequire a sustained CO2 pricing model (via carbon trading or otherwise), which results inCO2 prices that are high enough to justify commercial investment. Further, the reportedcosts of CCS vary strongly due to differences in location and the type of capture systeminvolved. As discussed in my talk, commercial scale demonstrations across the full CCSspectrum – from capture through compression/transport to CO2 injection andsurveillance, with investigations of the next generation of capture techniques – arerequired to drive the industry up the learning curve, but down the cost curve to below100$/tCO2.’’

An aside question was later submitted relating to the often-quoted statement that CO2 emissionsare currently about 30 Gtpa. Several authors refer to this number as the ‘total anthropogenicemissions.’ The public perception, however, is that the figure refers to energy-related carbon dioxideresulting primarily from the combustion of fossil fuels. But shown (Fig. 3), for instance, is a pie chartdepicting 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 isaround 40% of the 30 Gtpa?Maitland responded by saying that one runs into semantics but a betterfigure – based on this chart – would be 66.3% if we define ‘fossil fuel combustion’ as that used forenergy supply + transportation fuels + fossil fuels burnt in industrial processes + heating ofbuildings.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 fromhis experience and recounted his involvement in a clean-coal project in Australia on CO2 separationthrough coal gasification and the subsequent sequestration. He estimated that it would cost aroundone billion US dollars to get this project to a level needed to even start demonstrations on anindustrial scale. He note that this figure was consistent with an estimate for a power plant upgradediscussed by his colleague, Niels Fabricius (Qatar Shell) in a later talk. He further reminded theaudience that the underpinning research is also extremely costly and cannot be undertaken withoutsubstantial 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


perhaps could be the most efficient and cost effective. She asked if Schwander had any comment onthat. Robert Moene (Shell) replied that Shell is involved in a small project on chemical looping butcalcium processes are not in the scope at this stage.Martavaltzi again offered her opinion that itwould 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 implementedover a relatively short time scale. He, however, reaffirmed that Shell is investing widely, especiallythrough 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 – 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.

Power generation without CCS

CO2 price

Number of installations

Deployment

Demonstration

Discover and developTe

chno

logy

cos

t

Earlier deployment through demonstration

4/8/2012 18

Figure 4. Slide from Schwander’s presentation.

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

NOTESAll presentations referred to in this article are available as ‘Supplementary Material’ online athttp://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.

http://www.qscience.com/toc/stsp//CCS+Workshop

http://www.iea.org/techno/etp/ETP_2008_Exec_Sum_English.pdf

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

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Published: 17 December 2012c� 2012 Linke, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Meeting report

Industrial requirementsChair: Patrick Linke

Texas A&M University at Qatar, Doha,Qatar PRESENTATION

Life Cycle Assessment of the Natural Gas Chain and Power Generation Optionswith CO2 Capture and StorageAnna Korre, Zhenggang Nie, and Sevket DurucanDept. of Earth Science & Engineering, Imperial College, London, UKFossil fuel based power generation technologies with/without CO2 capture offer anumber of alternatives, which involve different fuel production and supply, powergeneration and capture routes with varied energy consumption rates and subsequentenvironmental 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 fuelsupply and power production systems and ensure that a reduction in greenhouse gas(GHG) emissions does not result in increases in other environmental impacts. Besidesenergy and non-energy related GHG releases, LCA also tracks various otherenvironmental emissions, such as solid wastes, toxic substances and common airpollutants, as well as the consumption of other resources, such as water, minerals andland use. In this respect, the dynamic LCA model developed at Imperial Collegeincorporates fossil fuel production, transportation, power generation, CO2 capture,CO2 conditioning, pipeline transportation and CO2 injection and storage, and quantifiesthe environmental impacts at the highest level of detail, allowing for the assessment oftechnical and geographical differences between the alternative technologiesconsidered. The life cycle inventory (LCI) databases developed model the inputs andoutputs 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 mannerwith a clearly arranged and flexible structure for long term strategic energy systemplanning and decision-making.The presentation discussed the principles of the LCA models developed and the newlyextended models for the natural gas-fired power generation with alternative CO2 capturesystems. Additionally, the natural gas supply chain LCA models, including offshoreplatform gas production, gas pipeline transportation, gas processing, liquefied naturalgas (LNG) processes, LNG shipping and LNG receiving terminal developed are used toestimate the life cycle GHG emissions for an idealised case study of natural gasproduction in Qatar, LNG transportation to a UK natural gas terminal and use in a powerplant. 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 andPolicies 2012 Carbon Capture and Storage Workshop:3 http://dx.doi.org/10.5339/stsp.2012.ccs.3

of 3Linke, 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 acommercial application of capture to a power plant. Of particular interest was therealistic estimate of the costs involved. He discussed the relation between the time tobring the project to fruition and risks involved and – following Schwander’s presentationand remarks – how a risk assessment influences the relevant research. His presentationalso 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 ofpost-combustion, amine CO2 capture as carried out through their affiliate companyCANSOLV Technologies Inc., specifically to upgrade the Boundary Dam Power Station,Estevan, Saskatchewan, Canada. To quote from thesite http://www.globalccsinstitute.com/: ‘the project entails the rebuilding of Unit #3 atthe existing Boundary Dam coal-fired power plant to include post-combustionCO2 capture at one million tonnes per year. The 110 MW net unit is scheduled tocommence operations in 2014.’

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

DISCUSSIONThe session covered two examples of how a specific procedure is applied to address a commercialapplication of a CCS assessment and probable solutions. Fabricius’ talk discussed upgrading theBoundary Dam Power Station, Saskatchewan, Canada, through CANSOLV Technologies Inc. Korreused 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 mostrelevant and interesting but asked if Korre had applied her methods to other LNG scenarios. Korreanswered 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 givensystem over a period of time and a calculation of the overall system efficiency in energy conversion topower 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 takeit 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 carboncapture/reduction at the natural gas source, and also in the LNG shipping process. Youmentioned that the reduction of GHG emissions from the supply chain has the potentialto decrease life-cycle emissions significantly. Have you applied your LCA models to givean estimate of the possible percentage reductions? Also, have you considered therelative costs of capture in the UK compared with that which could occur in Qatar?’’

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

http://www.globalccsinstitute.com/


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

Korre replied that their LCA model has been used to compare emission reduction arising from LNGtransport with Qatar’s state-of-the-art Q-Max/Q-Flex tankers as opposed to transport withconventional 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 beconsidered relevant to Qatar industry.) With regards to the relative costs comparison, she indicatedthat 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 thatprevious results from a one-ton-a-day capture pilot demonstration plant has indicated that oneshould 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. TheBoundary Dam clients will invest more than one billion dollars based on results from the pilot. Othercompanies 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 tooptimise the efficiency of the scrubbing process. (Fabricius replied about 50�C). He added thatworking with a mixture of CO2 and SO2 gives rise to a challenge: one has to be aware of the systemdew point in order to minimise the effects of corrosion, which could be a huge problem. Fabriciusacknowledged this problem but remarked that the absorber was built of concrete lined with corrosionreducing bricks. Al-Taie wanted to emphasize that Fabricius was discussing capture with respect tocoal and the resulting problems associated with the combined CO2 and SO2 emissions. He thenremarked that Middle East crude is heavily sour, but is used routinely by many countries as arelatively inexpensive fuel. Hence it is very important that the energy sector consider the implicationsof capture from sulphur containing sources.

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


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Published: 17 December 2012c� 2012 Ali, licensee BloomsburyQatar Foundation Journals. This isan open access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Meeting report

Pre- and post-combustionChair: Fedaa Ali

Qatar Environmental and EnergyResearch Institute, Doha, Qatar

PRESENTATION

Gas turbine related technologies for carbon captureR. Peter LindstedtDepartment of Mechanical Engineering, Imperial College, London, UK.Combustion modes in gas turbines are evolving in order to meet requirements related tolower emissions and greater thermodynamic efficiency. Such demands can becontradictory and the additional complication of fuel flexibility comes to the fore withpotential new fuel stream opportunities arising. The latter may include hydrogen andcarbon monoxide rich streams as well as blends with significant amounts of carbondioxide arising from certain types of syngas (e.g. bio-derived). The matter is furthercomplicated by the impact of combustion stability related issues that arise in thecontext of the ubiquitous transition to lean pre-vapourised premixed (LPP) combustionfor power generation applications. Post-combustion carbon capture is generallyconsidered the leading candidate in the context of LPP based technologies. Significantcapture related issues arise in terms of parasitic losses associated with CO2 separationand transportation technologies (e.g. compression). The former is typically the majorcontributor and the relatively low concentration of CO2 in flue gases, combined withexcess oxygen resulting from LPP based operation, does impact separationtechnologies. It hence appears natural to consider the operating mode of the gasturbine and the impact of the fuel composition on the flue gas characteristics alongsidethe development of efficient and novel separation technologies.

PRESENTATION

An overview of carbon capture technologyBruce R. PalmerChemical Engineering Program, Texas A&M University at Qatar, Doha, QatarThis paper gives a brief review of carbon capture technology, but emphasises theproblems that can arise from natural gas produced from gas and/or petroleumreservoirs containing substantial amount of hydrogen sulfide and carbon dioxide,known as ‘‘acid gas.’’ Natural gas desulfurization or sweetening processes for treatingnatural gas are an integral part of natural gas cleanup. Discussed is the coupling ofcapturing both CO2 and H2S, particularly using an amine solvent and particularly in thecontext of post- and pre-combustion. Methods to dispose of these captured gases areoutlined. The paper gives an overview of the current status of capture and disposal onthe global and commercial scale.

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

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

of 3Ali, 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: thepower and heat units are shown. Lindstedtmade the point that the power and heat units are treatedseparately from the separation unit in the conventional post-combustion process, which is notnecessarily the most efficient practice. Lindstedt also had several comments on gas turbine/fuelcompatibility and the audience were interested in his comments on this most practical issue.

Fual

Fual

Flue

Flue gas

Fual

Air

Air

Air

Air

Post-combustion capture

Pre-combustion capture

O2/CO2 recycle(oxyfuel) combustioncapture

Source: IPCC, 2005.

Powerand heat

Powerand heat

Powerand heat

Gasification orpartial oxidation

shift + CO2separation

Air separation

Air separation

O2

N2

N2

H2

Recycle (CO2, H2O)

CO2 (H2O)

N2, O2, H2O

N2, O2, H2O

CO2

CO2 separation

CO2

CO2 dehydration,compression

transportand storage

Figure 1. Schematic from Lindstedt’s presentation.

In fact, later questions were asked after the workshop regarding turbine/fuel compatibility becauseprojects are in progress at Texas A&M University at Qatar concerning hydrogen as a fuel. Work is alsobeing carried out on turbine performance with GTL blends. Lindstedt was invited to comment. He didso 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 isperhaps the principal challenge at present. In short, the closer a burner technology operates tostability limits, the more important the properties of the fuel. Furthermore, the operation with somefuels (e.g. syngas related) can pose significant additional safety concerns in case of equipment oroperational failure. Another aspect that should not be ignored in this context is the state and quantityof post-combustion pollutants other than CO2 and the link to environmental regulations andseparation 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 nowCO2. 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 recoveryat the same time. He discussed acid gas treatment and reminded the audience that there wereproven techniques in the gas industry to separate CO2 from H2S either using separate amine solventsor 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 laterquestion on the impurity content of coal bed/shale extracted methane. It was asked if remediationfrom 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 littleH2S because this sulphur species adsorbs strongly on the coal matrix. Accordingly,processing this gas is relatively straightforward. Unfortunately coal-bed methanecontains only a few of the heavier hydrocarbons which are a significant source ofrevenue in the case of conventional natural gas.’’

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


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

This question, already indirectly addressed by Schwander and Fabricius who both discussedinvestment in the context of risk assessment, was answered by Palmer as follows: While the presentpresentation was not an economic analysis, the literature provides some information concerning theprocesses which have favourable economics. As shown in the table below, most of theseeconomically viable commercial-scale projects derive value from making product to specification toavoid economic penalties. Most of these processes are not combustion-based processes so theterms ‘‘pre-combustion’’ and ‘‘post-combustion’’ are not stickily applicable in these instances.However, in terms of processing conditions, these processes are more closely related topre-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 hispresentation 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. Itis recommended that reference be made to the comprehensive data base put out by the GlobalInstitute for Carbon Capture and Storage:http://www.globalccsinstitute.com/publications/data/dataset/status-ccs-project-database


http://www.globalccsinstitute.com/publications/data/dataset/status-ccs-project-database


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Published: 17 December 2012c� 2012 Ali, licensee BloomsburyQatar Foundation Journals. This isan open access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Meeting report

Industrial procedures and problemsChair: Fedaa Ali

Qatar Environmental and EnergyResearch Institute, Doha, Qatar PRESENTATION

The Lacq industrial CCS reference project (France)Jacques MonneTotalTotal is committed to reducing the impact of its activities on the environment, especiallyits greenhouse gas emissions. The group’s priorities are to improve the energy efficiencyof 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 programson CO2 capture and geological storage (CCS). Total has been involved in CO2 injectionand geological storage for over 15 years, in Canada (Weyburn oil field) for EOR andNorway (Sleipner, Snohvit) in aquifer. In 2006, Total decided to invest 60 million Eurosin the Lacq basin for experimenting a complete industrial chain from CO2 capture totransportation and injection in a depleted gas.This first French CCS pilot project is unique in several respects, by its size capturingcarbon from a 30 MWth oxycombustion gas boiler (size unprecedented worldwide), bythe choice of a deep onshore depleted gas reservoir (unprecedented in Europe) locatedat 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 naturalgas, High pressure steam production, CO2 capture, transport and injection) fullyintegrated in the Lacq industrial complex.The permitting process was also a first in Europe because at that time (from 2007 up to2009), the Directive 2009/31/EC of the European Parliament and of the Council of 23April 2009 on the geological storage of carbon dioxide was not issued and the Frenchauthorities decided to apply the ‘‘mining law’’ for the subsurface facilities and theenvironmental code for surface facilities. This permitting process has included twomonths of official public hearing. In parallel to this official process, TOTAL decided to beproactive in the stakeholder involvement. Public information meetings were held sincethe start of the project early 2007 and a public consultation and dialog phase has beenorganized. That led to the creation of a permanent local information and surveillancecommission (CLIS). From the beginning of this project, public acceptance has been amajor concern. TOTAL’s approach is to set-up a high level of transparency and opendialog with all stakeholders. Sharing data with academics though a scientific follow-upcommittee and achieving specific scientific collaboration programs are also part of ourobjectives.This project entails the conversion of an existing air steam gas-boiler into an oxy-gascombustion boiler, oxygen delivered by an air separation unit is used for combustionrather than air to obtain a more concentrated CO2 stream in the flue gas, easier to becaptured. 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, Systemsand Policies 2012 Carbon Capture and Storage Workshop:5http://dx.doi.org/10.5339/stsp.2012.ccs.5


steam network of the Lacq sour gas production and treatment plant. After a quench ofthe flue gas, the rich CO2 stream is compressed (up to 27 barg), dehydrated andtransported via a pipeline to a depleted gas field, 30 kilometers away, where it isinjected in the deep Rousse reservoir. Over 3 and half years, up to 90,000 tons ofCO2 will be injected.

Monne’s talk concentrated on three significant topics: (i) the operation of a pre-combustiondemonstration plant, the construction and operation of an integrated CCS chain, (ii) a quantitativeattempt to assess the impact of injection on the environment, and (iii) an insight into the sensitivity ofthe public concerns of the transportation and storage procedures. Two slides fromMonne’spresentation 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 underconstruction or operational?Monne answered that there are three main pilot projects in Europe: theSchwarze pumpe project (30 MW oxy-coal burners, started in 2008), the Compostilla project (30 MW


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 ispreferable.’’ He askedMonne 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 studiesregarding post- and oxy-combustion capture technologies relating to a Canadian projectin the context of the Canadian economic background. The results, however, did notdifferentiate between these technologies in terms of technical costs. It should be notedthat, in general, technical costing is specific for each project and has to be determinedaccordingly, for instance via a LCA as discussed at this Workshop by the speakers fromImperial College. Further, when comparing pre- and post- capture technologies, it isimportant to take into account their applications. In principle, pre-combustiontechnologies are mainly applicable to biomass/coal-fire power stations, integratedgasification combined cycle power generation plants, and to natural gas combined cyclepower 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. Iwould like you to give an indication about the cost of your campaign of the regularcommunication to the public and also if it was a significant fraction of the on goingtechnical and overall costs. Could you also tell us more on the public engagementmeetings and the subsequent feedback? ‘‘

Monne answered that, in fact, the cost was not significant. Although we (Total) quickly realized thatcommunications top the public were very important, it that turned out to be more of an organizationalproblem than a cost problem. Explaining the storage technology to the public was especially difficult:


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 byasking if there was a feedback on the percentage of people convinced from the campaign.Monneresponded 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 wassupported by the appropriate slides from his presentation, particularly those referring to subsurfaceand microseismic monitoring, and to the monitoring of the surface and water supply. He mentionedthat the interaction of CO2 with the subsurface minerals is a topic for CCS research. However, all thestudies (geo-chemical, geo-mechanical) already carried out concerning the project’s local Roussereservoir have shown that there was no major environmental impact of injected CO2.



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Published: 17 December 2012c� 2012 Benyahia, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Meeting report

Alternatives to amine-based capture& new technologiesChair: Farid Benyahia

Qatar University, Doha, Qatar PRESENTATIONIonic liquids as novel materials for energy efficient CO2 separationsRichard D. Noble and Douglas L. GinChemical Engineering Department, University of Colorado, Boulder, CO, USALarge improvements in separations technology will require novel materials withenhanced properties and performance. The fundamental interlinks for success inmerging synthesis and process incorporation are the structure, relevantphysical/chemical properties, and performance of new materials. Specific materials withthese interlinks are room-temperature ionic liquids (RTILs) and their polymers andcomposites. As a chemical platform, RTILs have an enormous range of structuralvariation that can provide the ability to ‘‘tune’’ their properties and morphology for agiven application. Introduction of chemical specificity into the structure of RTIL-basedmaterials is an additional key component.Membrane separation is the focus as a process for implementation. There have notbeen new materials successfully developed for this process in thirty years. ForCO2 capture, the target improvement in productivity is two orders of magnitude or morecompared to commercial materials currently available.

PRESENTATIONMetal-organic frameworks and porous polymer networks for carbon captureJulian Patrick Sculley, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe ZhouChemistry Department, Texas A&M University, College Station, TX, USAThe ability to rationally design materials for specific applications and synthesizematerials to these exact specifications at the molecular level makes it possible to makea huge impact in carbon dioxide capture applications. Recently, advanced porousmaterials, in particular metal-organic frameworks (MOFs) and porous polymer networks(PPNs) have shown tremendous potential for this and related applications because theyhave high adsorption selectivities and record breaking gas uptake capacities. Byappending chemical functional groups to the surface of these materials it is possible totune gas molecule specific interactions. The results presented herein are a summary ofthe fundamentals of synthesizing several MOF and PPN series through applyingstructure property relationships.

PRESENTATIONIntroduction to market challenges in developing secondgenerationcarbon capture materialsJason 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:6http://dx.doi.org/10.5339/stsp.2012.ccs.6

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

Absent an economic or social cataclysm, there is no plausible way to meet what will bethe world’s unavoidable energy demands without utilizing its vast supply of fossil fuels.One important technology being contemplated to mitigate the negative impact ofanthropogenic 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 achievefuture least-cost solutions, second generation or ‘2.0’ carbon capture materials arebeing developed with government support to improve efficiencies over the currentapplied solution that is ‘‘a very expensive proposition’’1 for the installed energygeneration base. One 2.0 material, Metal Organic Frameworks (MOFs), is ‘‘capable ofincreasing (carbon dioxide) selectivity, improving energy efficiency, and reducing thecosts of separation processes’’1 in CCS. Such materials can address CCS utilizationoutcomes in addition to lowering the carbon capture cost. To support further 2.0carbon capture material development while CCS faces economic challenges,framergyTM is leveraging alternative usages for MOFs and other 2.0 materials developedfor carbon capture.

PRESENTATION

CCS from industrial sourcesPaul S. Fennell1⇤, Nick Florin1, Tamaryn Napp2, Thomas Hills1,2.1Department of Chemical Engineering, Imperial College, London, UK2Grantham Institute for Climate Change, Imperial College London, UKThe literature concerning the application of CCS to industry is reviewed. Costs arepresented for different sectors including ‘‘High Purity’’ (processes which inherentlyproduce 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 itsapplication to the electricity production sector. Costs range from less than $201110/tCO2 up to above $2011 100/tCO2. In the words of a synthesis report from theUnited Nations Industrial Development Organisation (Unido) ‘‘This area has so far notbeen the focus of discussions and therefore much attention needs to be paid to theapplication of CCS to industrial sources if the full potential of CCS is to be unlocked’’.

DISCUSSIONEditor’s note. Ornstein gave his presentation slightly later in the program but, since it follows closelythe 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 thesealternative techniques, or their variants, will have to be considered commercially. Ornstein put thisforcibly. He quotes Herzog1:

‘‘Today, the only proven CCS capture technology is amine scrubbing. In some waysit works very well – it is highly selective for CO2 and has recovery rates above 90%...Itmakes retro-fitting older, less efficient plants very difficult. For example, an existing plantwith 35% efficiency when retrofitted with CCS will have its efficiency reduced to20–25%. This is a very expensive proposition.’’

Hanley, however, submitted this observation: Zhou and Ornstein have made the point that theenergy 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 ofthe commercial amine solutions. (But, of course this latter information is usually confidential.) Alongthese lines, do the authors have any comments on how – with respect to energy consumption – theiralternative capture techniques might compare with the traditional amines? Ornstein responded withthe statement that the materials licensed from Dr. Zhou’s group would have a significant energy

1http://sequestration.mit.edu/pdf/Research_Program_for_Promising_Retrofit_Technologies.pdf.

http://sequestration.mit.edu/pdf/Research_Program_for_Promising_Retrofit_Technologies.pdf


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, butNoble rebutted by stating that the chemicals he is discussing are not toxic and, furthermore, are safeenough 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 amembrane configuration, with the membranes stacked vertically, the volume would be in the order ofa few thousand square meters.’’ Ornstein added the cautionary comment that replacing solventscrubbing with a membrane could be challenging commercially because of the volume of flue gasthat 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 doesnot 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 knowamine and water react. Is this important in this case?’’ Noble replied that the chemistry/reactionconditions 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 includewater 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 wascarried out by third parties and he could not give a precise answer. He did, however, note that amembrane only has a small ionic liquid content, which would keep the costs down. Following up onthe membrane format, Fennell asked how many cycles do the membranes last. Noble answered thathe 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 groupwas 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 onproblems of industrial concern, we cannot give a published summary of the questions and answersbecause 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 fromCCS has gained popularity. Several key organizations have relabeled CCS by adding‘‘utilization’’ to the acronym, thus CCUS, or sometimes – as in the UK – even removingthe word storage altogether, thus CCU.’’

That utilization rather than storage might be a path to follow lead to the following comment fromFennell:

‘‘If the UK is actually diverting into carbon capture and utilisation (CCU), I disavow mycountrymen. Carbon dioxide utilisation is a dangerous distraction from CCS. Roughly30Gtn of CO2 are emitted per year worldwide. The total utilisation of CO2, excluding EORis of the order of 100 Mtn/year—orders of magnitude less. Moreover, most processescapturing CO2 (particularly urea production, at 65–146 Mtn/ year, release theCO2 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 suggestthat they are part of the solution to global warming.’’


Ornstein countered:

‘‘I am not saying that there is a policy towards CCU in the UK at the moment, but certainlyit’s something that’s been looked at. It may not be a permanent solution, or solution onits own, but certainly a step change towards a more broad approach. In addition, thisapproach 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 carbonfutures in the UK, to which I presume you refer. There were many aspects which I foundhighly troubling—many changes suggested were not made (this is reflected in theintroduction). You have suggested that mobilisation of capital into the area of CCS maybe predicated in the US on CCU applications. Again, this is potentially a worrisome areabecause if technologies have a niche CCU application, sub-optimal technologies forfull-chain CCS may be developed and promoted. At the end of the day, CCU will doalmost 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 goodinvestment is important for moving things forward financially,’’ replied Ornstein.Contributing to this debate, Zhoumade 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 problemthat 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’sperception. He discussed, for example, the significant amount of carbon produced by cementproduction and the iron and steel industry with possible ways to reduce and/or capture it. Thetechnique 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 isconsistent with a theme discussed at the onset of the Workshop: namely, that the necessary carbonemission 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 productionprocess is being researched, or was even at a proof-of-concept stage.

Integration with Ca looping

CaO purge + fresh limestone

CaO purge

coal, air

Cement plant

flue

flue without CO2

O2

N2

CO2

carbonator

CaCO3

CaO

limestone

coal

calciner

ASU

air

Unlike most other CO2 capture technologies, the exothermic reaction capturing CO2 occursat 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 residuesfrom 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 purgeflowrate were used, the electricity industry produces exactly the correct amount of CaO forcurrent cement manufacture.

Figure 1. Integration with Ca looping.


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


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-technologies-

tested-norcem-cement-plant-norway/,accessed 4th August 2012.


http://www.alstom.com/press-centre/2011/6/alstom-heidelbergCement-study-co2-capture-technologies-tested-norcem-cement-plant-norway/

http://www.alstom.com/press-centre/2011/6/alstom-heidelbergCement-study-co2-capture-technologies-tested-norcem-cement-plant-norway/

OPEN ACCESS


Published: 17 December 2012c� 2012 Benyahia, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Meeting report

TransportChair: Farid Benyahia

Qatar University, Doha, QatarPRESENTATION

Shipping and CCS: A systems perspectiveN. Mac Dowell and N. ShahCentre for Process Systems Engineering, Dept. of Chemical Engineering, Imperial CollegeLondon, UKIn this contribution, we present an overview of the contribution made by the shippingsector to global CO2emissions. We review the currently proposed technology options formitigating these emissions, and propose a new option for the control of greenhouse gasemissions from shipping.

PRESENTATION

Green shippingTalal Al-TamimiRasGas Company Limited, Doha, QatarThe state-of-the-art facilities of RasGas and QatarGas process natural gas from Qatar’sNorth Field, the World’s largest non-associated gas field. At the Ras Laffan site, gas isliquefied to LNG and then loaded to tankers for transportation. But along with theobjective of supplying LNG to customers as efficiently as possible comes theresponsibility to be environmentally aware and, in particular, to ensure that any carbonemissions during the loading and transportation are minimised. The presentationoutlines RasGas’s approach.The transportation of LNG by the giant tankers designated Q-Flex and Q-Max–vesselswith cargo capacities of the order of 215,000 m3 and 266,000 m3, respectively–isdiscussed. A key point is that, although these vessels are much larger than theconventional carriers, the fuel consumption is almost the same, with obvious economicand environmental advantages. It is emphasised that carbon dioxide emissions to theatmosphere from the LNG cargo itself are minimal since the carriers are fitted withon-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 theexisting diesel main engines: LNG from the vessel’s cargo tanks will be vaporized andthe gas used as the fuel. The benefits of replacing marine diesel fuel with gas aredelineated, not only with respect to carbon emission reduction, but also to ensure thatthe 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 majorattempt to reduce the BOG generated and flared at the Ras Laffan LNG terminal. It isremarked that GHG emissions can be substantially reduced and the recovered gas canbe 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 Policies2012 Carbon Capture and Storage Workshop:7 http://dx.doi.org/10.5339/stsp.2012.ccs.7


DISCUSSIONSeveral in the audience remarked that it was interesting to learn fromMac Dowell’s talk that theCO2 emissions from shipping are approximately equivalent to that from road transport and aircraft.Apas Bandyopadhay (Qatar Ministry of Environment ) followed upMac Dowell’s outline of the

special requirements for ship-board capture facilities; two points, for example were mentioned in thepaper: that the size of the equipment has to be minimal and, if the equipment was solvent based, thesolvent 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 fromshipping. I think that it is a possible solution though as it is cheap and produces usefulbyproducts during the capturing process. Other amines, for example MEA, have in factbeen onboard submarines for years. So solvents are a feasible solution—though makingthem 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 hugetankers, designated Q-Flex and Q-Max, in Qatar’s LNG fleet. Discussion was stimulated by thecontents of his slide reproduced in Fig. 1. Many in the audience, for example, learnt that the LNGcargo itself does not contribute directly to CO2 emissions.Mac Dowell and others remarked thatimprovements in fuels, and in ship construction and operation in general, would give significantreductions in GHG pollutants. Lindstedt, for instance, remarked that more efficient propeller systemswould obviously reduce emissions.

Economies of Scale

.In contrast to conventional LNG vessels these Q-Flex and Q-Max vessels candeliver all the cargo loaded as well as act as an efficient floating storage facility.

The Q-Flex/Q-Max fleet:

.Benefit from economies of scale where more LNG can be transported per journeythereby lowering the transportation cost per unit of LNG. Although those vesselsare much larger than the conventional vessels the fuel consumption is almost thesame. This means that by using larger vessels the number of voyages are reducedresulting in lowering emissions to the environment.

.Those vessels are fitted with a reliquefaction plant. Gas venting into theatmosphere is very unlikely in this type of LNG carrier.

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 satisfythe mandated maximum sulphur content, but he also added that converting the engines to burnnatural gas is an obvious solution to reducing sulphur and other pollutant emissions. Al-Taminireinforced this statement:

‘‘Using LNG as energy source onboard the LNG carriers will reduce the amount ofsulphur produced from the vessels and will allow the vessel operators and the charteresto comply with the mandatory rules inside the emission controls area in Europe andother 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 beingflared during Liquefied Natural Gas (LNG) ship loading at the Port of Ras Laffan. The

1http://www.zawya.com/story/Qatargas_Jetty_Boiloff_Gas_Project.

http://www.zawya.com/story/Qatargas_Jetty_Boiloff_Gas_Project


project is part of the Common Facilities Projects at Ras Laffan Industrial City in the northof Qatar. The project will enable boiled-off gas to be collected from LNG ships andcompressed at a central facility. The compressed gas will then be sent to the LNGproducers to be consumed as fuel or converted back into LNG. This project, when fullyoperational, 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 couldbe used to generate power for domestic consumption.



O P E N A C C E S S Special issue: Carbon Capture and Storage Workshop, Texas A&M University in Qatar, April 2012Guest editor: Howard JM Hanley

Meeting report

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

http://dx.doi.org/10.5339/stsp.2012.ccs.8Published: 18 December 2012

© 2012 Macdonald, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.

Chair: Iain MacdonaldImperial College, London, UK

Economic and social issues

PRESENTATION

The carbon conundrum: GCC perspectivesFarid 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.

DISCUSSIONBenyahia’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.

Macdonald, Sustainable Technologies, Systems and Policies 2012.CCS.8

2Page of 5

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-scientists-

gavin-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


3Page of 5

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


4Page of 5

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


5Page of 5

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


Published: 17 December 2012c� 2012 Maitland, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Carbon capture and storage: The wayaheadGeoffrey C. Maitland*

Department of Chemical Engineering,Imperial College, Exhibition Road,London SW7 2AZ, UK*Email: [email protected]

ABSTRACTThe paper gives a general introduction and overview of Carbon Capture and Storage (CCS) with anemphasis on the capture of CO2 and other greenhouse gases from the waste gas streams of powerplants and industrial processes. This stage accounts for about 80% of the overall cost of the CCSprocess 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 theneed to implement CCS as one of many measures to mitigate carbon emissions. Current targets willrequire a commercial CCS capacity to remove about 10Gte CO2 pa by 2050. The overall features ofCCS processes are described – capture, compression and transport, sub-surface storage – coveringthe main capture options and the three main types of storage site (deep saline aquifers, depleted oiland gas reservoirs and unmineable coal seams). The current status of large-scale CCS demonstrationprojects is reviewed. The main classes of carbon capture technologies are then described, both thosecurrently capable of large-scale deployment and those in development for the future. Finally the mainchallenges facing CCS, to make it a globally-deployed commercially viable technology, aresummarised and suggestions made for future developments in the clean recovery and use of fossilfuels which combine CCS with sub-surface processing.

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

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

of 18Maitland, Sustainable Technologies, Systems and Policies 2012.CCS.9

INTRODUCTIONCarbon Capture and Storage (CCS) is a technology that can in principle eliminate or substantiallyreduce the emissions of carbon dioxide (CO2) to the atmosphere resulting from the combustion andprocessing of fossil fuels to produce power, fuels, chemicals and carbon-based materials incentralised facilities, where CO2 can be extracted from the gaseous product streams and then betransported to suitable underground long-term storage sites. If widely deployed it can make asubstantial contribution to carbon mitigation in the decades ahead and be a critical technology inenabling atmospheric CO2 concentrations to be maintained at levels that will avoid catastrophicclimate change consequences. This paper gives an overview of the main technical, social andeconomic issues concerning CCS and the current status of its deployment, with a particular emphasison 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 tomeet this demand, they currently contribute only about 20% globally. Fossil fuels provide the majorshare, 12.5TW [1], of our energy needs. By 2050 it is expected that global energy demand willdouble [2]. If we set aside solar and nuclear, the other sources are restricted to providing a few TWand collectively are unlikely to match even the current energy demand, let alone the large projectedfuture increases. Nuclear energy could in principle meet a large proportion of this growing demandbut its widespread implementation is still restricted by safety and security concerns and lead timesfor installation are long. Solar energy must be the long-term hope meeting long-term demandrenewably; if we can harness effectively but a small fraction of the >105 TW of solar energy falling onthe 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 improvingefficiency and reducing costs and, whilst good progress has been made in recent years, thetimescales for making this competitive are still long. Fossil fuels on the other hand have the capacityto provide about 25TW of energy even based on existing known reserves of both conventional andnon-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 economicroutes to exploit them developed. So most projections are that we will need to continue to use fossilfuels to meet global demand for a large part of this century and that even by 2050 they will provide atleast 60% of our energy requirements (see for example Fig. 2).

current wotld consumption15 TW

Tidal/Wave/Ocean Currents: 2 TW gross

Fossil Fuels:Current 12.5 TWPotential 25 TW

Hydroelectric: 4.6 TWgross, 1.6 TW feasible

technically, 0.6 TWinstalled capacity

Geothermal: 9.7 TW gross (small % technically feasible)

Solar: 1.2 !105 TW onearth's surface,

36,000 TW on land

Wind 2-4 TW extractable

Biomass/fuels: 5-7 TW,0.3% efficiency for non- food cultivatable land

The Energy Landscape

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

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


Other Renewables Biomass Nuclear Gas Oil CoalYears

EJ

1400

1200

1000

800

600

400

200

01990 2000 2010 2020 2030 2040 2050

Figure 2. Typical future energy projection by source (Intergovernmental Commission on Climate Change, ThirdAssessment 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 reservesof coal and the recent increasing amount of non-conventional oil and gas exploitation [1] all indicatethat 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 andmore difficult to recover and process non-conventional sources. Just as the stone age did not endbecause we ran out of stone, it is increasingly clear that we will not stop using fossil fuels because werun 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 fromindustrial and power generation processes [5] since the industrial (see Figs. 3 and 4) revolutionleading to atmospheric levels of GHGs which the strong weight of evidence indicates are leading tosignificant climate change.

CO2 e

mis

sion

s fr

om fo

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fuel

com

bust

ion

and

tran

sfor

mat

ion

(Gt)

Year (-)

1700 1800 1900 2000 2100

30

25

20

15

10

5

0

Figure 3. Emissions from fossil fuel combustion, and fuel transformation (Carbon Dioxide Information AnalysisCentre 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 of30% on 1990 levels [6]. Atmospheric CO2 levels have reached 390 ppm [7], already above the380 ppm target set at Kyoto [8] in 1996 as the cap we must stay below to avoid major climatechange. The current best case scenario adopted by the main climate change monitoring bodies suchas IPCC [9] is to maintain atmospheric levels below 450 ppm [10] (see Fig. 5), which would stillcorrespond 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

http://cdiac.ornl.gov/ftp/ndp030/global.1751_2006.ems


2005 Sources of CO2

83.9%

CO2 as a portionof all Emissions

5,751.2

<0.5<0.5<0.5

TgCO2 Eq

0 25 50 75 100 125 150 175

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

Figure 4. Distribution of anthropogenic carbon dioxide emissions from power generation and industrialprocesses (Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2005, April 2007, EPA EPA 430-R-07-002 http://www.epa.gov/climatechange/Downloads/ghgemissions/07ES.pdf).

Year

375 ppm

550 ppm

450 ppm

1000 ppm

Global Carbon Emissions GT

4-6°C

3-4°C

2°C

!T

[CO2]

2000 2010 2020 2030 2040 2050 2060

16

12

8

4

Figure 5. Projection of evolution of global carbon emissions, mean atmospheric CO2 concentrations and likelyman global temperature increases for three scenarios: ‘business as usual’ (red), capping mean CO2 levels at550 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% ofpre-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 GHGemissions come from energy-related sources, and CO2 represents 94% of all GHG emissions, theimpact of major industrial processes such as cement and iron and steel manufacture is coming underincreasing scrutiny [12,13]. The other major GHGs are methane (5% of total emissions) and oxides ofnitrogen (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 ofCO2 due to photochemical degradation. Nevertheless prevention of their release (by for examplereduced natural gas flaring and the use of pure oxygen rather than air for power combustionprocesses – ‘oxyfuel’ – as well as capture and storage) will make a useful contribution to reducingclimate 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 byimproved 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

http://www.epa.gov/climatechange/Downloads/ghgemissions/07ES.pdf


Baseline emissions 62 GtCCS industry and transformation 9%

CCS power generation 10%

Nuclear 6%

Renewables 21%

Power generation efficiency& fuel switching 7%

End-use fuel switching 11%

End-use electricity efficiency 12%

End-use fuel efficiency 24%

BLUE Map emissions 14 Gt

20502005

WEO 2007 450 ppm case ETP 2008 BLUE Map scenario0

70

60

50

40

30

20

10CO

2 em

issi

ons

(GtC

O2/

yr)

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

safe, low waste nuclear energy. However, the remaining 20%, at least, must be achieved by capturingand storing as much as possible of the CO2 and other GHGs released by the extraction, processingand use of fossil fuels. This capability, alongside the other measures, will enable the continued use offossil fuels into the second half of this century but will require the global capacity to capture and store10Gte CO2 per annum. Given that today there are no fully commercial CCS projects and only eightdemonstration projects that meet the large-scale integrated project criteria [15] (>0.8 Mte CO2 pacaptured and stored – see Fig. 7), which collectively with the 40 or so smaller projects planned orunderway 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 Institute2011, ‘The global status of CCS 2010’).

The International Energy Agency, in its 2010 CCS Technology Roadmap [16], estimates thatmeeting 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 PROCESSThe CCS process involves three main stages (see Fig. 9):

- Capture of CO2 (and sometimes other GHGs) from waste product gas streams of centralisedfossil fuel burning facilities e.g. flue gas from coal-fired power plants, cement manufacture.


OECD North America

OECD Europe

OECD Pacific

China & India

Other

CO2 captured (world)

Num

ber o

f pro

ject

s

4000

3500

3000

2500

2000

1500

1000

500

02010 2015 2020 2030 2035 2040 2045 20502025

capt

ured

(MxO

2/yr

)

4000

2000

0

6000

8000

12000

10000

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

Figure 9. Schematic summary of overall carbon capture and storage process, indicating the range ofCO2 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 (viapipeline or tanker) to storage site.

- Injection of supercritical CO2 into a suitable (in terms of injectivity, storage capacity andlong-term storage integrity) sub-surface storage site; this needs to at depths greater than800 m to maintain supercritical fluid conditions.


In the supercritical state CO2 has a similar density to oil, 600–700 kg m�3, slightly lower thanwater but about 600 times greater than gaseous CO2 at lower pressures. This has obviousadvantages for both transport and storage. However the viscosity in the supercritical state remainssimilar 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 thesupercritical CO2, avoiding the fingering instabilities that can arise in multiphase fluid displacementsinvolving fluids of greatly contrasting viscosity. These fluid mechanical issues are one of the majorchallenges 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 salineaquifers [17,18]. Close to 2000Gte CO2 capacity is considered to be available in depleted oil and gasreservoirs. For some of these reservoirs, where the pressure has still not fallen below the minimummiscibility pressure (for CO2/oil), there is the additional incentive of using the initial CO2 injection tolower the in situ oil viscosity and recover a significant fraction of the oil in place that has not beenproduced 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 costsof 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 incarbonates) and geology/chemical reactivity to CO2 (carbonates will dissolve in acidic CO2/brinefluids, resulting in reactive transport and complex dissolution-precipitation processes, makingporosity and permeability variable in time and space in carbonates in contrast to the relatively inertand time-invariant rock matrix of clastic reservoirs) means that there are major design challenges inoptimising the injection and retention of CO2 in different types of geological environment.


A third option is to store the CO2 in unmineable or uneconomic (e.g. offshore) coal seams. Here thetrapping 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 stronglyadsorbing 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 ofCO2. This process is known as Enhanced Coal Bed Methane, ECBM [20], and estimates of theavailable 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 to10Gte CO2 pa by 2050). Since it is very likely that more storage capacity will be identified andverified in future years, especially once CCS becomes a viable commercial process, then the ability todeploy CCS as an effective carbon mitigation mechanism is unlikely to be limited by available storagecapacity. A bigger challenge will be posed by the juxtaposition of sources of CO2 emissions andsuitable storage sinks—the selection of suitable storage sites relatively close to major emissionsources and the development of effective CO2 transportation networks (national and trans-nationalCO2 grids) to make optimal use of available storage capacity (maybe linked to possible EOR or ECBMopportunities) 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 formationsfor EOR, reservoir re-pressurisation or gas storage applications [21]. The major technical andeconomic challenges lie in the upstream carbon capture stage. Here again there are three major typesof process currently being deployed in demonstration projects or under consideration for futurecommercial deployment in power generation or industrial manufacturing processes—see Fig. 12.

Power & Heat

Power & Heat

Power & Heat

CoalGas

Biomass

CoalGas

Biomass

CoalGas

Biomass

CoalGas

Biomass

Air

Air/O2

Steam

Air/O2

Air

Air

N2

N2

H2

O2

CO2

N2O2

CO2

CO2

CO2

CO2

CO2

Raw material Gas, Ammonia, Steel

Gasification Reformer +CO2 Sep

Process+CO2 Sep

Separation

Air Separation

Compression& Dehydration

Gas, Oil

Post combustion

Pre combustion

Oxyfuel

Indusrial Processes

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 theheat for e.g. steam production for driving turbines for electricity generation, resulting in anitrogen-rich flue gas from which the CO2 (and other GHGs) is removed by solvent or solidadsorption 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 andcarbon monoxide) and subsequently via the water gas shift reaction

CO + H2O ! CO2 + H2

to CO2 + H2. The CO2 is then captured from this stream whilst the H2is used as a ‘clean’ fuel togenerate electricity using gas turbines, to power fuel cells or as an energy source formanufacturing processes. Alternatively, or alongside this, Syngas can be used as a feedstock toproduce liquid fuels or chemicals via catalytic Fischer-Tropsch like processes.


- A third alternative, which has growing impetus, is oxyfuel combustion whereby the fossil fuelis combusted using pure oxygen rather than air, resulting in a flue gas containing mainlyCO2 and steam. Condensation of the steam results in a concentrated CO2 with minor impurities(such as SO2, H2S which may require a desulphurisation stage) which can be compressed andtransported directly to storage. Here the gas separation stage is relatively cheap; the majorcosts 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 optionssuch as gas membranes are currently under development.

Post-combustion capture has the advantage that it is relatively easy to retrofit to existing plantwhereas the other two approaches are best introduced as part of a new build. Industrial processescan use any of these options, depending on the nature of the feedstocks and the preciserequirements and constraints of the process. Again post-combustion capture is likely to be the mostviable 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]. Theprecise costs depend on the type of capture process used, the composition of the CO2-containing gasstream, the nature and location of the storage site relative to the CO2 sources and the mode oftransportation. However, typically costs per te CO2 are $50–100 for capture, $10 for storage, $2 fortransportation and $1–2 for long-term monitoring. These add about 1–3 cents per kWh to electricitygeneration costs.

Capture$50-100 per te CO2

$10 per te CO2 per 250 km

$10-20 per te CO2

Transport

Storage–

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

There are currently eight integrated CCS demonstration projects which are categorised as LargeScale 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 arelocated in Norway (2), Algeria, Canada and USA (4). A major US investment is the FutureGen $1.5bnclean 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 havebeen injected since the project started in 1996. Gravity segregation and flow under 800 m ofimpermeable shale controls the CO2 movement. Major drivers for this project were the imposition of aNorwegian carbon tax (⇠%55 per te CO2) in 1991 and the need to reduce the CO2 concentrationfrom 9% in the produced gas to below 2.5% for domestic gas supplies. In 2014, it is expected thatthe carbon capture facilities at Sleipner T will separate an additional 100,000–200,000 te pa ofCO2 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 inthe Krechba formation. An interesting more recent development is the Lacq project in France. Startedin 2010, this project aims to test a fully integrated industrial CCS process by capturing 120,000 teCO2 over a two year period using an oxyfuel combustion unit on the steam generation plant of theLacq industrial complex. The CO2 is transported via a 27 km pipeline for injection into the Roussenatural gas reservoir at a depth of 4500 m. A summary of current and planned CCS projectsworldwide is given in Fig. 14.


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

CARBON CAPTURE TECHNOLOGIESSolvent processesThe most common approach for capturing CO2 from waste gas streams is to absorb the gas in asuitably selective solvent and then regenerate the CO2 for storage, usually by heating the solvent. Forpost-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 alkalinesolvents, the most common of which are amines. Such a process has been widely used forCO2 scrubbing in chemical processes for many years, so has been a readily transferable technology toCCS 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 isexposed to an aqueous MEA solution (15–30 wt%) in a scrubbing column, typically at about55�C and a pressure of 1 bar. The loading of CO2 at the exit from the column is ⇠0.4 mol CO2/molMEA. The CO2 is then removed from the MEA in a stripper column by boiling at a pressure of ⇠2 barand a temperature of ⇠120�C). The energy required for this stripping stage (typically 4 GJ

http://www.co2crc.com.au/demo/worldprojects.html

http://www.vattenfall.com/www/co2_en/co2_en/index.jsp


te�1CO2 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 mustbe diverted to the stripping unit rather than used in the steam turbine for electricity generation. Thisefficiency 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 energyinput to the stripper reboiler in recovering the captured CO2 and that used to compress the CO2 toliquid/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 solventsfor CO2 capture [33]. Hindered (secondary or tertiary) amines show some promise in approaching acapacity of 1 mol CO2 per mol amine and a larger cyclic capacity (significantly lower loadings understripper conditions) than MEA, combined with smaller values of regeneration energy. Specifically thesecondary 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 ofCO2 absorption for hindered amines is usually lower than for MEA; activators like piperazineaccelerate absorption and amine/activator blends look promising. Major reductions in theregeneration energy are a challenge; the value for ammonia, 55 kJ mol�1, is about 60% that for MEAand 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 othersignificant issues which influence choice of amine-related solvents; the optimisation of the solventmolecular 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 forproduced gas streams containing significant CO2 concentrations, physical rather than reactivesolvents can be used (e.g. methanol or n-alkanes) [40]. These have the advantage of binding theCO2 much more weakly resulting in significantly lower regeneration energies and hence efficiencypenalties. They also degrade less and are less corrosive. Overall therefore the costs associatedsolvent 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 (seeFig. 16), have a very wide liquid range with particularly high boiling points and can be designed to beboth selective to CO2 or other GHGs and to tune the absorption/desorption energetics. They arerelatively expensive but have the potential for combining high loadings with high regeneration yieldsand efficient recycle with very low solvent make-up. These systems are still in the research phase butseem to have high future potential [38].

Solid adsorption processesAdsorbing CO2 on high surface area solids is the other major class of capture processes under activeconsideration for carbon capture, or indeed in some cases for permanent storage. As with solventprocesses, the adsorption can be physical or reactive. The process closest to commercial deploymentas a viable rival to amine scrubbing is Calcium Carbonate Looping [42] (see Fig. 17). Here finelydivided calcium carbonate, in the form of limestone or other mineral forms, is calcined at about650�C to lime, calclum oxide CaO. This is passed to a carbonator vessel where it is contacted at900–950�C with the flue gas or other CO2-containing stream and converted exothermically back toCaCO3. 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 theparticle microporosity [42] but regeneration is possible (e.g. using steam) which enables furtherrecycling of ‘spent’ adsorbent [43,44].


--

N N

N

N

N

R

R

R

R'

R'

N(R)4

P(R)4

F3CF3C

CF3SS

S

O O

O OO

O

O

–BF4–PF6

(a) (c)

(d)

(g)

(i)(h)

(f )

(e)

(b)

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 andEnviron. 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 bythe recovery of heat from the hot CaO and CO2 streams, and heat produced from the exothermiccarbonation reaction (�179 kJ mol�1), all of which can used to generate additional steam. Hence theefficiency penalty associated with CO2 capture from a power station using carbonate looping turnsout to be extremely competitive (⇠3–4% for the capture stage and 3% for subsequentcompression) [45]. It has a number of potential advantages: it uses a sorbent derived from cheap andabundant natural limestone; it has a relatively low efficiency penalty; it uses mature large-scaleequipment, such as circulating fluidised beds (CFBs), which reduces the scale-up risk; the technologyhas been demonstrated on medium scale plant; it has particular synergy with cement manufacturewhere 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 sinteringand porosity loss but also due to sulphate formation in the presence of sulphur-based gases such asSO2 [45]) and particle attrition with the continued looping of the sorbent. However, this processcould reduce the thermal efficiency de-rating associated with CO2 capture to about 6–8% comparedto 8–10% for MEA-scrubbing, representing a significant fuel and cost saving over the lifetime of atypical 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 solidsorbents [47,48], and physisorption systems such as structured porous solids (molecular cages)including zeolites, molecular-organic frameworks (MOFs) [49] and gas hydrates [50,51].


Other capture processesAn approach that combines some features of calcium carbonate looping and oxy-combustionprocesses is ‘chemical looping’ [52]. Here, direct contact between air and the fossil fuel is eliminatedby 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 beds—see Fig. 18. In one (theregenerator), the metal is oxidized using air and/or steam in an exothermic process that can be usedto raise steam; the oxide is fed to the other reactor (the reformer) where it is reduced back to themetal by reaction with the fossil fuel, producing CO2 and steam, which is readily separated bycondensation 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 mustbe overcome to achieve overall efficiencies of greater than 50% [53]. Chemical looping-combustionhas been investigated using gaseous and solid fuels, as well as advanced H2productionprocesses [54,55]. The major challenges are in optimisation of the oxide(s) used, balancing rawmaterial availability and cost, the energetics of the redox process and the long-term degradation rateof 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 differencethat 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 capturefrom high pressure process streams without significant depressurisation, hence reducing greatlysubsequent compression costs, one of the key economic factors in the overall CCS chain. Three maintypes of membrane can be deployed, polymeric, metallic or ceramic; the choice is strongly dependent


on the temperature and gases involved in the particular application. In the case of CO2 separationfrom flue gas, a critical issue is to increase membrane permeability in order to reduce the efficiencypenalty associated with achieving the pressure gradient across the membrane [56]. Major challengeswhich 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 fromcombustion, together with water and sunlight, to grow microorganisms such as algae orcyanobacteria. The use of highly productive genetically engineered algal strains is expected toenhance greatly the capture capacities and rates for these systems [57,58]. Another biologicalcapture option being pursued involves enzymes. One such process uses carbonic anhydrase tocapture 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 atwhich algae can grow, and challenges associated with bioreactor design.

- Cryogenic separation: This is an alternative approach for gas–gas separation exploiting thedifferent boiling temperatures and partial pressures of the gases in a mixture, to separate theminto distinct phases by cooling or pressurization [61]. For CO2 separation/capture, CO2 can befrozen at �75�C and atmospheric pressure, or condensed to a supercritical fluid whenpressurised beyond its critical point at 31�C and 74 bar. The major problem for cryogenicseparation 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 theformation of ice [62].

- Building CO2 into materials [63,64]: Although CO2 contains carbon in its highest oxidationstate (+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 thanCO2. 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 forretaining CO2 in storage reservoirs, taking over from the shorter-term trapping mechanisms ofcapillary trapping and dissolution in the reservoir fluids.

On the other hand, the reduction of CO2 to lower oxidation states requires significant energy. Thiscan be achieved via electrochemical or photoelectrochemical reduction [66] (assuming theavailability of suitable amounts of renewable electricity) or by using highly reactive organic ororganometallic compounds [67]. The potential for expanding commercial processes for using CO2 asa feedstock is in producing three main classes of products: fine chemicals, including urea, carboxylicacids, and carbonates; fuels or commodity chemicals such as methanol and formic acid; and plasticssuch as polycarbonates and polyurethanes [68,69]. The main challenges to this ‘re-use’ of CO2 arethe 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-basedmaterials. Currently only about 150 Mte CO2 is used each year as a chemical feedstock comparedwith the 2050 target of removing 10Gte pa CO2 via CCS or other capture-based processes.

THE FUTURE CHALLENGES FOR CO2 CAPTUREIt can be seen that several CO2 capture technologies are in commercial or semi-commercial use andare being deployed in demonstration projects across the world. However, this stage represents by farthe most expensive part of the overall CCS chain so much R&D is being carried out to produce moreefficient, lower-cost and more environmentally acceptable solutions. A summary of the majorchallenges 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 loweringcompression costs


- 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 carboncapture, and CCS overall, over the next decade or so. Processes will become more complex but alsomore efficient. A possible roadmap or technology adoption trajectory, based on the current state ofmaturity of the various candidate approaches and the anticipated time to reach commercialreadiness, is shown in Fig. 20 [23,36].

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

Finally, we can ask the question ‘what lies beyond CCS?’. In the long-term, maybe not until the endof 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 fuelsfor heat and power, and our liquid fuels, chemicals and materials requirements will all be met usingrenewable biofeedstocks. However, the transition to this state will take many decades and CCS as wenow envisage it may only be a short-term measure. Rather than using a lot of energy to bring fossilfuels 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 productionconduits

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 separationand capture of CO2 and other GHGs and toxic products [70,71]. We would deliver to the surface, or atthe 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 valuematerials (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 refineryengineering experts running and monitoring the underground refinery from their technical basesacross 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


Figure 21. The shape of things to come for carbon capture and storage? Subsurface processing refining with insitu 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-termrenewables era, will last more than five decades. So there is plenty of time to develop and refinethese approaches to optimising our utilisation of the energy and materials content of fossil fuels andreducing the environmental footprint of their exploitation more and more.

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OPEN ACCESS


Published: 19 December 2012c� 2012 Schwander, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Carbon capture and storage: Anindustry viewpointMarcus Schwander

Qatar Shell Service Companies

INTRODUCTIONEconomic growth in developing nations – driven not least by fast growing populations – is leading toa surge in demand for energy, with rapid increases in both renewable energy deployment and fossilfuel production. Since 2000, the world has added 0.3 billion tonnes oil equivalent per annum ofrenewable energy, but nearly eight times this amount from fossil production.1 Current trends are thatincreasing renewable energy system deployment is not backing out other fuels; rather, it issupplementing a constrained fuel pool, allowing for faster economic growth. This approach will notdeliver the necessary global greenhouse gas (GHG) reduction goals by 2050. Thus, there is anenormous challenge for global efforts to halve CO2 emissions by 2050 in order to avoid the worsteffects 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 fornewer energy technologies to become affordable and available at scale. Therefore, large scaleCO2 mitigation technologies for fossil fuels are necessary, which underpins the importance of carboncapture and storage (CCS); many countries will therefore need to adopt CCS, post-2020, to meet GHGreduction goals consistent with the ‘‘2�C target’’ are to be met. The IEA Energy Technology Pathwayhas found that CCS could deliver 19% of the total emission reductions required to meet the2�C target, and would require just 6% of the overall investment needed to achieve a 50% reductionin GHG emissions in 2050. It has been estimated that, without CCS, the overall costs to halve globalemissions by 2050 could rise by 70%.

CARBON CAPTURE AND STORAGECCS is not one single novel technology but rather represents a combination of largely existing andproven technologies to first separate or capture CO2 from different sources, the to compress andtransport it, and finally to inject it deep underground and monitor its movement. All of thesetechnologies have individually been deployed safely for many years – much experience oncompression, transport, injection and recirculation of large quantities of CO2 has been gained fromthe Enhanced Oil Recovery (EOR) industry in West Texas, which has been operating for decades – butthe combination of the technologies in a single project for the sole purpose of storingCO2 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, eitherthrough using CO2-rich gas fields as source or through using CO2-EOR as a sink. Six of the eightoperating projects are in natural gas processing, while the other two are in synthetic fuel production

1Source: IEA.2Source: 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:10http://dx.doi.org/10.5339/stsp.2012.ccs.10

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

and fertiliser production, and five of the projects involve EOR. In addition there are six large-scaleintegrated projects under construction, including the first project in the United States that will storeCO2 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 sandsupgraders, and the Gorgon project (Shell interest 25%), a liquefied natural gas (LNG) venture offWestern Australia that will include the largest CCS project in the world. The total CO2 storage capacityof all 14 projects in operation or under construction is over 33 million tonnes a year, broadlyequivalent to preventing the emissions from more than six million cars from entering the atmosphereeach 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 operationsbefore 2015. Moreover, all the other 74 globally-recorded LSIPs projects estimate a total injectionrate of 120 million tones of CO2 sequestered annually by 2020—far from the needed 300 milliontons by 2020 to achieve 50% reduction by 2050. Of these 74 projects 10 may decide within the next12 months whether to take a final investment decision and move into construction.4 Around tenlarge-scale projects have been put on hold or cancelled over the past year. The most frequently citedreason for a project being put on hold or cancelled is that the project was deemed uneconomic in itscurrent form and the general policy environment.

ACTIVITYA large number of universities and national or international GHG management and CCS consortiafrom around the world are active in the development, testing and demonstration of individual CCStechnologies. Current CCS fundamental research and developments concentrate on understandingthe impact of impurities in CO2 streams and the CO2 behaviour underground, to improve or developnew systems for monitoring, measurement and verification of stored CO2 and to develop second andthird 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 uncertaintymanagement are being deployed to characterize, assess and ultimately develop a storage complexthat can contain securely the CO2 from impacting groundwater and mineral resources. To this end theQatar Carbonate & Carbon Storage Research Collaboration launched in 2008 by Qatar Petroleum,Qatar Shell, Qatar Science & Technology Park and Imperial College London is developing theunderlying science and know-how to support secure and cost-effective large-scale CCS in the MiddleEastern 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 capturetechnologies and many engineering solutions are currently available, but there are no silver bullets; itis hard engineering work and new developments have to be tested at industrial scales. Shellpioneered gas and liquid treating and holds the leading position in the number of licenses for acidgas capture processes. Its portfolio of technologies covers deep and selective removal of gascontaminants, such as carbon dioxide, mercaptans and hydrogen sulphide for natural gas, andrefining and industrial process gases. Since the 1950s, Shell has built or licensed around 1,200 acidgas treatment plants throughout the global oil and gas industry. Fig. 1 shows the range oftechnologies Shell is using for these various applications. Selecting the most suitable process forCO2 removal is, to a great extent, determined by the nature of the CO2 source, the utilities available,and injection conditions of the CO2.

3Quest project would potentially capture 1 million tonnes of CO2 per year from the Scotford Upgrader, where bitumenproduced by Shell’s Athabasca Oil Sands Project is processed into synthetic crude oil.

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

5End of pipe flue gas scrubbing usually through a CO2 selective separation process like amines or other chemicalsolvents.

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

7Through combustion with pure oxygen in oxy firing, pure CO2 is produced in the combustion facility which, often afteradditional treating is compressed and stored.


CO2 separation and capture

Absorption Adsorption Cryogenics Membranes MicrobialProcess

Integration

InorganicPolymerHybridPhysicalChemical

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

In general, industry is maturing next-generation CO2 capture technologies to reduce costs andincrease efficiencies to allow scale up to commercial levels, thus making the technologyenvironmentally acceptable. To this end, improved and novel systems solutions are beinginvestigated with utility integration and utility-led designs and full-integrated capture, transport andstorage optimization of line-ups. On the process side, emphasis is on energy optimization andintegration, smart line-ups, minimizing process footprint (solvent losses, waste, toxicity),high-pressure separation and regeneration concepts. Smart equipment and materials are indevelopment concentrating on high efficiency contactors, heat exchangers and rotating equipmentand low-cost construction materials with low levels of required maintenance and high levels ofreliability. Innovative breakthroughs on adsorbents, solvents, membranes and hybrid solutions areexpected 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) thatis involved in applying the capture technologies.8 Solutions for reduction of parasitic CO2 emissionsare investigated through energy efficient solvents technology, heat integration and use of lowCO2-intense energy sources (i.e. waste heat, renewable energy). Although CCS costs, in particularinvolving flue gas capture systems, are currently high, around 50% cost reduction appears feasiblewhen deploying next-generation capture systems. Through the R&D effort and the earlydemonstration projects, efficiency in design and operation will reduce costs over the coming years, aswith 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 ascryogenic 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 andabsorbent carbonate slurries.

ShellShell is active in researching and developing next generation of CO2 capture systems from a variety ofsources, including sources that are generally:

1. High pressure and medium-to-high CO2 concentration in nature, such as gas processingfacilities for natural, high CO2-content reservoirs, hydrocarbon-gas-feeding gas treatmentplants, such as liquefied natural gas (LNG), gas to liquids (GTL) or domestic gas plants andHMU and gasification product streams. Higher partial pressure of CO2 usually leading to easierand cheaper CO2 removal.

8With today’s technology the parasitic CO2 emissions are in the order of 25–30% of the amount of CO2 that iscaptured.


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

Through our subsidiary Cansolv Technologies, Shell is involved in the 2012 piloting of its 2ndgeneration post-combustion capture system for deployment in large scale integrated CCS projectssuch as the ‘‘Boundary Dam’’ in Canada, for which the final investment decision was taken in May2011 with the government of Saskatchewan as co-funder. In a separate Shell paper reported in thisvolume, the breakthrough solvent technologies of Cansolv for low-cost, post-combustion capture andrelated industry-scale demos will be discussed in detail. In addition, Shell is involved in thedevelopment of 3rd generation post-combustion, potassium carbonate-based system (precipitatingcarbonate slurry) offering cost reduction, lower nitrosamines emissions and energy efficiencybreakthroughs.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 reducingcosts 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-combustioncapture, an environmental concern. After release of emissions of amines into the environment, thesubsequent photo-oxidative degradation mechanisms – with its environmental impact and toxicityaspects – 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 impliesthat studies into the degradation of amines and health aspects, as well as the development ofmitigation 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 measuresthat 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 toreduce emissions by around 90% over the longer term. CCS has huge potential but needsdemonstration projects to be in place quickly in order to realise its full potential in mitigatingCO2 emissions. The first wave of demonstration projects need to get up and running to drive downthe cost of CCS and to ensure that the lessons learned from this initial wave of demonstration projectswill drive the industry up the learning curve for the larger wave of commercial scale investment gradeplants 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 globalCCS deployment, can still be considered of global benefit because emissions are captured andstored. Given that CCS exists primarily as a CO2 mitigation solution, government policies toencourage and support progress are vital. This requires that many enablers are put in place, such asclarity on liabilities, the building of public confidence and support, stable regulations and a proventechnology and value chain. Clear incentives, linked to policy goals, that give the necessary pricesignals to the value of emissions avoided are important, as these will support the action to driveinvestment into CCS projects. Without government support, a global CCS effort will not appear. Theinescapable truth is that CCS will be needed. According to the IEA, we need to see 100 CCS projectsby 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.

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

OPEN ACCESS


Published: 20 December 2012c� 2012 Korre, Nie, & Durucan,licensee Bloomsbury QatarFoundation Journals. This is anopen access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Review article

Life Cycle Assessment of the naturalgas supply chain and powergeneration options with CO2 captureand storage: Assessment of Qatarnatural gas production, LNGtransport and power generation inthe UKAnna Korre*, Zhenggang Nie, Sevket Durucan

MERG, Department of Earth Scienceand Engineering, Royal School of Mines,Imperial College London, SW7 2BP, UK*Email: [email protected]

ABSTRACTFossil fuel-based power generation technologies with and without CO2 capture offer a number ofalternatives, which involve different fuel production and supply, power generation and capture routeswith varied energy consumption rates and subsequent environmental impacts. The holisticperspective offered by Life Cycle Assessment (LCA) can help decision makers to quantify thetrade-offs inherent in any change to the fuel supply and power production systems and ensure that areduction in greenhouse gas (GHG) emissions does not result in increases in other environmentalimpacts. Beside energy and non-energy related GHG releases, LCA also tracks various otherenvironmental emissions, such as solid wastes, toxic substances and common air pollutants, as wellas the consumption of resources, such as water, minerals and land use. In this respect, the dynamicLCA model developed at Imperial College incorporates fossil fuel production, transportation, powergeneration, 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 assessmentof technical and geographical differences between the alternative technologies considered. The lifecycle inventory (LCI) databases that were developed, model the inputs and outputs of the processesat component or unit process level, rather than ‘‘gate-to-gate’’ level, and therefore generate reliableLCI data in a consistent and transparent manner, with a clearly arranged and flexible structure forlong-term strategic energy system planning and decision-making.The presentation discussed the principles of the LCA models developed and the newly extendedmodels 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 pipelinetransportation, gas processing, liquefied natural gas (LNG) processes, LNG shipping and LNGreceiving terminal developed are used to estimate the life cycle GHG emissions for an idealised casestudy of natural gas production in Qatar, LNG transportation to a UK natural gas terminal and use in apower 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 supplychain and power generation options with CO2 capture and storage: Assessment of Qatar naturalgas production, LNG transport and power generation in the UK, Sustainable Technologies,Systems and Policies 2012 Carbon Capture and Storage Workshop:11http://dx.doi.org/10.5339/stsp.2012.ccs.11

of 11Korre, Nie, & Durucan, Sustainable Technologies, Systems and Policies 2012.CCS.11

INTRODUCTIONAccording to the recent World Energy Outlook report, the world energy demand will grow by 35% by2035, assuming that recent government policy commitments will be implemented in a cautiousmanner [1]. Although the share of fossil fuels in the global primary energy consumption is expectedto fall slightly, from 81% in 2010 to 75% in 2035, natural gas is the only fossil fuel to increase itsshare in the global mix in the period up to 2035 [1]. Arguably, the growth of energy demand has thepotential to cause a significant increase in greenhouse gas (GHG) emissions associated with climatechange. It is widely accepted that, in terms of energy, the coming decades will be challenging for allnations 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 inproviding solutions to both secure economic growth and prosperity, and to reduce greenhouse gasemissions in economically feasible ways [2]. Together, with the development of renewables andnuclear energy, clean fossil fuel technology with carbon capture and storage is an essential part offuture 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 bedirectly, from the operations, or indirectly, through the upstream processes required in theirimplementation. For example, carbon dioxide capture processes can result in both direct and indirectGHG emissions and other environmental impacts [4–6]. This is also the case for renewabletechnologies; for example, considerable GHG emissions occur from the consumption of energy inmanufacturing 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 inpower generation, tracking GHG releases throughout all stages of power generation life cycle (orvalue chain). It is then possible to provide accurate information for decision makers and ensure that anew power generation technology option would not result in upstream or downstream changes thatwill increase the overall release of GHGs. It is also important to ensure that the power generationsystems considered do not aggravate other environmental concerns, such as solid and hazardouswaste generation and the release of toxic substances which impact upon human health andecological 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, toxicsubstances 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 thetrade-offs inherent in any change to the power production systems and helps to ensure that areduction in GHG emissions does not result in increases in other environmental impacts. The otherstrength of LCA is that the International Organization for Standardization (ISO) has developed the ISO14040 series of LCA standards, which provide guidance on setting appropriate system boundaries,reliable data collection, evaluating environmental impacts, interpreting results, and reporting in atransparent manner. This offers an excellent starting point for the development of measurementprotocols for GHGs and other environmental impacts [7]. Considering the three flexible mechanismsdeveloped to help emitters in developed countries to meet their GHG emission targets (EmissionsTrading, Joint Implementation and the Clean Development Mechanism), LCA offers the means toinclude new power generation projects into the CDM framework and help the participants of flexiblemechanisms to assess their proposed projects and verify their emission reductions from a valuechain 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 byprevious LCA studies [8–16]. 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 rangingresults 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 LCAstudies. The use of gate-to-gate data implies that the electricity generation systems have been largelysimplified to a single black box with constants and linear coefficients used to assign inputs andoutputs, covering a broad range of technological and geographical differences, in which the actualvariability of process parameters and operating conditions are implicitly neglected. In addition, plant


level analysis limits the capacity of such studies to quantify the trade-offs inherent in any change tothe power production systems and restrict the ability to identify design options that eliminate highlypolluting emissions.In this respect, the dynamic LCA model developed at Imperial College incorporates fossil fuel

production, transportation, power generation, CO2 capture, CO2 conditioning, pipeline transportationand CO2 injection and storage, and quantifies the environmental impacts at the highest level ofdetail. This allows for the assessment of technical and geographical differences between thealternative power generation, CO2 capture, transport and storage technologies considered. Earlierpublications by the authors [4,6] present the post-combustion life cycle model developed and acomparative assessment between the post-combustion and oxy-fuel capture options modelled forcoal fired plants. This paper presents the principles of the LCA models developed and the newlyextended 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 andLNG receiving terminal developed are used to estimate the life cycle GHG emissions for an idealisedcase study of natural gas production in Qatar, LNG transportation to a UK natural gas terminal anduse in a power plant. The scenario considers a conventional and three alternative CO2 capturesystems, transport and injection of the CO2 off-shore in the Irish Sea.

LIFE CYCLE ASSESSMENT METHODOLOGY AND ITS APPLICATION IN POWER GENERATION WITHCO2 CAPTURE AND STORAGELife Cycle Assessment methodologyLife Cycle Assessment is a compilation and evaluation of the inputs and outputs and the potentialenvironmental impacts of a product system throughout its entire life cycle, ranging from raw materialextraction and acquisition, through energy and material production and manufacturing, to use andend of life treatment and final disposal [17]. In order to deal with the complexity of LCA, theInternational Standards Organisation (ISO) established a methodological framework for performingLCA studies, which comprises four phases, including the goal and scope definition, Life CycleInventory Analysis (LCI), Life Cycle Impact Assessment (LCIA) and Interpretation, as shown in Fig. 1.

Life Cycle Assessment and framework (ISO 14040)

Goal and scopedefinition

Inventory analysis

Impact assessment

Interpretation

Direct Applications:

Development and improvement

Strategic planning

etc.

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, thefunctional unit, competing systems considered, and the breadth and depth of (or level of detail) theLCA study in relation to this aim. Life Cycle Inventory Analysis is the phase where input/outputrelationships are quantified and an inventory of input/output data for all component processesinvolved in the life cycle of the system(s) under study is prepared. The input/output flows for a unitprocess 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


INPUTS OUTPUTS

Economicflows

Economicflows

Product Product

ProductsServices Services

Materials MaterialsEnergy Energy

Wastes (for treatment) Waste (for treatment)

UNIT PROCESS / PRODUCT SYSTEM

Environmentalinterventions

Environmentalinterventions

Abiotic resourcesBiotic resources

Land transformationLand occupation

Goods

Chemicals to the air

Chemicals to the soilChemicals to water

RadionuclidesSound

Waste heatCasualtiesEtc.

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

categories (e.g. global warming, acidification, and human toxicity), category indicators, andcharacterisation factors are defined first. Then the LCI results are assigned to categories andconverted into category indicators via characterisation factors. Characterisation factors can convertenvironmental 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 ofcause–effect chain (including fate, exposure, effect and damage) and uses midpoint indicators (suchas global warming potential, acidification etc.) to reflect the relative environmental importance of anemission or extraction. The endpoint approach models the cause–effect chain up to the finalenvironmental damages, the damages to human health, ecosystems and resources. Interpretation isthe phase in which the findings of either the inventory analysis or the impact assessment, or both, areanalysed in relation to the defined goal and scope in order to deliver conclusions, explain limitationsand provide recommendations [17].

LCA application in power generation with CO2 capture and storageOne of the objectives of the dynamic LCA model developed at Imperial College was to build acomprehensive LCI database for the analysis of power generation with alternative CO2 capture andstorage options and of fossil fuel supply chain, in a consistent and transparent manner. Theunderlying 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 whichthe inputs/outputs of any unit process have been quantified.

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

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

The system boundaries of LCA in power generation with CO2 capture and storage, a generalisedoutline of which is presented in Fig. 3, covers power generation, alternative CO2 capture options andupstream processes such as extraction and processing of fossil fuels, raw materials production, aswell as CO2 compression, transport and storage. The functional unit selected for the analysis was1 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 withpost-combustion CCS system. The component unit processes are connected through flows ofintermediate products or emissions as illustrated in Fig. 4. The purpose of modularisation was tomake complex systems more easily understood and more accurately modelled. Throughmodularisation, the LCI models quantify flows of materials, natural resources, energy, intermediateproducts 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 beaccounted for by modifying the parameters of the component unit processes as necessary.


Natural resourcesEmissions to air,

water and soilElectricity and

by-products

Power Generation with CO2 CaptureExtraction of

fossil fuelConsumables

Production

Raw Material Production

Upstream processes

infrastructure

Power plant and CO2 capture facility

infrastructure

CO2 injection infrastructure

CO2 pipeline infrastructure

CO2 Conditioning

CO2 Transportation

CO2 Storage

Processing of fossil fuel

Fossil fuel transportation

Consumables transportation

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

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

Potential CO2Leakage to Air

Air,

Natural gas (components):

Soil wastes: Discharge to surface waters

Electricity

CO2 captureCO2conditioning

LP steam

CO2 pipeline transportation

CO2 saline aquifer storage

Storm water basinWater

treatment plant

Air cooled condenser

CO2

CO2

Energy

CO2 injection

CO2

HRSG

Fluegas

FluegasGas

CombustionTurbine

SteamTurbine St

ack

Steam

Wastewater

CO2depleted flue gas

HRSGblowdown

Condensate return

Exhaust steam

Water make-up

Effluent

WaterSodium HydroxideSulphuric acid

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 differenttechnical and engineering scenarios from a life cycle perspective. Ultimately, modularisationeliminates the limitations introduced by the linear input/output coefficients used by conventional LCImodels.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 aqueousCO2 absorption and CO2 stripping system, which is comprised of two sections (Fig. 5). In theabsorber, CO2 is chemically absorbed from the inlet gases by contacting it with the countercurrentCO2-lean solvent, e.g. monoethanolamine (MEA). The treated gas exits the top of the absorbercolumn. The CO2-rich solvent is passed to the stripper, where, by heating the CO2-rich solventsolution, the CO2 is stripped off and the CO2-lean solvent is regenerated. The regenerated CO2-leansolvent is then recycled back to the absorber and the CO2 is passed to compression processes. Thesystem, especially MEA solvent system, also uses chemicals (such as NaOH) for proposes of solvent


AB

SOR

BER

STR

IPPE

R

CO2 depleted Flue Gas

CO 2 H2O

(SO 2) (NOx )

WasteDiluted Flue Gas

3-15% CO2

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

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

HX

Reboiler

Reclaimer

Lean solvent

Rich solvent

Filtration

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 thecompensation 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 usingengineering calculations. In order to characterise the technological differences of different chemicalabsorption CO2 capture processes, the LCI model developed accounts for 8 types of solvents. Fig. 7shows the LCI results of a MEA CO2 capture system applied to a coal-fired power plant withpost-combustion configuration.

CASE STUDY: QATAR NATURAL GAS PRODUCTION, LNG TRANSPORT TO THE UK AND USE INPOWER GENERATIONThe LCA models developed at Imperial College have been applied to an idealised case of natural gasproduction in Qatar, LNG transport to the UK and use in power generation systems with alternativeCO2 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 LNGships. The gas received is regasified at South Hook terminal. The regasified gas is transported topower plant by pipeline. Four types of gas power plant configurations have been investigated in thecase study. They are conventional natural gas combined cycle (NGCC) plant, NGCC plant with


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

Qutar North Fieldoffshore naturalgas production

Gasprocessing

and LNGplant at Ras

Laffan

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

UK via Suez

Receivingterminal at SouthHook + onshoregas pipeline to

power plant

Alternative gas power generationwith/without CO2 capture

CO2 pipelinetransportation

CO2 injectioninto saline

aquifer

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), andauto-thermal reforming (ATR) plant with pressure swing adsorption (PSA) CO2 capture. The capturedCO2 is transported by pipeline to saline aquifer storage site, where CO2 is injected underground.Tables 1–4 provide the key parameters or operational parameters of the supply chain, of

alternative power plant configurations without or with CO2 capture, CO2 transportation, and ofCO2 injection to a saline aquifer. The LCA model developed not only accounts for these keyparameters but also the operational parameters at unit processes level. The user can change theseparameters in order to apply fully and dynamically the LCA models to a specific case study, allowingfor 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 theLNG receiving terminal as demonstrated in Fig. 9. The GHG emissions from the offshore platform andpipeline transportation are not significant. Fig. 9 also indicates that insignificant GHG emissions aredue 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


Table 1. Supply chain parameters/operational parameters.

Qatar North Field PlatformNatural gas platform production rate 1,730 MMscf/dayNatural gas reservoir life span 20 yearsPlatform drilling 3.5 yearsNumber of wells predrilled 10 wells

Offshore pipeline: from North Fieldplatform to Ras Laffan

Distance 80 km

Onshore NG processing plant at RasLaffan

Plant throughput 1,730 MMscf/day

Ras Laffan LNG plant Plant capacity 15.6 MTPANumber of trains 2CO2 content in NG to be processed 0.50 %

LNG shipping Distance 11,281 kmVelocity 36.12 km/hourCarrier volume 266,000 m3

Onshore LNG receiving terminal atSouth Hook, UK

Capacity 1,730 MMscf/day

Onshore pipeline: South Hook to Powerplant

Distance 100 km

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

CCGT power plant

Power plant capacity (MW) 500Atomic ratio of H/C, 3.886Fuel to air equivalence ratio 0.85Pressure drop rate in the combustor,1pc/pc (%) 3Combustor inlet pressure/reference pressure, Pc/Pref 15.8Combustor inlet temperature/reference temperature, Tc/Tref 1.8combustor inlet pressure, pc (Pa) 1,600,000Steam/fuel ratio 0

CCGT with MEA CO2 capture powerplant

Power plant capacity (MW) 500Atomic ratio of H/C, 3.886Fuel to air equivalence ratio,8 0.85Combustor inlet pressure, pc (MPa) 1.6Flue gas bypass rate 0Gas turbine plant thermal efficiency (%) 55

ATR with PSA power plant

Power plant capacity (MW) 500Natural gas hydrogen/carbon ratio, HC 3.886Steam/Carbon ratio, SC 2O2/Carbon ratio, OC 0.5H2 recovery ratio, HR (%) 95H2 to electricity efficiency, HE (%) 60

Steam Methane Reforming with H2Membrane power plant

Power plant capacity, MW 500Natural gas hydrogen/carbon ratio H/C 3.8862SMR + Membrane temperature (K) 1,075SMR + Membrane pressure (bar) 10Steam/carbon ratio 3H2 to electricity efficiency (%) 60

Table 3. CO2 transportation operational parameters.

Mass flow rate of CO2 product in pipeline (kg/s) 44.84Length of the pipeline (km) 150CO2 velocity in pipeline (m/s) 2CO2 inlet pressure (MPa) 15CO2 outlet pressure (MPa) 15CO2 temperature (�C) 25

CO2 capture. This also results in the highest GHG emissions per MW generated, compared to theother power plants with CO2 capture. ATR with CO2 PSA capture power plant has low energyefficiency. This is due to the fact that the configuration of ATR with CO2 PSA capture requires pureO2 from the Air Separation Unit, which consumes energy. On the other hand, the concentration ofH2 in the offgas exiting from PSA unit is high. The H2 in the offgas is combusted, rather than beingconverted to electricity. This also reduces the whole plant energy efficiency.


Table 4. CO2 injection operational parameters.

CO2 injection rate (t/hr) 161.44Depth of reservoir (m) 1239Reservoir horizontal permeability (mD) 22Reservoir vertical permeability (mD) 22Reservoir pressure (MPa) 8.4Reservoir Thickness (m) 171Surface temperature (F) 68Temperature increase in CO2 heater (F) 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 withH2 membrane plant, CCGT with MEA CO2 capture plant and ATR with CO2 PSA capture plant are3.51%, 6.09% and 11.75% respectively. The energy penalties of CO2 capture by SMR withH2 membrane plant and CCGT with MEA CO2 capture plant are lower than energy penalties ofCO2 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 emissionsare from gas processing plant, LNG plant, LNG shipping and power plant. Our operation processes orconstruction processes account for insignificant GHG emissions in the life-cycle perspective.

CONCLUSIONSThis 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 theLCA model developed is demonstrated using natural gas produced in Qatar shipped to the UK by LNGand used in power plant with alternative configurations and CO2 capture routes. The LCI modelsdeveloped quantify flows of materials, natural resources, energy, intermediate products andemissions at component unit process level, based on fundamental physical/chemical principles orempirical relationships which, to a greater extent, account for the technological, spatial and temporalcharacteristics of the power generation systems considered. This approach not only addresses thelimitations of conventional LCI models that use linear input/output coefficients, but also facilitatesthe screening of technological options in order to improve the life cycle environmental performanceof 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 handlethe complexity of fossil fuel power generation systems and reduced the LCA model uncertainty. Themodels 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 LCImethodology developed at Imperial College provides an innovative and robust approach forconducting LCA for novel systems by configuring virtual systems at unit process level.


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 capturesystems can significantly reduce life-cycle GHG emissions by 74%–85%. For gas power plants withalternative 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 decreaselife-cycle GHG emissions significantly. This also implies that gas power plants with CO2 capture usinggas from different supply chains can have considerable variation in their carbon foot print.

REFERENCES[1] International Energy Agency (IEA) 2011, IEA world energy outlook 2011 exclusive summary;

http://www.iea.org/Textbase/npsum/weo2011sum.pdf.[2] Bulteel P. and Capros P. Untying the Energy Knot of Supply Security, Climate Change, Economic Competitiveness:

The Role of Electricity, 2007. http://www.worldenergy.org/documents/p001469.pdf.[3] Kannana R., Leonga K.C., Osmana R., Hoa H.K. and Tsob C.P. Life cycle assessment study of solar PV systems: An

example of a 2.7 kWp distributed solar PV system in Singapore. Solar Energy. May 2006;80:5, 555–563.[4] Korre A., Nie Z. and Durucan S. Life cycle modelling of fossil fuel power generation with postcombustion

CO2 capture. Int. J. Greenhouse Gas Control. 2010;4:2, 289–300.[5] POSTNOTE 383 June 2011 Carbon Footprint of Electricity Generation. UK Houses of Parliament, The Parliamentary

Office of Science and Technology.

http://www.iea.org/Textbase/npsum/weo2011sum.pdf

http://www.worldenergy.org/documents/p001469.pdf


[6] Nie Z., Korre A. and Durucan S. Life cycle modelling and comparative assessment of the environmental impacts ofoxy-fuel and post-combustion CO2 capture, transport and injection processes. Energy Procedia.2011;4:2510–2517.

[7] Adams B. and Senior C. Curbing the blue plume: SO3formation and mitigation. Power. May 2006;150:4, 39–41.[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 shellgasification-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 powergeneration. 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 withpostcombustion 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 CO2emissions: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 withpost-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: Anoperational 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 ImpactAssessment: Methodology Report, no. 1999/36A. 3rd ed., Pre Consultants b.v, Amersfoort, the Netherlands.2001.

http://dx.doi.org/doi:10.1016/j.ijggc.2010.03.006

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Published: 19 December 2012c� 2012 Lindstedt, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Gas turbine related technologies forcarbon captureR. Peter Lindstedt*

Department of Mechanical Engineering,Imperial College, Exhibition Road,London SW7 2AZ, UK*[email protected]

ABSTRACTCombustion modes in gas turbines are evolving in order to meet requirements related to loweremissions and greater thermodynamic efficiency. Such demands can be contradictory and theadditional complication of fuel flexibility comes to the fore with potential new fuel streamopportunities arising. The latter may include hydrogen and carbon monoxide rich streams as well asblends 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 issuesthat arise in the context of the ubiquitous transition to lean pre-vapourised premixed (LPP)combustion for power generation applications. Post-combustion carbon capture is generallyconsidered the leading candidate in the context of LPP based technologies. Significant capturerelated issues arise in terms of parasitic losses associated with CO2 separation and transportationtechnologies (e.g. compression). The former is typically the major contributor and the relatively lowconcentration 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 thegas turbine and the impact of the fuel composition on the flue gas characteristics alongside thedevelopment of efficient and novel separation technologies.

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

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

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

INTRODUCTIONThe use of carbon capture and storage (CCS) has been identified as a potentially significantcontributor in the quest for reduced CO2 emissions with the IEA suggesting [1] that deployment in thecontext of industrial and power generation applications can make a 19% contribution towardsmeeting the Blue Map Scenario. The potential success of carbon capture (CC) technologies dependsto a significant extent on the ability to maintain a high overall efficiency of the process cycle and, byimplication, a reduction in parasitic losses associated with CO2 separation technologies. Such losseshave been estimated to range from 6 to 8% depending on the process used [2] with a correspondingimpact on fuel consumption and cost of operation. By means of comparison, the move to advancedgas turbine based combined cycle plants from older gas-fired boilers can be expected to increase theefficiency [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 andthe need for improved technologies and process optimization arises. In order to achieve optimalperformance it appears natural for the gas turbine component to be considered alongside thedevelopment of (novel) separation processes. Hence, it is argued that, in addition to achievingoptimum gas turbine efficiencies and low emissions, consideration should also be given to theexploration of combustion modes that permit subsequent separation processes to operate atmaximum efficiency and vice versa. In other words, an additional constraint arises alongside currentchallenges associated with demands for fuel flexibility and the generalization of the combustionmode transition to lean pre-vapourised premixed operation.

TECHNOLOGY CHALLENGESThe brief summaries provided below are primarily intended to provide a background for discussionand the identification of technology needs.

Capture optionsPost-combustion capture has the key advantages that retro-fit is possible and that power generationcan continue in the absence of capture should an outage occur. It can readily be argued that thealternatives of oxy-fuel combustion and pre-combustion capture are not suitable options. The use ofoxy-fuel combustion has the advantage of providing CO2 rich flue gases. However, the impact oncombustion stability, combustion temperatures and emissions in a gas turbine context is likely toprove 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 thatsyngas 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 suitablefuel streams. In addition, H2 rich fuel streams will arise in the context IGCC plants and can in principlebe used in gas turbines subject to the applied combustion mode.

Gas turbine technologiesThe challenges associated with the transition to LPP based combustion modes for power generationare well known and have been the subject of intensive research programs in the EU and the US. It isnot the intention to review these extensive efforts as part of the current paper, though it is relevant topoint out that more reactive fuels (e.g. hydrogen rich streams) present greater challenges. It may alsobe noted that active and passive control strategies have been explored as well as efforts aimed atcreating more intrinsically stable combustors. Some of the guidelines that can be followed have beenoutlined [5] and solutions that permit the use of combustion regime independent calculationmethods have been developed jointly with gas turbine manufacturers [6]. The design ideassummarised by Milosavljevic et al. [5], based on targeted near field aerodynamics, contributed to thecommercial launch of the Siemens SGT-750. The novel stabilization and design approach used forthe burner resulted in the filing of a large number of patent applications and provide a pointertowards 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 flametemperatures in the range 1550–1850 K during piloted operation, less than 1 ppm CO at flametemperatures above 1450 K, reduced issues pertaining to combustion dynamics and stablecombustion over a wide range of temperatures. The use of a rich pilot combustor (RPC) stabilised the


flame for both rich and lean conditions, with the main flame stability not reliant on the RPC at highloads 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

8.0

7.0

6.0

5.0

4.0

3.0

2.0

1.0

0.00.0 10.0 20.0 30.0

CO ppm

NO

x (1

5% O

2)

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

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

Fuel blendsConventional fuel blends used in the context of gas turbines for propulsion devices have receivedmuch attention as part of world-wide research efforts and summaries are available [7,8] along withincreasingly accurate chemical kinetic mechanisms [9]. It is, however, notable that whileFischer-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 chemicalkinetics into design calculations is often not possible. The knowledge of the corresponding lowerhydrocarbon chemistry is much further advanced and for hydrogen and methane progress has beenmade to the point where properties of both laminar and turbulent systems can be computed withgood accuracy [10,11]. There are, however, gaps in our understanding of the behavior of hydrogenrich fuel blends as may arise, for example, in the context of refinery gas and syngas from differentsources. Issues that remain to be addressed also include the impact of smaller quantities of morereactive hydrocarbons upon the combustion characteristics of such mixtures in the context of gasturbines operating in a LPP mode.

Pollutants in flue gasesCombustion generated oxides of nitrogen and sulphur may have an impact on subsequentCO2 separation technologies. The problems associated with oxides of sulphur can be expected to beinsignificant 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-combustionCO2 removal. The amount of NOx formed is strongly dependent upon the gas turbine combustiontechnology and the sensitivity of subsequent processes can be expected to influence technologyoptions. The inter-conversion of oxides of nitrogen and sulphur in flue gases resulting from oxy-coalcombustion has been studied computationally [12–14] using detailed chemical kinetic modeling.The gas phase chemistry was based on a comprehensively validated C/H/N/S kinetic model featuring75 chemical species and 406 reversible reactions. A novel aqueous phase extension, featuring 13chemical species and 20 reversible reactions, was also implemented along with mass transferbetween both phases. Missing or outdated thermodynamic data was calculated using G3B3 quantummechanical methods and the chemistry extended to include low temperature pathways usingRRKM/ME based methods [15]. Computed results were compared with experimental data obtainedfrom a Doosan Babcock 160 kW coal-fired oxy-fuel rig as exemplified in Fig. 2.


100%

75%

50%

25%

0%0 50 100 150 200 250 300 350 400

Time (s)

% C

onve

rsio

n

SO2NOxExperimental SO2Experimental NOx

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

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

CONCLUSIONSThe following directions for future research are suggested:

1. The interface between gas turbine and CO2 separation technologies can usefully be consideredmuch 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 separationtechnologies can be considered in greater detail. This includes the role of potential pollutantssuch as oxides of nitrogen.

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

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

It is, of course, possible to define further research and development directions and to provide amore fine-grained breakdown of the above. Nevertheless, it is notable that the above topics are likelyto 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-netherlands-paving-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 PDFmethods. 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 ExperimentalDatabase and Kinetic Models for Surrogate Jet Fuels, Paper AIAA-2007-770, Presented at 45th AIAA AerospaceSciences 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 ValidationData for Development of Surrogate Jet Fuels, Paper AIAA-2008-972, Presented at 46th AIAA Aerospace SciencesMeeting, Reno (2008).

http://www.alstom.com/press-centre/2008/12/alstoms-orders-from-essent-confirmed-in-the-netherlands-paving-the-way-for-major-combined-cycle-power-plant/

http://www.alstom.com/press-centre/2008/12/alstoms-orders-from-essent-confirmed-in-the-netherlands-paving-the-way-for-major-combined-cycle-power-plant/

http://dx.doi.org/doi:10.1016/j.proci.2006.08.123

http://dx.doi.org/10.1016/j.proci.2010.05.092


[9] Wang H., Dames E., Sirjean B., Sheen D.A., Tangko R., Violi A., Lai J.Y.W., Egolfopoulos F.N., Davidson D.F., HansonR.K., Bowman C.T., Law C.K., Tsang W., Cernansky N.P., Miller D.L. and Lindstedt R.P. A high-temperature chemicalkinetic model of n-alkane (up to n-dodecane), cyclohexane, and methyl-, ethyl-, n-propyl and n-butyl-cyclohexaneoxidation 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 inCH4/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 oxidationand 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 fromoxycoal 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.

http://melchior.usc.edu/JetSurF/JetSurF2.0

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Published: 18 December 2012c� 2012 Palmer, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

An overview of carbon capturetechnologyBruce R. Palmer*

Chemical Engineering Program, TexasA&M University at Qatar, Doha, Qatar*Email: [email protected] CARBON CAPTURE FROM NATURAL GAS

Natural gas produced from gas and/or petroleum reservoirs could contain substantial amount ofhydrogen sulfide and carbon dioxide, known as ‘‘acid gas.’’ The presence of small concentrations ofH2S (ppm levels) in natural gas results in a sour gas with a drastically-reduced market price andhampered wide utilization. Additionally, the presence of CO2 in the natural gas could decrease itscalorific value and increase its transportation cost. Therefore, natural gas desulfurization, orsweetening processes for treating natural gas, are an integral part of natural gas cleanup. After H2S iscaptured chemically using a base solvent such as aqueous amines, the concentrated H2S streams aresent to the Claus sulfur plants to produce elemental sulfur or can be used to produce sulfur oxideswhich are converted ultimately into sulfuric acid or used to produce gypsum [14].The amines frequently used to capture H2S 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 theatmosphere after hydrogen sulfide is converted to sulfur or can be captured and sent to sequestrationsites, depleted petroleum, and or/natural gas reservoirs or saline aquifers for disposal. TheCO2 captured from natural gas streams can also be used for enhanced oil recovery (EOR) to produceoil from petroleum reservoirs (see Fig. 1).

Coalbedmethane

production

Deepcoal

seam

Deepbrine formation

Depletedhydrocarbonreservoir

Reservoirtrap/seal

Naturalgasreservoir

Brine formation

Injection of CO2 in to geologicreservoirs

Pipelinetransporting CO2

from power plants to injection site

Offshore natural gasproduction with CO2

separation and sequestration

Original illustration by Eric.A. Morissdey. U.S. Geological Surveyillustration 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 significantamounts of water so that its injection in a geologic formation requires multistage high-pressurecompressors with intercooling. Based on the depth and conditions of the geologic formation, theinjection is frequently carried out at about 150 bars. If the CO2 to be sequestered still contains asmall fraction of H2S, this acid gas can be also injected in the geologic formation without majorCite this article as: Palmer BR. An overview of carbon capture technology, SustainableTechnologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:13http://dx.doi.org/10.5339/stsp.2012.ccs.13

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

difficulties. The only problem would be that wet H2S is highly corrosive to carbon steel so stainlesssteel facilities are required after the compression station. The compression plant is shown in Fig. 2.

Captured CO2

CO2

Pipeline

1st Stage 2nd Stage 3rd Stage 4th Stage

Dehydration

Dew point control

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 fieldin Norway. The produced natural gas contains about 9% CO2. In this North Sea field, one milliontons/year of liquefied carbon dioxide is injected into a saline aquifer in the Utsira sandstoneformation as shown in Fig. 3. Injection depth is one kilometer. The sandstone formation has a storagecapacity of about 600 billion tons of carbon dioxide. The project economics are very favorable, basedon 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 increasinglyhigher sulfur content must be tapped. This natural gas will be required to meet the considerablenatural gas demands of the Middle East and the natural gas customers of this region. Acid–gasinjection is being considered in the Middle East as a means to dispose of the tremendous amounts ofCO2 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 producedfrom power generation facilities contains particulates and about 15% by volume carbon dioxide. Atypical process for treating combustion products, including carbon dioxide removal, is shown inFig. 4. The flue gas cleanup techniques involve (1) injection of ammonia followed by catalytic reactionto remove NOx (2) removal of particulates by electrostatic precipitation (3) removal of sulfur dioxidewith 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 carbondioxide removal are monoethanolamine (32%), diethanolamine (20–25%), methyldiethanolamine(30–55%) and diglycolamine (50%). In the capture process, the aqueous amine, which is a weakbase, reacts with acidic CO2, to form water-based aminated products. This is illustrated below forreaction with monoethanolamine [12,17]:

2RNH2(aq) + CO2(g) + H2O(l) ! RNHCOO�(aq) + RH+

3 (aq). (1)


Boiler

Electrostatic precipitator

(ESP)

Selective catalytic

reactor (SCR)

NH3

Air heater

Flue gas desulphurization

(FGD)CO2 recovery

CO2

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 andnear atmospheric pressure.Some gas streams contain both CO2 and H2S. This is the case in processing natural gas, for

example. The sulfur-bearing H2S is also acidic and is extracted by amines as indicated below,

RNH2(aq) + H2S(g) $ RNH3HS(aq). (2)

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

Makeup water

Sweet gas

Absorber

Sour Gas

Toptray

Toptray

Bottom tray

Bottom tray

Lean

amin

e

Leanamine

cw

cw

Richamine

Richamine

Liquid

Pump

Pump

Vapour

Regenerator

Steam

Reboiler

Condensate

Reflux

Condenser

Reflux drum

(H2S + CO2)Acid gas

Typical operating ranges

Absorber : 35 to 50°C and 5 to 205 atm of absolute pressureRegenerator : 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 carbondioxide capture at an electric generation utility at the Searles Valley, California, chemical plant. Theplant ran for several decades, and the technology was licensed to the Shady Point Power Plant inOklahoma in 1991 [1].


While acid–gas treatment and carbon dioxide capture with amines are similar, there are substantialdifferences 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 dioxidecapture from combustion gases operates near atmospheric pressure. Additionally the volume of gasfrom combustion processes is substantially greater than the amount of natural gas processed inamine units, and accordingly the equipment for combustion processing is substantially larger thanthe 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 gasifiedin 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 capturebecause 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

(H2S, SOx) and then is subjected to a water-gas-shift (WGS) reaction where CO reacts with water inthe 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 asshown below:

CO(g) + H2O(g) ! CO2(g) + H2(g) (3)

At high temperatures, 350�C, iron oxide promoted with chromium oxide iron oxide promoted withchromium oxide is employed. As the temperature drops to 190–210�C, copper supported by amixture 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 44commercial-scale gasification units. A number of acid–gas treatment options are employed asdescribed 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 thereis a wide range of experience in application of this extractant. Additionally, it has been formulatedwith 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. Selexolremoves hydrogen sulfide preferentially to carbon dioxide so these gases can be separated, ifrequired. 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 carbondioxide.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 desiredtwo-stage removal of acid gas can be carried out, hydrogen sulfide is removed first followed bycarbon dioxide. High concentration gases are produced in stripping, reducing subsequentsequestration costs. Reduction in the solvent temperature increases removal of hydrogen sulfide andcarbon 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 themost costly process for treating acid gas. Accordingly, the Rectisol process probably is of limitedapplication 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, COand CH4. The use of an ionic liquid, a quaternary ammonium polyether, was also investigated forcapture of CO2 [7,8]. This work paves the way for cleanup of syngas under warm conditions, allowingelimination of refrigeration in the sorption process.


Production of carbonyl sulfide, COS, can pose a problem in both IGCC and Claus sulfur recoveryunits, because this species does not react with amine solvents. Carbonyl sulfide removal can beeffected by hydrolysis; the reaction is as follows:

COS(g) + H2O(g) ! CO(g) + H2S(g). (4)

This reaction is facilitated with an activated alumina-based catalyst and is normally designed tooperate at 175 to 200�C. Hydrolysis thermodynamics become more favorable as the temperature isreduced so the operating temperature is a balance between the kinetic and thermodynamicconsiderations. Typically, the hydrolysis product gas is cooled using the sensible heat to generatesteam 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 whenthe MDEA and Selexol processes are employed. Conversely, very high extractions of hydrogen sulfideand 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 carbonmonoxide shift reactor followed by acid–gas absorption. In this instance, hydrogen sulfide can beremoved in one acid–gas removal process (absorber and stripper), and carbon dioxide is removed inthe subsequent acid gas removal step (absorber and stripper). The WGS may be carried out prior toacid–gas absorption with a catalyst that can tolerate sulfur. This process is illustrated in Fig. 6.

FEED

SULPHUR REMOVAL

STEAM

TO CLAUS

H2SSTRIPPER

CO2

STRIPPERH2SABSORBER

CO2

ABSORBER

TO METHANATOR

VENT

AIR

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 COMBUSTIONThis process involves combustion of coal in oxygen. The products of combustion are water andcarbon dioxide. Early work by Argonne National laboratory is reported by Kumar et al. [20]. Theadiabatic flame temperature in oxy-fuel combustion is very high so that the flame temperature ismoderated by dilution of oxygen with the carbon dioxide produced in combustion. Carbon dioxide iscooled before utilization as the diluent. Water is removed from the gases produced in combustion bycondensation, and the resulting carbon dioxide is nearly pure. This technique has a number ofattributes; 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 attributesare 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 produce150,000 tonnes/year of CO2 for about four years. The injection of CO2 into the Northern DenisonTrough and sites in southeast Queensland also will be examined [15]. There is little experience inapplication of this technique so it is likely that the development costs will be substantial and the riskin building the first plants will be high.


ACKNOWLEDGEMENTThe author wishes to acknowledge the assistance of Professor Badie I. Morsi, Department of ChemicalEngineering, 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 EnergyTechnology 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 TechnologyLaboratory, 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 ServiceCenter Boiler No. 2, Rapid City, South Dakota, Argonne National Laboratory Report ANL/CNSV-61, 1987.

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Published: 18 December 2012c� 2012 Monne, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

The Lacq industrial CCS referenceproject (France)Jacques Monne*

Lacq Pilot, Total E&P, France*Email: [email protected] SUMMARY

Total is committed to reducing the impact of its activities on the environment, especially itsgreenhouse gas emissions. The group’s priorities are to improve the energy efficiency of its industrialfacilities, 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 investe60 million in the Lacq basin for experimenting in a complete industrial chain from CO2 capture totransportation 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 onshoredepleted gas reservoir (unprecedented in Europe) located 5 km south of Pau and its suburbs (around140,000 inhabitants) and by operating a whole industrial chain (extraction, treatment, combustion ofnatural gas, high-pressure steam production, CO2 capture, transport and injection) fully integrated inthe 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 thegeological 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. Thispermitting process has included two months of official public hearing. In parallel to this officialprocess, Total decided to be proactive in the stakeholder involvement. Public information meetingswere held since the start of the project in early 2007 and a public consultation and dialog phase hasbeen organized. That led to the creation of a permanent local information and surveillancecommission (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 scientificcollaboration 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 amore concentrated CO2 stream in the flue gas, easier to be captured. The 30 MWth oxy-boiler candeliver up to 40 t/h of steam to the high pressure steam network of the Lacq sour gas production andtreatment 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 inthe 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 inair mode, switching from air to oxy mode and load variations up to full capacity have beenCite this article as: Monne J. The Lacq industrial CCS reference project (France), SustainableTechnologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:14http://dx.doi.org/10.5339/stsp.2012.ccs.14

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

Industrial scale:30MWth oxycombustionIntegrated within existing facilities

Figure 1. Overview of Lacq project.

demonstrated to be robust, in line with the predicted behavior. The flue gas treatment, which mainlyconsists 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 dryers’ role consists of drasticallylowering the CO2 rich stream dew point to protect the carbon steel transportation pipeline againstcorrosion. The unique equipment in the whole CCS pilot plant, which has proven to be morechallenging to operate, is the Lacq CO2 rich stream compressor. The suction chamber of the 3rd stagecylinder was rapidly and severely attacked by acid corrosion. On the other hand, the carbon steeltransportation pipeline, and one stage reciprocating compressor, located in Rousse, which is builtwith the same materials, does not suffer corrosion as they are located downstream of the molecularsieve 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 monitoringaspects: a part of this program has been imposed by the French administration an additional part hasbeen defined for R&D purposes.

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Published: 19 December 2012c� 2012 Noble & Gin, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Ionic liquids as novel materials forenergy efficient CO2 separationsRichard D. Noble*, Douglas L. Gin

University of Colorado, Boulder,CO 80309, USA*Email: [email protected]

ABSTRACTLarge improvements in separations technology will require novel materials with enhanced propertiesand performance. The fundamental interlinks for success in merging synthesis and processincorporation are the structure, relevant physical/chemical properties, and performance of newmaterials. Specific materials with these interlinks are room-temperature ionic liquids (RTILs) and theirpolymers and composites. As a chemical platform, RTILs have an enormous range of structuralvariation that can provide the ability to ‘‘tune’’ their properties and morphology for a givenapplication. Introduction of chemical specificity into the structure of RTIL-based materials is anadditional key component. Membrane separation is the focus as a process for implementation. Therehave 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 commercialmaterials currently available.

Cite this article as: Noble RD & Gin DL. Ionic liquids as novel materials for energy efficient CO2separations, Sustainable Technologies, Systems and Policies 2012 Carbon Capture and StorageWorkshop:15 http://dx.doi.org/10.5339/stsp.2012.ccs.15

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

FUNDAMENTAL SCIENTIFIC APPROACHSeparations are accomplished either by mass separating agents (MSAs) or by energy separatingagents (ESAs). Separations employing ESAs consume significant amounts of primary energy. It isestimated that separations processes account for more than 5% of the primary energy consumptionin the United States. The fundamental approach we are undertaking is a major shift from the use ofenergy intensive separations (e.g., heat for distillation, amine scrubbers) to the tailored design ofmaterials 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 variousseparation processes. Likewise, the materials performance criteria will be determined by the processin which an MSA will be employed. A fundamental understanding of how materials properties in anMSA affects its performance can then provide interaction and feedback to indicate what materialproperties are necessary for various process configurations. If we know the structure/propertyrelationships for a particular type of MSA material, then we can design new structures andcompositions that have the desired separation properties and performance; this is the fundamentalconnection.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 operatingcosts. Selectivity corresponds to the separation efficiency. For CO2 capture, this is important for thesubsequent 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 intargeted applications to be made. The focus is on ‘‘tunable’’ materials, i.e., room-temperature ionicliquids (RTILs)) and polymers and composites based RTILs.

GAME-CHANGING WITH RESPECT TO CURRENT TECHNOLOGYCapturing CO2 from mixed-gas feed streams is a first and critical step in carbon sequestration. Theeffectiveness and efficiency of current technologies for separating CO2 is limited. Amine absorption isthe 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 requireapproximately 22–30% of the produced plant power [1–3]. This parasitic load corresponds to aCO2 capture cost of $40–100/ton of CO2 and an increase in the cost of electricity (COE) of50–90% [1–3]. These values are well above the 2020 DOE NETL Sequestration Programpost-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 theproduced plant power. A 500 MW power plant will cost ⇠$1 billion. Using the same permeancevalue, 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 permeancecharacteristics, ⇠100 GPU (1 GPU = 10�6 cm3 cm�2s�1cmHg�1). The membrane area requiredfor a given application usually scales linearly with the permeance for a given gas flux through themembrane. A ten-fold increase in permeance equates to a ten-fold decrease in membrane arearequired to achieve the same productivity. Reduced membrane area requirements also translate intosmaller membrane footprint requirements and correspondingly better system economics.Membrane permeability, typically defined in barrer (1 barrer = 10�10cm3(STP) cm/(cm2s cmHg)),

is a material property measure that is a function of both the diffusive and solubility-driven transportof a gas through that material. Permeance, i.e., the pressure-normalized flux thru a membrane, is insimple terms, the transport of a gas through that material taking the thickness of the membrane intoaccount. For example, a 0.1-µm thick membrane with a permeability of 1000 barrer would have apermeance of 10,000 GPU. Thus, a combination of a thin film selective layer and very highpermeability membrane materials is necessary to achieve 10,000 GPU permeance and


0

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ture

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Membrane CO2/N2 selectivity

90% CO2 capturePressure ratio = 5.5

4,000 gpu

2,000 gpu

CO2 permeance

1,000 gpu

Base casemembrane

Figure 1. Effect ofmembraneCO2 permeance andCO2/N2 selectivity on the cost of capturing 90%of theCO2 fromflue gas at a fixed pressure ratio of 5.5 [7].

correspondingly, unprecedented potential for achieving carbon capture costs of $10/ton CO2 (seeFig. 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 permeanceof ⇠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 powerplants [5]. Merkel et al. have shown that the optimal membrane selectivity for separation of CO2 fromflue gas is in the range of 20 to 40 and that increasing membrane permeance is the critical factor inreducing capture costs [6]. They show that for a given process scheme, a system comprised of amembrane with a selectivity in the aforementioned range and CO2 permeance of 1000 GPU results ina cost per ton of CO2 captured of ⇠$32 (Fig. 1). A 4-fold increase in CO2 permeance to 4000 GPUdecreases this cost by nearly 50% to ⇠$16. In their analysis, Merkel et al. [7] assumed a membraneskid cost of $50/m2 (including membrane modules, housings, frame, valves and piping) and includethe 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 proposedeffort, would result in a cost per ton of CO2 captured of less than $10. This is a significant reductioncompared to both the benchmark amine technology and the current membranes under developmentfor this application. As a basis of comparison, commercially available polymer membranes for thisapplication 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 valuescan be extrapolated to 10,000 GPU. Figure 2 illustrates that achievement of this permenace wouldresult 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 aneat 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/orthe cation [8]. In addition, RTILs have a unique combination of physiochemical properties, such asnegligible vapor pressure, high thermal stability, low flammability, high ionic conductivity, andintrinsic solubility for certain gases, all of which make them unusual in terms of organic liquids andsolvents [8]. Because of this combination of properties, RTILs have attracted a great deal of interestas new liquid materials for a number of important chemical and engineering applications.


00 2000 4000 6000 8000 10000 12000

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ease

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OE,

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Cost of Capture - Merkel et. al.Cost of Capture - ExtrapolatedIncrease in COE - Estimated

Figure 2. Estimated COE increase based on increases inmembrane permeance to 10,000 GPU. Solid line is powerlaw fit to the calculated cost of capture taken fromMerkel et al. [7]. The dotted line represents extrapolated costof capture.

The most common classes of RTILs contain imidazolium, ammonium, phosphonium, andpyridinium cations [8]. Imidazolium-based RTILs (Fig. 3) are the most ubiquitous because they are themost modular in terms of chemical synthesis. Using imidazole as a starting material, two differentgroups can be attached to the imidazole ring via nucleophilic substitution reactions using the tworing 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 incorporateadditional properties or to introduce other functional groups. This broad synthetic versatility allowsthe physical and chemical properties of imidazolium-based RTILs to be readily tuned via inclusion ofspecific functional groups on the cation unit, or by the judicious choice of the anion. In addition, solidand semi-solid materials based on RTILs can also be prepared by polymerizing reactive RTILs intoionic polymers (i.e., poly(RTIL)s) [9–11], gelling RTILs with small molecule gelator additives to formsoft solids [12], or combining different poly(RTIL) (solid) and RTIL (liquid) components to form softcomposites [13]. These materials retain many of the desired properties of the parent RTILs, and areimportant for materials or device applications requiring more mechanical robustness.

N N N N N N N N RRRR'-X

H1) NaH2) R-X R' R'

XX

M

M

Y

sY

ImidazoliumRTIL

(Anion Exchange)Imidazole

Figure 3. Transformation of imidazole to a functionalized RTIL.

The design and synthesis of several new types of imidazolium-based RTILs, poly(RTIL)s, andRTIL-based composite materials from our research groups for use in the area of targetedCO2 separations from N2 incorporates a fundamental materials advance. It is extremely desirable tohave new membrane and sorbent materials that provide better selective transport or capture.Materials based on imidazolium-based RTILs represent a promising new separations platform forachieving these goals because of their unique properties and their chemical and morphologicalmodularity.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. Indense solid membranes (e.g., polymers), gas separation is typically afforded by differences in thethermodynamic solubility (S) of each gas in the polymer and/or differences in diffusivity (D) of eachgas through the membrane material [14]. In this solution–diffusion (S–D) mechanism, thepermeability (P = S · D) is the pressure gradient-normalized flux of each gas through the membranematerial, and gauges how easily each gas moves through a dense material to separate it from other


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 theother, and/or a much higher D value for one gas over the other. This gives a large permselectivityfactor [ 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 thepermeability increases, the diffusion difference decreases, which reduces selectivity. Even though it ispossible to design membrane materials with good solubility selectivity for certain gases, it is alsoimportant to have high overall diffusivity through them or the productivity (i.e., through-put) of theentire process will be too low to be useful [14]. A fundamental difference with the use of RTILs asmembrane materials is that they separate based on solubility selectivity. Thus, a compositeconsisting of an RTIL incorporated into an RTIL polymer will increase the permeability due to the liquidwithin the polymer but the selectivity remains relatively constant since the chemical structure of bothcomponents can be the same.

NEW FUNCTIONALIZED RTILS FOR CO2 SEPARATIONSPrevious research has demonstrated the viability of simple, alkylimidazolium-based RTILs asCO2-selective solvents for light gas separations (e.g., CO2/N2, CO2/CH4, and CO2/H2) [15]. Since thisinitial work, there has been a considerable interest in functionalizing these ‘‘tailorable’’ RTIL solventsto improve CO2 solubility and/or solubility selectivity. The effect of polar and fluorinated substituentsin place of simple alkyl units on the imidazolium ring was investigated by our research group with thisgoal in mind [16–19], and results indicate that alkylnitrile-, oligo(ethylene glycol)-, andfluoroalkyl-substituted imidazolium RTILs exhibit significantly better CO2 solubility selectivity thananalogous alkyl-functionalized imidazolium RTILs [16–19]. The structures of some of thesefunctionalized and non-functionalized RTILs synthesized by our groups are shown in Fig. 4.

N N N NN

N N N Nn

NTf2 NTf2 NTf2 NTf2

n = 1, 3, 5 m = 1, 3, 5 p = 1, 2, 3 q = 1, 3

mO

p qCF2

CF3

Figure 4. Representative functionalized and non-functionalized RTILs.

POLY(RTIL)S AND COMPOSITE MEMBRANES FOR CO2 SEPARATIONSPoly(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)sare 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 astraightforward method to produce ‘‘solid’’ RTIL membranes. Various novel poly(RTIL) monomershave been designed and synthesized based on promising (i.e., CO2-selective), non-polymerizableRTIL analogues. For example, oligo(ethylene glycol)- and nitrile-functionalized poly(RTIL)s were foundto have enhanced CO2 permeability selectivity compared to analogous alkyl-functionalized

N

N NN

N N

N N

N

NTf2

NTf2NTf2

NTf2n

m

p

q

O

p = 1, 2, 3

q = 1, 3

n = 1, 3, 5

m = 1, 3, 5

CF2CF3

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


poly(RTIL)s [20]. These poly(RTIL)s present all of their CO2-selective functional groups as pendantside 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 beensynthesized is shown in Fig. 6. Unlike the previous poly(RTIL)s discussed, all of the CO2-selectivefunctionality 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-polymerizablepoly(RTIL)s. In many cases, the side-chain poly(RTIL) or main-chain poly(imidazolium) membranesperformed comparably or better than the liquid-state, functionalized RTIL analogues in terms ofCO2 selectivity performance. However, these dense, solid-state polymer films have inherently lowerCO2 diffusivity and cannot attain the large CO2 fluxes obtainable with Supported Ionic LiquidMembranes (SILMs), where the active membrane material is a liquid.

N N

NTf2

n

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

n

n

N

N

N

N

NTf2

NTf2

NTf2

NTf2

O

N

N

N

N

Poly(RTIL): 80 mole % RTIL: 20 mole %

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 consistentlyexhibited 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 inFig. 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

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(a) (b)

Figure8.ComparativeCO2 separationperformanceof several poly(RTIL)s, poly(RTIL)-RTIL composites, andSILMsrepresented 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].


films, and no evidence of the RTIL ‘‘bursting’’ from of the membrane under applied gas pressure hasbeen observed, which is a significant limitation with SILMs. The most important consequence ofblending a free liquid RTIL into an solid poly(RTIL) matrix is that there is little, if no, sacrifice inCO2 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, supportedmembranes. 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 analogousliquid-based membrane and deviates further from the parent solid poly(RTIL). Figure 8 shows thecomparative CO2 separation performance of several poly(RTIL)s, poly(RTIL)-RTIL composites, andSILMs as summarized in ‘‘Robeson Plots’’.

REFERENCES[1] Figueroa J.D. Advances in CO2 capture technology - the US Departments of Energy’s carbon sequestration

program. Int. J. Greenhouse Gas Control. 2008;2:9.[2] Rochelle G.T. Cost and performance baseline for fossil energy plants. Science. 2009;325:1652.[3] Shelly S. Capturing CO2: Membrane systems move forward. Chem. Eng. Prog. 2009;105:42–47.[4] NETL, Existing plants—Emissions and capture program goals, 2009, US Department of Energy.[5] Favre E.J. Carbon dioxide recovery from post-combustion processes: Can gas permeation membranes compete

with absorption?. J. Membr. Sci. 2007;294:50.[6] Merkel T.C., Lin H., Wei X. and Baker R. Power plant post-combustion carbon dioxide capture: An opportunity for

membranes. J. Membr. Sci.. (in press, Corrected Proof)[7] Merkel T., Lin H., Wei X., He J., Firat B., Amo K., Daniels R. and Baker R. In: NETL Review Meeting 2009.[8] Welton T. Room-temperature ionic liquids. Solvents for synthesis and catalysis. Chem. Rev. 1999;99:2071.[9] Ohno H. Molten salt type polymer electrolytes. Electrochim. Acta. 2001;46:1407.

[10] Ding S., Tang H., Radosz M. and Shen Y. Atom transfer radical polymerization of ionic liquid2-(1-butylimidazolium-3-yl)ethyl methacrylate tetrafluoroborate. J. Polym. Sci. A: Polym. Chem. 2004;42:5794.

[11] Washiro S., Yoshizawa M., Nakajima H. and Ohno H. Highly ion conductive flexible films composed of networkpolymers based on polymerizable ionic liquids. Polymer. 2004;45:1577.

[12] Ikeda A., Sonoda K., Ayabe M., Tamaru S., Nakashima T., Kimizuka N. and Shinkai S. Gelation of ionic liquids with alow molecular-weight gelator showing Tgel above 100 �C. Chem. Lett. 2001;30:1154.

[13] Bara J.E., Hatakeyama E.S., Gin D.L. and Noble R.D. Improving CO2 permeability in polymerized room-temperatureionic liquid gas separation membranes through the formation of a solid composite with a room-temperature ionicliquid. Polym. Adv. Technol. 2008;19:1415.

[14] Wijmans J.G. and Baker R.W. The solution-diffusion model: A review. J. Membr. Sci. 1995;107:[15] Camper D., Bara J., Koval C. and Noble R. Bulk-fluid solubility and membrane feasibility of Rmim-based

room-temperature ionic liquids. Ind. Eng. Chem. Res. 2006;45:6279.[16] Bara J.E., Gabriel C.J., Lessmann S., Carlisle T.K., Finotello A., Gin D.L. and Noble R.D. Enhanced CO2 separation

selectivity in oligo(ethylene glycol) functionalized room-temperature ionic liquids. Ind. Eng. Chem. Res.2007;46:5380.

[17] Carlisle T.K., Bara J.E., Gabriel C.J., Noble R.D. and Gin D.L. Interpretation of CO2 solubility and selectivity innitrile-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 influoroalkyl-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 ionicliquids. 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 selectivityin polymerized room-temperature ionic liquid gas separation membranes through incorporation of polarsubstituents. 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 forCO2 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: platformtechnologies 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 membranewith 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 liquidmembranes 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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Published: 19 December 2012c� 2012 Sculley, Li, Park, Lu, Zhou,licensee Bloomsbury QatarFoundation Journals. This is anopen access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Review article

Metal-organic frameworks andporous polymer networks for carboncaptureJulian Patrick Sculley*, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe Zhou

Chemistry Department, Texas A&MUniversity, College Station, TX, USA*Email: [email protected]

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

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

Cite this article as: Sculley JP, Li JR, Park J, Lu W, Zhou HCJ. Metal-organic frameworks and porouspolymer networks for carbon capture, Sustainable Technologies, Systems and Policies2012 Carbon Capture and Storage Workshop:16 http://dx.doi.org/10.5339/stsp.2012.ccs.16

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

INTRODUCTIONCarbon capture and sequestration (CCS) is a topic that has received a considerable amount ofattention in the last few years because of the importance of reducing anthropogenic carbon dioxideemissions [1–3]. The scientific investigation of porous solid materials has traditionally involved abroad spectrum ranging from chemists to materials scientists to engineers in large part due to theindustrial importance of these materials for separations [4]. Over the last three decades there hasbeen resurgence in the chemical arena with the development of metal-organic frameworks (MOF) asadvanced porous materials [4–6]. These materials self-assemble from inorganic metal ions orclusters and organic bridging ligands. Due to the modular construction using molecular buildingblocks, it is possible to design a MOF to have precise structural characteristics and physicalproperties. Through the power of organic synthesis it is also possible to add functional groups to theorganic 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 powerdemands 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 toregenerate them, the water solutions must be heated up, which can account for about 30 percent of apower plant’s energy output [8,9]. In order to reduce the energy penalty that coal or natural gas firedpower plants incur during the process of scrubbing CO2 from flue gas, new methods and materialsmust be investigated. Some of the major technical challenges are that flue gas is usually plagued withcontaminants (SOx, NOx, and fine particulates), it is hot (typically 40–60�C) and only containsapproximately 14–16% CO2 (translates to a partial pressure in the gas stream of about0.15 bar) [10]. Physisorptive materials such as MOFs work in regions of much lower sorptionenthalpies than chemical absorption and can therefore be used to mitigate energy costs becauseregenerations are energetically favorable. Another aspect of MEA scrubbing is the highly corrosiveproperty of aqueous amine solutions. To deal with this problem specially designed tanks are neededand the solutions must be handled cautiously [10].

METAL-ORGANIC FRAMEWORKSMOP constructionAs the building units of MOFs, the design and construction of the metal-organic polyhedra (MOPs) isa prerequisite. A great example of the modularity in design is shown in Fig. 1. By choosing a simplesecondary building unit such as the dicopper paddlewheel (in the center of the figure), and mixing itin solution with a variety of linkers, numerous MOPs can be synthesized [11]. Each MOP has differentphysical properties that are related to the bridging linker. Structure property relationships can beestablished between the functional group and a desired physical property, such as high CO2 uptakeat low pressure, which can be used to increase selectivity of CO2 over N2 or CH4 (natural gaspurification). The metal cluster can also be replaced with other metals such as molybdenum togenerate isostructural MOPs with different physical properties [12]. These polyhedra can be bridgedinto three dimensional structures, using ditopic moieties such as 4,4’-bipyridine, [13] or by designingligands which will form polyhedral pores that are covalently linked such as the PCN-6x seriesdeveloped by us [14,15].

Polyhedra-based frameworksA hierarchical approach can be used to connect these polyhedra into 3D networks, by carefullydesigning linkers with topologies that will generate polyhedra-based networks (Fig. 2). All of thePCN-6x series MOFs have the same topology with identical cuboctahedral cages, but increasinglylarger mesocavities by increasing the ligand length. This leads to increasing BET surface areas of3350, 4000 and 5109 m2/g for PCN-61, �66, and �68 respectively. An important trend that isobserved for this series is the proportional increase in CO2 uptake capacities at 35 bar, from 23.5 to26.3 to 30.4 mmol/g. In terms of volumetric uptake this translates to a storage capacity that isbetween 7.3 and 8.2 times the amount of CO2 stores in an empty container. Similar trends areobserved for other gases stored at high pressure for energy applications, primarily H2 and CH4 [15].


DEF DEF

MeOH/DMA

MeOH/DMA

DMA

MeOH

MeOH/DMA

MeOH/DEFMeOH/DEF

MeOH/DEF

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

(a)

(c)

(b)

(d)

PCN-61 PCN-66 PCN-68

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

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


Gate

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pristineright after the first UV5 hrs after the first UVafter the first heating

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231 K195 K143 K

77 K 87 K113 K

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

POROUS POLYMER NETWORKSThe 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 lowcost, ease of processing, and high thermal and chemical stability. Initial publications showed thatthese covalently bonded materials were indeed very stable and had similar surface areas and porevolumes (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 aremarkable pore volume of 3.04 cm3/g. This tremendous porosity is directly related to the amount ofgas stored at high pressures (50 bar) of H2 (140 mg/g), CH4 (360 mg/g) and CO2 (2121 mg/g). Toincrease low pressure CO2 adsorption however, we introduced polar functional groups (SO3H andSO3Li) as can be seen in Fig. 4. By raising CO2 specific interactions in these materials, it is possible totune gas-framework interactions thereby creating highly selective materials. As an example, PPN-6was synthesized by an optimized Yamamoto homo-coupling reaction [19] usingtetrakis(4-bromophenyl)methane and has a BET surface area of 4023 m2/g. The first attempt atfunctionalizing a PPN for this targeted application was by stirring it in chlorosulfonic acid (followed bylithium hydroxide), as shown in Fig. 4. Both modified PPNs have exceptionally high CO2 uptakecapacities at pressures relevant to flue gas separations. Using the approximate partial pressures ofCO2 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-SO3Li has a selectivity that compares favorably to NaX zeolite at about 150. The higherCO2 adsorption capacity and lower N2 capacity of PPN-6-SO3H lead to a record high IAST selectivityof 414. Additionally, these materials are thermally stable to above 400�C, can be stirred in boilingwater as well as strong acids and bases without losing any of their adsorptive properties. This

Br

Br

Br

Br

CNi(COD)2 PPN-6

CISO3H RO3S

LiOHPPN-6-xSO3H (R = H)

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


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

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

REFERENCES[1] Pradier J.P.C.-M. ed., Carbon Dioxide Chemistry: Environmental Issues. The Royal Society of Chemistry. 1994.[2] Wang Q., Luo J., Zhong Z. and Borgna A. Energy & Environmental Science. 2011;4:42–55.[3] Chu S. Science. 2009;325:1599.[4] Li J.R., Sculley J. and Zhou H.C. Chem. Rev. 2012;112:869–932.[5] D’Alessandro D.M., Smit B. and Long J.R. Angewandte Chemie International Edition. 2010;49:6058–6082.[6] 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.[7] Zhao D., Timmons D.J., Yuan D. and Zhou H.-C. Accounts Chem. Res. 2010;44:123–133.[8] Rochelle G.T. Science. 2009;325:1652–1654.[9] Ciferno J.P., Fout T.E., Jones A.P. and Murphy J.T. Chem. Eng. Progress. 2009;105:33–41.

[10] Ciferno J.P., Marano J.J. and Munson R.K. Chem. Eng. Progress. 2011;107:34–44.[11] Li J.R. and Zhou H.C. Nature Chem. 2010;2:893–898.[12] 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.[13] Li J.R., Timmons D.J. and Zhou H.C. J. Am. Chem. Soc. 2009;131:6368–6369.[14] Zhao D., Yuan D., Sun D. and Zhou H.-C. J. Am. Chem. Soc. 2009;131:9186–9188.[15] Yuan D., Zhao D., Sun D. and Zhou H.-C. Angewandte Chemie International Edition. 2010;49:5357–5361.[16] Ma S.Q., Sun D.F., Yuan D.Q., Wang X.S. and Zhou H.C. J. Am. Chem. Soc. 2009;131:6445–6451.[17] Park J., Yuan D., Pham K.T., Li J.-R., Yakovenko A. and Zhou H.-C. J. Am. Chem. Soc. 2011;134:99–102.[18] 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.[19] Yuan D., Lu W., Zhao D. and Zhou H.-C. Adv. Mater. 2011;23:3723–3725.[20] Lu W., Yuan D., Sculley J., Zhao D., Krishna R. and Zhou H.C. J. Am. Chem. Soc. 2011;133:18126–18129.

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Published: 18 December 2012c� 2012 Fennell, Florin, Napp,Hills, licensee Bloomsbury QatarFoundation Journals. This is anopen access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Review article

CCS from industrial sourcesPaul S. Fennell1,*, Nick Florin1, Tamaryn Napp2, Thomas Hills1,2

1Department of Chemical Engineering,Imperial College, London, SW7 2AZ2Grantham Institute for Climate Change,Imperial College London, SW7 2AZ*Email: [email protected]

ABSTRACTThe literature concerning the application of CCS to industry is reviewed. Costs are presented fordifferent sectors including ‘‘high purity’’ (processes which inherently produce a high concentration ofCO2), cement, iron and steel, refinery and biomass. The application of CCS to industry is a field whichhas had much less attention than its application to the electricity production sector. Costs range fromless than $2011 10/tCO2 up to above $2011 100/tCO2. In the words of a synthesis report from theUnited Nations Industrial Development Organisation (UNIDO) ‘‘This area has so far not been the focusof discussions and therefore much attention needs to be paid to the application of CCS to industrialsources if the full potential of CCS is to be unlocked’’.

Keywords: CCS, industry, cement, iron, steel

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

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

INTRODUCTIONCarbon capture and storage (CCS) is frequently associated with coal-fired electricity generation, andto an increasing extent with gas-fired generation. However, there are many other sources ofCO2 which can also benefit from the technology and many of these are substantially easier to retrofitwith CCS than are power stations. Due to rising energy costs, many energy intensive industrialprocesses have made significant advancements in energy efficiency over the past 40 years and arenow operating close to their thermodynamic limits. The options for further reduction are highlylimited. Furthermore, for process-related emissions (those inherent to the process itself, such as theemission of CO2 during the calcination of limestone for lime or cement manufacture) there is littlechoice other than to apply CCS if the industry is to be substantially decarbonized. In light of this, it issurprising that the power industry, where technologies such as wind, tidal and hydropower offerserious alternatives to the application of CCS (through clearly there are issues with intermittentgeneration) 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 bepaid to the application of CCS to industrial sources if the full potential of CCS is to be unlocked’’. Inthis paper, the major classes of industrial CO2-emitting processes are discussed, the most suitabletypes of carbon capture equipment for each of them, and the likely costs of implementing thetechnology. One thing which is immediately apparent is that there is a very much reduced set ofliterature pertaining to industrial emissions when compared with the large and growing literature onthe application of CCS to power stations. Much of the literature refers back to a small number of IEAstudies [2,3], there is much less independent validation of costs by different researchers. This is mostlikely owing to the breadth of different processes in the industrial CCS arena, and the proprietarynature 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 vsthe ‘‘business as usual’’ scenario to CCS, and this is roughly split 55:45 between power generationand industrial emissions applications. The share of total direct (i.e. excluding process emissions andindirect emissions from electricity production) industrial emissions of CO2 from the majorCO2-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 thepartial pressures of CO2 in the exhausts of different industrial processes vary greatly (see Fig. 2), with

Total direct CO2emissions fromindustry in 2007was 7.6 Gt, globally

Iron and steel 30%

Cement 26%

other 23%

Chemicals andpetrochemicals 17%

Pulp and paper 2%

Aluminium 2%

Figure 1. Share of direct industrial CO2 emissions attributable to the major industrial sectors [5]. Adaptedfrom [6].


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 apressure 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, forreference, the estimated costs of CCS range between around $29–$107 for CO2 capture from coal ornatural gas-fired power stations [4,8–10]. Some care is necessary though, given the recent significantincreases in capital cost indices. The costs of separation currently outweigh the costs of transport andstorage, with transport costs estimated at 0–$16/t, depending upon the distance transported, withstorage costs at $2–3/tCO2 [11]. All costs in this paper are expressed in 2011 USD and escalatedusing the Power Capital Costs Index (PCCI) where appropriate [12]. A word of caution is necessary atthis stage—academic estimates of costs are generally a little lower than industrial estimates, so careis 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 oftenconsist of up to five large blast furnaces on one site, emitting a total of 17.5 Mt CO2 per year andmaking it one of the largest stationary sources of CO2 emissions in the world. Table 1 compares thesize 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 (Adaptedfrom [8]).

Source Average emissions/source No. of sources in 2005

Power station flue and fuel gas- Natural gas fired boilers 1.01 743- Gas turbines 0.77 985- Coal fired boilers 3.94 2025

Chemical and petrochemical- Refineries 1.25 638- Ammonia 0.58 194- Ethylene oxide 0.15 17

Iron and steel 3.5 180Cement 0.79 1175

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


SECTORAL ASSESSMENTSHigh purityThis is a classification based on the output concentration of CO2 from the process (30–100%), ratherthan a particular industrial sector. There are a number of processes which currently separateCO2 from process streams for the purposes of product quality or because a required reactionproduces CO2 as an outlet gas. This sector includes natural gas processing. Clearly, the opportunitiesfor CCS are significant in this sector, because the most difficult job of separating the CO2 from theremaining streams has already been accomplished. Unfortunately, the emissions of high purityCO2 are relatively small, at [1] only 426 Mt/yr, only 6% of the total industrial emissions. However, theopportunities for demonstration of the technology are large, with a number of significant projectsalready up and running, as discussed below. The industry is well developed, with solvent-basedCO2 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 $9for retrofit to an existing LNG plant, $15–8 for an onshore natural gas plant, $17–20 for an offshorenatural gas plant in shallow waters and rising to $29 for a deep water installation [1]. Early work inthis area [14] suggested a mitigation cost of $30/tCO2 for fertilizer production and $34/tCO2 forethylene oxide production (note that these costs were estimated in 1990, so that the capital costescalation factor and hence the potential error caused is large).

CementCement manufacture contributes over 5% of global CO2 emissions [15], and with the total demandfor cement expected to double by 2050 [16] it will continue to be a large source of CO2 for manyyears. There are two major sources of CO2 in the cement production process—from the calcination oflimestone (CaCO3) to form CaO (around 60% of the total emissions, excluding the fuel used to effectthe calcination [17]), the major constituent of ordinary Portland cement, and from the fuel used toraise the temperature in the cement kiln and to effect the calcination (approximately 40% of the totalemissions) to effect the chemical reactions necessary to produce cement [18]. These figures agreewith 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 calcinationincluding 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 (atleast 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 researchon 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 studycurrently in the pipeline is based at a NORCEM cement plant in Brevik, Norway. A post-combustioncapture 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 asretrofit to existing plants at low technical risk [23]. However, unlike power plants, cement plants havelimited low-grade waste heat available for solvent regeneration (typically only up to 30% of the totalheat required for regeneration can be supplied by waste heat [24]. Thus, additional steam has to begenerated 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]. Oxygenenrichment, where the kiln air is supplemented by short bursts of pure oxygen, has already beenapplied in the cement industry. Oxygen enrichment has the advantage of creating high value energythrough increased kiln temperatures, which increases the kiln capacity. With each percentage pointincrease 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 newbuilds since most of the core units have to be rebuilt. Current research is focused on overcoming three


major challenges: 1) the effect of a high CO2 concentration on the calcination reaction, 2) limitingdamage 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 theCO2 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 hightemperature to form CaCO3, which is then regenerated at ⇠950�C (in a ‘‘calciner’’), with the cyclethen 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 exothermicCO2 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 cementmanufacture because of the integration of the waste products from the cycle with the raw materialsfor cement manufacture.

CaO purge+ freshlimestone

coal, air

Cementplant

flue

carbonator calciner

flue without CO2

CaCO3

CO2

N2

O2

CaO

CaO purgelimestone

coal air

ASU

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, inthat 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 verysubstantial fraction of the hard to eliminate process-related emissions and eliminates therequirement for a precalciner for the cement works. Of course, it is also possible to remove theemissions via a standard post-combustion scrubbing route, such as MEA scrubbing. However, theestimated 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 tothe 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 cementproduction] are the incorporation of trace elements into clinker and their effects on the performanceof cement.’’ The cement industry is by nature cautious, which is understandable given theconsequences if the cement does not perform to the required standard. Current research at ImperialCollege [29] is investigating the likely build-up of trace elements during repeated cycles of calcinationand carbonation for CO2 capture from cement Fig. 4 demonstrates the steps undertaken during thetesting 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 measureof the cement quality) formed improved with increasing cycles of calcination and carbonation: seeFig. 5, which compares the alite/belite ratio for cases with and without the addition of coal to effectthe 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


PRODUCTION OFCYCLED SORBENT

PRODUCTION OFCLINKER

XRD ANALYSIS OFCLINKER

TRACE ELEMENTANALYSIS OFSORBENT

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

0

10

20

30

40

50

60

70

80

90

100

% A

lite

No Fuel 2g / cycle

1 5 10 15No. Cycles

Figure 5.Wt.% alite determined by XRD using the ‘Relative Intensity Ratio’ (RIR) method (Snyder & Bish, ModernPowder 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 figureis for steam import from a power station, the higher figure for boiler steam import), around $56 foroxyfuel operation and $85–117 for MEA-based scrubbing (again, the lower figure is for powerstation steam and the higher for boiler steam). The IEA GHG programme [33] has assessed the costsof an oxyfired cement kiln in the UK, and estimated a cost of $54 for decarbonisation of the calcineronly, or $29 for an Asian developing country. This was in contrast to their assessment of $138 forpost combustion capture using MEA for the entire plant in the UK, or $93 for a developing country.

Iron and steelThe manufacture of iron and steel is another sector where the use of carbonaceous fuels is currentlyintrinsic to the process, leading to significant difficulties in decarbonisation through routes other thanCCS. The current primary manufacturing route involves the heating of coke, pulverized coal, bulk ironore 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 passdown the furnace and contact countercurrently with hot reducing gases produced by the combustion


of the coke (and potentially a small amount of coal), and (potentially O2-enriched) air. Therequirement for coke (which supports the ore as it passes down the furnace and prevents collapse ofthe bed) is one of the main drawbacks of the blast furnace, since the production of coke is costly inboth environmental and monetary terms, and the substitution of coke with coal is a subject ofsignificant research [34]. Research in the area of CCS from iron and steel production is being carriedout by the Ultra-Low CO2 Steel (ULCOS) programme [35]; a consortium of 48 EU companies andorganisations from 15 EU countries. The programme began in 2004 and has since focused onresearch and small pilot demonstrations of a number of alternative iron and steel productionprocesses, which enable the capture of CO2 and its subsequent storage. Following good progress, theprogram 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 thepower sector, could be used to capture CO2 from the blast furnace exit gas stream, however much ofthe carbon then remains uncaptured in the form of CO. Through reforming and the water–gas shiftreaction, the CO2 concentration can be increased to 60% CO2 [3], making physical solvents such asSelexol, which has been developed for IGCC pre-combustion capture, technically and economicallyfeasible.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) orPressure Swing Adsorption (PSA) together with cryogenics separation to remove final impurities. TheCO2 is transported to underground storage, and the separated CO and H2 are recycled and injected atthe bottom of the blast furnace, where they act as reducing agents. This has the additional benefit ofdecreasing 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 stabilizingproperties of coke and allows coal or gas to be used instead. The COREX process exports a significantvolume 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 attemperatures below the melting point of iron and either gas or coal can be used as the reducingagent 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. Thisreducing gas is then fed to the reactor and reacted with the solid iron ore, producing a mixture of CO,CO2, H2 and H2O. 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 thenbe 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 postcombustion 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 termby converting conventional blast furnaces to top gas recycling. Alternatively, it is possible to addconventional 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 removearound 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 significantpotential synergies with the power generation sector.

Refineries/petrochemicalsRefineries produce CO2 through both process heating and intrinsic chemical transformations (such asregenerating the catalyst used in a fluid catalytic cracker). Refineries are variable in scale andprocesses 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


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 highpurity, and the remaining ⇠50% is comprised of a number of small sources. Initial experiments beingconducted 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 thecosts 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 Capture type Retrofit or new build Cost ofCO2 avoided$/tCO2

Low High

Utilities, combined cycle gas turbine Post-combustion New 39 105Pre-combustion New 38 106

The Heaters and boilers (UK) Post-combustion Retrofit 108Pre-combustion Retrofit 69Oxy-combustion Retrofit 62Post-combustion New 134Oxy-combustion New 70Chemical loopingcombustion

New 46 59

Fluid Catalytic Cracker Post combustion New 119Oxy-combustion Retrofit 77

Hydrogen production SMR Post-combustion New

It is clear from Table 2 that the costs of CO2 capture vary significantly between different parts of therefinery. 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 orretrofit. Costs appear to be a little higher than for power stations, and significantly higher than fordecarbonisation of the cement industry. Similar costs might be expected to those for heaters andboilers for other applications where raising steam is key, such as ‘‘Steam-Assisted Gravity Drainage’’to produce heavy oils.

Biomass processesThis 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 ofCO2 are from breweries/ethanol production plants (which have the advantage of also yieldinghigh-purity CO2 streams), and potentially in the future from either biomass gasifiers/Fischer-Tropschreactors to produce hydrocarbon fuels, or the direct production and upgrading of pyrolytic oils [42].


The potential for this sector should not be underestimated—there are around 3 billion tonnes ofbiomass residues (i.e. from farming, timber production, etc.) produced per year [43]. In the UK, theTESBIC project [44] has assessed the commercial potential of the integration of biomass combustionfor 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 thebiomass 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 areextremely low, being only associated with drying and compressing the CO2 for transport. However, byfar the most interesting finding from their paper is that adding CCS to the bioethanol plant (andcapturing only 13% of the carbon reduces the cost of carbon avoided from $729 to, figures whichprobably say more about the value of first generation biomass fuels for the mitigation of globalwarming 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 andearly opportunities. Dedicated pilot and demonstration projects should be facilitated.’’

CONCLUSIONSThe wide variety of industrial sources of CO2 leads to a large variation in the estimated costs. Theserange from significantly below the cost of application in the electricity production sector, to muchhigher. 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 isproprietary, and secondly the industrial sector as a whole (with the exception of gas processing) hasbeen 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 generationand industry, particularly in the cement and iron and steel sectors. Good economic modelling isimportant. There are also significant experimental research challenges under investigation in the Ironand Steel and Cement manufacturing sectors. Owing to the high temperatures employed in both ofthese sectors, there are unique possibilities for both to be integrated with high temperature loopingcycles, which are being explored in particular in the cement industry.

ACKNOWLEDGEMENTSThe 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 ofthis paper.

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Published: 19 December 2012c� 2012 Ornstein, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Introduction to market challenges indeveloping second generationcarbon capture materialsJason Mathew Ornstein*

co2industries LLC d/b/a framergyTM,Suite 2011-A, Building 1904, 800Raymond Stotzer Parkway, CollegeStation, Texas 77843, USA*Email: [email protected]

ABSTRACTAbsent an economic or social cataclysm, there is no plausible way to meet what will be the world’sunavoidable energy demands without utilizing its vast supply of fossil fuels. One importanttechnology being contemplated to mitigate the negative impact of anthropogenic carbon dioxideloading of the atmosphere is Carbon Capture and Storage (CCS). CCS will play a vital role in least-costefforts 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 overthe current applied solution that is ‘‘a very expensive proposition’’2 for the installed energygeneration base. One 2.0 material, Metal Organic Frameworks (MOFs), is ‘‘capable of increasing(carbon dioxide) selectivity, improving energy efficiency, and reducing the costs of separationprocesses’’3 in CCS. Such materials can address CCS utilization outcomes in addition to lowering thecarbon capture cost. To support further 2.0 carbon capture material development while CCS faceseconomic challenges, framergyTMis leveraging alternative usages for MOFs and other 2.0 materialsdeveloped for carbon capture.

1International Energy Association (accessed 2012) [4].2Herzog (accessed 2012) [5].3Li et al. (2012). Pg. 873 [9].

Cite this article as: Ornstein JM. Introduction to market challenges in developing secondgeneration carbon capture materials, Sustainable Technologies, Systems and Policies2012 Carbon Capture and Storage Workshop:18 http://dx.doi.org/10.5339/stsp.2012.ccs.18

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

INTRODUCTIONWhile anthropogenic carbon dioxide loading of the atmosphere needs to be reduced dramatically tomanage the negative effects of global warming,4 more and more people are demanding the comfortsand goods provided by the same electricity that sends carbon dioxide into the atmosphere.5 Oneimportant technology being contemplated to mitigate these negative trends is Carbon Capture andStorage (CCS), a family of technologies and techniques that enable carbon dioxide to be capturedfrom fuel combustion or industrial processes. While CCS is still an emerging technology, and somesignificant commercial scale up will be required to rationalize costs, ‘‘IEA (International EnergyAssociation) analysis suggests that CCS will play a vital role in worldwide, least-cost efforts to limitglobal warming, contributing around one-fifth of required emissions reductions in 2050’’.6

CARBON CAPTUREPost-combustion carbon capture offers numerous advantages to other clean energy solutionsbecause 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 coalrepresenting the largest share,7 there is a concentrated source of anthropogenic carbon dioxideemissions. Beyond coal, carbon capture technology could be applied to other site-specific locationssuch as natural gas electricity generation, industrial steel and cement plants, and possibly eventransportation.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 engineeringimprovements in effective thermodynamic integration have changed this forecast and a far greaternumber of existing power plants are suitable for CCS post combustion retrofits.8To 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 separatecarbon dioxide form other gases.9 However, this chemical bonding process has some significantdrawbacks.

Today, the only proven CCS capture technology is amine scrubbing. In some waysit works very well — it is highly selective for CO2 and has recovery rates above 90%...Itmakes retro-fitting older, less efficient plants very difficult. For example, an existing plantwith 35% efficiency when retrofitted with CCS will have its efficiency reduced to20–25%. 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 materialsIt is well accepted that the most targetable CCS economic improvement, the cost delta, will likely becarbon capture and not transport or storage.11 2.0 materials for post combustion carbon capturethrough adsorption provides the most sensible solution, as post combustion technology will be thefirst CCS technology deployed. Some companies, like framergyTM, have been formed to leverage thelearning 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 chemicalbonding carbon capture. Programs like ARPA-E’s IMPACCT were aggressive in funding advancedmaterials to absorb carbon dioxide produced by existing coal plants.12 Other programs throughoutthe world are yielding new materials and hope for CCS.

4Mathews et al. (2009) [1].5CESinfo Forum (2011) [2].6International Energy Association (accessed 2012) [4].7CESinfo Forum (2011) [2].8Lucquiand & Gibbins (2009) [3].9International Energy Association (accessed 2012) [4].

10Herzog. (accessed 2012) [5].11McKinsey and Co. (2008) [6].12ARPA-E. (accessed 2012) [7].


35 - 50~30

~1 ~1

CAPTURE TRANSPORT STORAGE 2015 first demoreference case

60 - 90

2020 + early commercial

reference case

Figure 1. The cost delta between demonstration and early commercial reference CCS cases (expressed in e/tonCO2 abated) - Source: McKinsey and Co.

Porous materials, a potential 2.0 material for carbon capture, are applied to many industrialprocesses; but designing these materials with tunable metrics and defined structures can bechallenging.13 Improvements in techniques are allowing porous materials such as zeolites, activatedcarbon and metal organic frameworks (MOFs) to enter gas separations markets, and are beingstudied for CCS. Of these materials, MOFs appear to represent the greatest hope in designing a 2.0material for carbon capture.

By taking advantage of their regularity, rigidity/flexibility, variety, and designability inboth structure and properties, MOFs are being regarded as advanced porous materialscapable of reaching or surpassing a number of current technologies. As compared totraditional inorganic porous solids and activated carbon, the number of possibilities ofcombining inorganic and organic moieties to yield a porous material is staggering andis indeed reflected by the prodigious number of papers on this type of compounds in thelast 20 years.14

COMMERCIALIZATIONBetween 2000 and 2010, at least 33 venture capital investments into CCS technology were madewith a disclosed value over $380 million.15 As it became apparent that there would be no globalprice on carbon in 2011, several high profile CCS projects were scaled back or cancelled, and privatecapital for these technologies dried up.16 The commercialization process for CCS, and in particular 2.0materials 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&MUniversity, is the first incidence of private capital being attracted to the ARPA-E IMPACCT program.17

UTILIZATIONThe economics of storage, sometimes referred to as sequestration, represents a major obstacle to thedevelopment of CCS. Without a better understanding of what would be done with the massive amountof captured carbon dioxide generated through CCS, private capital has shied away from carboncapture improvements. For many years, geological storage was considered a feasible solution,18 butrecent announcements suggest that industry is questioning storage’s forecasted feasibility.19Technical 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 ElectricPower Mountaineer CCS II Project in West Virginia, USA20; but did impact the final decision.21 Withouta storage option, the concept of ‘‘utilization’’ for captured carbon dioxide from CCS has gainedpopularity. Several key organizations have relabeled CCS, adding ‘‘utilization’’ to the end of theacronym, before storage (CCUS) or sometimes even removing the word storage (CCU).

13Barton et al. (2009) [8].14Li et al. (2012). Pg 873 [9].15framergy Company Notes & Bloomberg New Energy Finance (2011) [10].16American Electric Power (2012) [11].17framergy Company Notes [10].18Rubin et al. (2007) [14].19American Electric Power (2012) [11].20Thomson Reuters (accessed 2012) [12].21American Electric Power (2012).


Scientifically, devising a utilization plan for separated carbon dioxide, where the molecule ends upin a new molecule, mimics the development of flue gas sulfur dioxide cleaning which producesindustrial products such as sulfur, sulfuric acid and gypsum.22 The most common utilization forcarbon dioxide captured from pilot CCS projects is enhanced oil recovery or enhanced natural gasrecovery. This usually requires the system to be located near a depleted oil field or natural gasdeposit.23 While this provides a bridging option for the early stages of CCS with favorable locations, itis clear that other utilization schemes will need to be developed to compliment advanced carboncapture 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 isthat, as sorbents, these materials don’t upset current engineering system of the massive installedbase 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 porousmaterials to be capable of increasing selectivity, improving energy efficiency, andreducing the costs of separation processes.24

In addition, 2.0 materials for carbon capture can be designed to improve utilization options as theymay 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 fuelcells.

These properties, together with the extraordinary degree of variability for both theorganic and inorganic components of their structures, make MOFs of interest forpotential applications in clean energy, most significantly as storage media for gasessuch as hydrogen and methane, and as high-capacity adsorbents to meet variousseparation needs.25

Porous material alternative usages are drawing significant industrial attention as scientists movedown the learning curve funded by government’s desire to deploy CCS. Carbon specific usages for 2.0materials can now be explored, such as natural gas upgrading and low density carbon capture, whichmay offer more immediate economic return.

CONCLUSIONIn the 1980’s, many countries struggled with the polluting effects as a result of coal’s emissions ofsulfur dioxide and nitrogen oxides. Through regulation, the United States was able to achieve itstargeted environmental goals of sulfur dioxide and nitrogen oxides reductions at lower than projectedcost.26 Much of this was achieved through technological innovation to post combustion powergeneration, 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 ofindustry to achieve cost-effective carbon capture and put CCS as a solution to global warming at riskof never developing. 2.0 materials for carbon capture, with their design advantages, offer a path tocost-effective carbon capture and improvements to utilization outcomes. Changes in the CCS marketwill encourage 2.0 material developers to seek alternative commercial usages for their intellectualproperty. framergyTM, located in Texas, USA, is leveraging the remarkable attributes of metal organicframeworks and other materials to open new business horizons.

22The World Bank (1998) [13].23Rubin et al. (2007) [14].24Zhou et al. (2012). Pg. 673 [15].25Zhou et al. (2012). Pg. 673 [15].26Schmalensee et al. (1998) [16].


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 ofCoal-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.

http://www.iea.org/ccs/

http://web.mit.edu/mitei/docs/reports/herzog-promising.pdf

http://arpa-e.energy.gov/ProgramsProjects/IMPACCT.aspx

http://www.reuters.com/article/2011/07/14/us-utilities-aep-carbon-idUSTRE76D34C20110714

OPEN ACCESS


Published: 19 December 2012c� 2012 Mac Dowell & Shah,licensee Bloomsbury QatarFoundation Journals. This is anopen access article distributedunder the terms of the CreativeCommons Attribution License CCBY 3.0 which permits unrestricteduse, distribution and reproductionin any medium, provided theoriginal work is properly cited.


Review article

Shipping and CCS: A systemsperspectiveN. Mac Dowell*, N. Shah**

Centre for Process Systems Engineering,Dept. of Chemical Engineering, ImperialCollege London, London, UK*Email: [email protected]**Email: [email protected]

ABSTRACTIn this contribution, we present an overview of the contribution made by the shipping sector to globalCO2 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

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:19http://dx.doi.org/10.5339/stsp.2012.ccs.19

of 11Mac Dowell & Shah, Sustainable Technologies, Systems and Policies 2012.CCS.19

INTRODUCTIONGlobal shipping is a major contributor of CO2 to the atmosphere. In 2007 shipping was responsiblefor approximately 3.3% of total global CO2 emissions. This corresponds to cumulative emissions ofover 1 billion tones [1]. This is illustrated in Fig. 1.

International Aviation 1.9%

Rail 0.5%

Other Transport (Road) 21.3%

Manufacturing Industries and Construction

18.2% Other Energy Industries

4.6%

Other 15.3%

Electricity and Heat Production

35.0%

Domesic Shipping and Fishing

0.6%

International Shipping

2.7%

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 largestemitter of carbon dioxide, only emitting less than China, the United States, Russia, India andJapan [2]. In the absence of emission reduction policies, emission scenarios predict a doubling totripling of 2007 emission levels by 2050 [3]. The significance of this predicted increase becomesmore apparent when one considers that many countries, e.g., the United Kingdom have set ambitioustargets towards appreciably reducing their CO2 emissions by 2050 [4]. Therefore, if unabated, theCO2 emissions associated with the shipping sector will be of even greater significance. Assumingreductions are achieved by other sources as is necessary to limit climate change to two degreesCelsius, unregulated shipping emissions could come to account for 12 to 18 percent of global carbondioxide emissions in 2050 [1].

CHINA

USA

RUSSIA

INDIA

JAPAN

GLOBAL FLEET

GERMANY

CANADA

UNITED KINGDOM

0 1 2 3 4 5 6 7

Emissions (Gigatons CO2)

Figure 2. Global shipping is among the world’s top 10 CO2 emitters [3].


International shipping is a very important model of transportation, which has historically increasedat a rate exceeding that of global GDP growth. This phenomenon is illustrated in Fig. 3.

Mill

ion

tons

Container transport

Year

1200

1000

800

600

400

200

0

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

Figure 3. Increase in containerized transport to the year ending 2006 [5].

It is of interest to compare the impact that shipping has on the climate to that of other transportsectors. It is clear from the data presented in Fig. 4 that international shipping exerts an influencesimilar to that of aviation in all cases, and in all cases but CO2 emission, ship emissions aresignificant compared with emissions from road traffic. This is of added importance when oneconsiders that SOx emissions exert a negative radiative forcing (RF), i.e., a cooling effect, on theclimate. As there are increasing requirements to mitigate the SOx emissions from shipping, this willserve to increase the potential warming effect associated with residual CO2 emissions, if these arenot mitigated in line with the SOx emissions. Further, the emissions of NOx from shipping aresubstantial and possibly represent up to around 20% of global NOx emissions.

Road Traffic Aviation Shipping4110

654 812

27.3

2.3

21.4

4.3

12.0

0.15

2.1 1.7

0.001

1320

207 280

Ann

ual E

mis

sion

s [T

g (C

O2/

NO

2/SO

2)/y

r]

CO2 NO2 SO2 PM10 Fuel Consumption

10000

1000

100

10

1

0.1

0.01

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 thecost-effective mitigation of the CO2 emissions originating from international shipping. There areseveral technology options which are considered to be promising in the near term for thedecarbonisation of large-scale, fixed point sources. These have been discussed at length in aprevious contribution [6], and in the interest of brevity will not be described in detail again here. Oneaspect which the majority of CO2 capture technologies have in common is that they have a very largefootprint. This is obviously of greater concern in the context of shipping than in the case of aland-based power station. Thus there is a clear need to develop means to mitigate the CO2 emissionsfrom shipping which are both cost effective and are appropriate for space-constrained environmentssuch 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 thengo on to consider some new chemical conversion-based methods for capturing CO2 emitted fromshipping. Finally, we conclude with some considerations of how legislating for decarbonisation ofshipping is distinct to that for the decarbonisation of large, fixed point sources.


TECHNOLOGICAL AND OPERATIONAL POTENTIAL FOR THE MITIGATION OF GREENHOUSE GASEMISSIONS FROM SHIPPINGIn 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 differentpower sources, including renewables and using emission reduction technologies, such as chemicalconversion. 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 partdictates 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 projectedextreme growth in emissions. Operational measures should not be the only tool utilized to reduceshipping emissions, but they are the low hanging fruit that can take immediate effect and reduceemission from the current fleet that will continue to be in operation for the coming decades.

Energy efficiencyImproved 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 ofoptions 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 isregularly 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 lowrevolution produce high propulsive efficiency. It is possible to retrofit a vessel with a more efficientpropeller. This could decrease fuel consumption by as much as 15 percent, with a range of 5 to 10percent likely [1]. The loss of propeller energy can also be recovered by measures such as vanes, freerotating vane wheels, pre and post-swirl devices, fins, ducts and high efficiency rudders. Thesemeasures 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 thevessel’s overall dimensions which may affect whether it is able to dock at ports and terminals. Thesebarriers will considerably reduce the potential for reduction of resistance and fuel consumption. Onsingle ships, improvements in power requirements of up to 30% have in fact occasionally beenachieved 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 contractedtrial performance measurements are typically performed in still water conditions. However,optimisation for more complex wave patterns is becoming more common. Ships during their life timewill more frequently operate in the wave field characterized by the short wavelength, �, (small seastates) in comparison to the ship length, L than in the wave field where the ship will experiencesignificant wave-induced motions (e.g. severe storm situation). Therefore, optimisation for wavesgenerally 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, bulkcarriers) in order to reduce the wave added resistance. The ordinary bow waterline curve issignificantly 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 notsatisfactory 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 designhas 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.


Figure 5. Tankmodel of axe-bowand 172,000DWTCapesize bulk carrier KOHYOHSANbuiltwith axe-bow forMitsuiO.S.K. Lines, Ltd in 2001.

Renewable energy sourcesSolar

Current solar-cell technology is sufficient to meet only a fraction of the auxiliary power requirementsof a tanker. Obviously, solar power is by its nature intermittent, thus an appropriate – likely fossilfuel-based – 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; withpresent technology it could be possible to realise only a modest reduction in energy demand, evenwith extensive use of solar power. Therefore, present-day cost levels and efficiency place solar powertowards 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 currentvessels with large reductions in fuel consumption. Wind technology could create fuel savings of about5 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]. Drawbackswith 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 bendingmoments on the hull, which can cause ships to list. Strength issues could result in a need for masts torun down to the keel, and the presence of the mast and rigging could have significant impacts oncargo 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 toassess the practical feasibility of the size and number of sails modelled. Nevertheless, sail assistedpower does seem to be an interesting opportunity for fuel saving in the medium and long termpicture.

Alternative fuelsAlternative fuels are a promising option for lowering the lifecycle greenhouse gas emissionsassociated with international shipping. This option is particularly attractive in that it can be readilyimplemented, 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 allowsfor more effective fuel combustion, resulting in better efficiency and lower levels of emittedparticulate matter. Switching over to MDO can reduce carbon dioxide emissions from vessels by asmuch as 5 percent [3].

Liquefied natural gas

Liquefied natural gas (LNG) is an attractive option for use as an alternative fuel within the shippingindustry. The fuel has a higher hydrogen-to-carbon ratio compared with oil-based fuels, which resultsin lower specific CO2 emissions (kg of CO2/kg of fuel). This is similar to the rationale of land-based


natural gas-fired power stations being inherently cleaner than coal-fired power stations. Further, LNGis a clean fuel, containing no sulphur; thus eliminating the SOx emissions and essentially eliminatingthe emissions of particulate matter. Additionally, the NOx emissions are reduced by up to 90% due toreduced peak temperatures in the combustion process. However, the use of LNG will increase theemissions of methane (CH4), and as CH4is a significantly more potent greenhouse gas than CO2, thisreduces 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 largespace. Thus, the actual volume requirement is in the range of three times that of diesel oil. Inaddition, the ready availability of LNG fuels in bunkering ports is a challenge which needs to besolved 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 seaoperations, since ECA requirements can easily be met by LNG-propelled ships. The price of LNG ispresently significantly lower than that of distillate fuels, making an economic incentive for a move toLNG

Biofuels

First generation biofuels which are derived from sugar, starch, vegetable oil, or animal fats can readilybe used for ship diesels with little or no adaptation of the engine. Depending on source, there arecertain technical issues, such as stability during storage, acidity, lack of water-shedding (potentiallyresulting 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 andadapting the engine. Care must be exercised to avoid contamination with water, since biofuels areparticularly susceptible to biofouling. Blending bio-derived fuel fractions into diesel fuel or heavy fueloil 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 aCO2 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 ofbiofuels can result in a 7% to 10% increase in NOx emissions. We note, however, that the extent ofNOx production is a function of the design and operation of the engine (e.g., fuel injection rate andtiming).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 producedfrom food crops in that they do not compete with food crops. The conversion process that is neededto facilitate production of second-generation biofuel on an industrial scale and economically viable isstill in development [1].

Emission reduction technologiesWhile many of the above described emission reduction techniques may seem piecemeal, they willcontribute to reducing fuel consumption and hence the carbon intensity of shipping. Incrementaldecreases in emissions from individual ships can result in large reductions across the entire fleet. Infact, the 2009 International Maritime Organisation study suggests that the fleet can become 25 to 75percent more efficient than it is currently through both operational and technological measures by2050. This same study finds that operational measures alone can reduce emissions by 10 to 50percent [1]. In this section, we present a chemical conversion option which could account for theremaining 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�1with theexhaust gases from ships typically having the following composition:

• 5 vol% CO2

• 13 vol% O2


• 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 ofCO2, leading to an average of 4,500 tonnes of CO2 emitted per trip [14]. It is immediately obviousthat 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 a30wt% solution of MEA is used. The CO2 is absorbed into the liquid phase via an exothermicreaction, with a 1Habs = 82 kJ/mol. The reaction scheme is illustrated in Fig. 6.

low temp RNHCO2- RNH3+

+RNH2

2RNH3+

carbamate

carbonateCO32-

2RNH2 + CO2

RNH3+bicarbonate

HCO3-

pH

!

!

H2O

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 absorbedCO2 exists as a bicarbonate salt. However, in the case of MEA, the prevalent salt at equilibrium is acarbamate salt, thus limiting the capacity of MEA to absorb CO2 to approximately 0.5 moles ofCO2 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 toapproximately 110 bar in preparation for transport and subsequent storage. It is interesting to notethat this type of technology has historically been deployed on board submarines for the removal ofCO2 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 thesurface, this obviously results in the CO2 entering the atmosphere. However, in the case of surfaceshipping, we are interested in reducing the emission of CO2 to atmosphere, thus simply venting theCO2 is not an appropriate approach. This requires the proposal of some suitable mechanism to storethe captured CO2 on board ship. One could envisage a scenario wherein the captured CO2 iscompressed and stored on-board ship. However this would entail significant extra cost both in termsof energy required to compress the CO2 and space required to store it on board. Further, one shouldconsider 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 ofO2 in ship exhaust gases thus poses an especially interesting challenge. The degradation productscan be hazardous to human health in addition to potentially reducing the efficiency of the captureprocess (reduced capture rates, equipment corrosion). The issue of corrosion has the effect of limitingthe concentration of MEA to a maximum of 30wt%. Thus, in land-based applications, replacementsolvent costs are an appreciable part of the operational costs of the capture process. A further issueis the volatility of MEA—leading to solvent losses and the creation of a fire hazard. This is obviously ofparticular importance in shipping applications.Thus, the principal challenges associated with CO2 capture from ships can be summarized as:

1. Energy penalty associated with solvent regeneration2. Solvent degradation by SOx, NOx and O2

3. Solvent and CO2 storage


In addressing points 1 and 2 above, astute selection of the solvent is the key. The solvent used inchemical absorption processes such as this one effective defines the thermodynamic and kineticlimits of a given process. Thus it is desirable that we identify sorbent materials with

1. High capacity to absorb CO2– minimize equipment size2. High thermal and chemical stability, i.e., resistant to thermal and chemical degradation3. Low volatility – avoid solvent losses and the generation of a fire hazard4. 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 applicationto land-based CO2 emission sources. Ammonia (NH3) has the advantage that it is chemically verystable – it is not degraded by O2, and is capable of simultaneously removing CO2, NOx and SOx inaddition to any HCl and/or HF that might exist in the flue gas [19]. The robust nature of this sorbent isof 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. Thisreaction follows the form [20,21]:

NH3(l) + CO2(g) + H2O(l) ! NH4HCO3.

Further, it has been reported that the energy consumption for CO2 regeneration using anammonia-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 engineand 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 captureprocess as a closed-loop system at low temperatures. A key advantage of on-ship CO2 capture is theready 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 theirparticular physicochemical characteristics. In particular, their extremely low volatility marks them asenvironmentally benign alternatives to volatile organic solvents for separation processes. Thisnon-volatility also leads to most ionic liquids being non-flammable under ambient conditions. Inaddition, ionic liquids are typically both thermally and chemically stable, and therefore are suitablefor the simultaneous capture of CO2 and other acid gas pollutants [22]. Further, ionic liquids havebeen trialed for capturing CO2 and have been observed to offer up to a 16% saving on the energyconsumption when compared to MEA-based processes [23]. Crucially, the mechanism through whichCO2 is absorbed is thought to be entropically-driven (rather than enthalpically-driven) – this is whatappears to reduce the energy of absorption. One outstanding issue associated with using ILs forCO2 capture is the low density of the IL. This will tend to increase the footprint associated with thecapture process.

On-board storage of captured CO2

In the previous sections, we have outlined some new technology options which can address the issueof CO2 emissions from shipping. However, we have not, as yet, considered the issue of what to dowith the CO2 once it has been captured. We suggest that the option of on-board compression andstorage 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 canbe expected to increase in value in coming decades.


Another option is the concept of using CO2 as an environmentally benign C1 building block for theproduction of biodegradable polymers [6]. In particular, Kember et al. [24] have suggested using adizinc catalyst for the copolymerization of CO2 and cyclohexene to produce polycarbonates andpolyurethanes. 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 usedas a chemical weapon – so there are obvious advantages in replacing this process. The concept ofstoring captured CO2 on board ship as a solid material with a resale value has obvious commercialand operational advantages. Another advantage is the mechanism through which it may beoffloaded. Offloading a compressed fluid is substantially more complex than offloading a solidmaterial, thus the processes outlined here are attractive from this perspective also.

SHIP-BASED TRANSPORT OF CAPTURED CO2Another area in which shipping is considered to be of interest in the context of mitigatinganthropogenic CO2 emissions is in the area of transporting captured CO2. It is possible to envisage ascenario in which CO2 is captured from a diffuse range of point sources, transported to shore viapipe-line. However, rather than extending the transport network along the ocean bed, the CO2 couldbe loaded onto ships, and then it is transported to an appropriate injection site. Owing to its lowdensity, it is inefficient to transport CO2 in the gas phase. Liquefaction before shipping is thereforenecessary for volume reduction. It is common to liquefy gas for ship transport, as experiencedcommercially for LNG, LPG and other chemical materials. Another requirement before shipping is thetemporary storage and the loading to the ship, and similar one when necessary for after shipping. It isenvisaged that a ship-based CO2 transport can move approximately 20,000 m3liquid-phase CO2.This could be particularly attractive when there are several small streams of relatively impureCO2 available, which are not suitable for combined pipeline transport, but are suitable forinjection [25]. CO2 capture is a continuous process but the cycle of ship transport is not, so bufferingcapacity at the port and at the storage site is required. This scheme is illustrated in a flowsheet inFig. 8. It is interesting to note, however, that as long as the distance of the injection site from shore isrelatively small, i.e., less than 1000 km, there is relatively little merrit in having larger ships withwhich to transport CO2 [25,26]. This is illustrated in Fig. 7.

transport distance

ship size [ton]

US$

/ton

–CO

2

0 20000 40000 60000

60

50

40

30

20

10

0

200 km

500 km

1000 km

3000 km

6000 km

Figure 7. Influence of ship size and transport distance on cost, adapted from [25].

CONCLUSIONSInternational shipping is an important transport mechanism, and is predicted to grow in importanceover the coming decades. This will increase the importance of reducing the CO2 emissions from thissource, particularly as other sources are themselves mitigated. In this paper, we have outlined severaloptions – some near term, some longer term – which can be used to reduce the greenhouse gasfootprint of the shipping sector. As the current shipping fleet is likely to be in service for severaldecades yet to come, the chemical conversion options are likely only to be applied closer to 2050.


CO2 source

CO2 ship

CO2 injection

CO2 capture

compression

(transport to port)pipeline

port

storage site (temporary storage)

temporary storage

(unloading)

marine transport

loading

liquefaction

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 inatmospherepurification and control on nuclear-powered submarines. Naval Research Laboratory, Washington, DC.1962.

http://www.theccc.org.uk/carbon-budgets/path-to-2050


[18] Gustafson P.R., Miller R.R. and Piatt V.R. eds., CO2 Absorption Properties of Some New Amines. The Present Statusof 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 gasemissions. 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 ReactiveMixtures 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-SAFTapproach. 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 oxideat 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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Published: 19 December 2012c� 2012 Al-Tamimi, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

Green shippingTalal Al-Tamimi

RasGas Company Limited, Doha, Qatar

SUMMARYThe 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 thenloaded to tankers for transportation. But along with the objective of supplying LNG to customers asefficiently as possible, comes the responsibility to be environmentally aware and, in particular, toensure that any carbon emissions during the loading and transportation are minimised. Thepresentation 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 isthat, although these vessels are much larger than the conventional carriers, the fuel consumption isalmost the same, with obvious economic and environmental advantages. It is emphasised thatcarbon dioxide emissions to the atmosphere from the LNG cargo itself are minimal since the carriersare 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 thefuel. The benefits of replacing marine diesel fuel with gas are delineated, not only with respect tocarbon emission reduction, but also to ensure that the legal restrictions on the sulphur content of amarine 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 greenhousegas emissions can be substantially reduced and the recovered gas can be used to generate asignificant percentage of the power required by the State of Qatar.

Cite this article as: Al-Tamimi T. Green shipping, Sustainable Technologies, Systems and Policies2012 Carbon Capture and Storage Workshop:20 http://dx.doi.org/10.5339/stsp.2012.ccs.20

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Published: 20 December 2012c� 2012 Benyahia F, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

The carbon conundrum: GCCperspectivesFarid Benyahia*

Department of Chemical Engineering,Qatar University, Doha, Qatar*[email protected]

ABSTRACTThe 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 stemsfrom 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 managementwould flourish. The situation is also exacerbated by doubts about the suitability of sites and globalcapacity to store captured CO2. Sophisticated cost models have been developed for carbon captureand storage, and these indicate that cost reduction in the complete carbon value chain should befocused on the capture phase as this is the most energy intensive. However, there are uncertaintiesabout 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 andenergy in the world, and by default emitters of CO2 per capita. There are currently no demonstrationor commercial scale CCS facilities in the GCC and in the short term, it is unlikely to be the case giventhat current carbon capture technologies favor coal rather than natural gas as fuel in power plants. Itis also unlikely that underground carbon storage be considered in the short term, given the risk ofCO2 plume migration that may displace brine in saline formations into strata containing hydrocarbonresources or potable. It is therefore imperative that substantial research be conducted to identifystorage sites, reduce energy consumption in carbon capture and develop alternatives to CCS in theform of carbon conversion into useful products or minerals with low environmental impact. The GCChave tremendous opportunities to lead the world in carbon management given their strongexperience in hydrocarbon processing. However, this may only be successful if agreed policies andlegal 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

Cite this article as: Benyahia F. The carbon conundrum: GCC perspectives, SustainableTechnologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:21http://dx.doi.org/10.5339/stsp.2012.ccs.21

of 8Benyahia F, Sustainable Technologies, Systems and Policies 2012.CCS.21

INTRODUCTIONThe GCC states are characterized by a number of unique features that make them quite distinctcompared to other countries in the Middles East and North Africa (MENA) and indeed any other partsof the world. These features may be broadly defined as permanent and non-permanent. Thepermanent features include hot climate, fresh water scarcity and arid land and poor soil nutrients. Thenon-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 inTable 1.

Table 1. Sources of energy for domestic 1 consumption in the GCC.

State Natural gas Oil

Bahrain 84.2% 15.8%Kuwait 37.4% 62.6%Oman 69.3% 30.7%Qatar 75.3% 24.7%K.S.A 37.6% 62.4%U.A.E 82.4% 17.6%

1 For electricity generation2 Source: International Energy Agency (2008)

Despite the Middle East and North Africa (MENA) region seeming energy-rich and holding 56% ofthe world proven oil reserves, it is on a downward trend in terms of energy security. MENA countriesare approximately 60% more energy-intensive than OECD countries. Environmental degradation,resource depletion, limited conversion capacities and unbalanced regional distribution of fossil fuelresources, have had strong constraining effects on MENA economies. This has been exacerbated withthe region’s fresh water supply because of heavy reliance on desalination, in turn, imposingincreasingly 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 theworld. 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 carbondioxide per person).

State/Year 2005 2006 2007 2008 2009

Bahrain 36 40 41 43 43Kuwait 33 32 30 31 31Oman 12 13 14 16 17Qatar 67 70 72 74 76K.S.A 17 17 16 17 17U.A.E 34 36 39 42 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 25 28 29 31 31Kuwait 77 77 75 79 84Oman 31 36 38 44 49Qatar 52 56 59 61 64K.S.A 405 406 396 426 438U.A.E 140 155 172 196 194

Source: US energy information administration (2010)

The energy intensity of the GCC states includes a significant contribution from desalination plantsthat are typically coupled with power generation. When water consumption increases (which is


currently the case), demand for power also increases and the carbon emissions naturally follow. It isinstructive to notice that a great deal of the fresh water produced in the GCC is used for agriculturalpurposes.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 sustainabilityexercises. The best known examples of these were articulated in the Qatar National DevelopmentStrategy 2011–2016 and the Qatar National Vision 2030, where rational use of hydrocarbonresources and environmental protection constituted essential ingredients. Amongst these, carbonemission reduction is given particular attention. The global carbon conundrum is perhaps morecomplex in the GCC region given its excessive dependency on hydrocarbons to drive the economyand provide essential power for fresh water supplies and air conditioning during the hot months ofthe year. This paper attempts to highlight and explain the current outstanding issues preventing thefull deployment of carbon capture and storage, and the GCC specific barriers and opportunities.

CARBON CAPTURE AND STORAGE: STATE OF THE ART AND GLOBAL HORIZONSState of the art in carbon captureThere has been significant progress in technology development and costing models for carboncapture for power plants ahead of full deployment in the future, pending similar progress being madein underground storage and legal frameworks. The carbon capture technologies explored includepost-combustion, pre-combustion and oxyfuel combustion. Sophisticated cost models weredeveloped depending on the type of fossil fuel used and the degree of carbon capture integrationwithin the plant. This progress has been largely led by industry given its vast experience in powerplant systems and gas processing [4]. In summary, economics of carbon capture favor coal fueledpower plants because more carbon is emitted from such facilities compared to gas driven powerplants. It has been suggested that the capture and transport cost of CO2 from coal fired plants wouldbe around 50 USD compared to 100 USD for natural gas [4]. Obviously this cost range needs regionaladjustments. The cost of the full carbon value chain seems to be dominated by the cost of captureand compression accounting for as much as 80% of the total carbon capture and storage (CCS) costdespite uncertainties in the cost of underground storage. Extensive details of such models, as well ascomprehensive details of the state of the art in carbon capture technologies, may be found in [4]. Ingeneral, 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 verysensitive to policies and regulations.

Carbon storage state of the art

The inter-governmental panel on climate change (IPCC) produced several useful documents aimed athelping decision makers on carbon matters. An important report by the IPCC includes a survey onglobal potential underground storage capacity for captured CO2 [5]. It can be seen from Fig. 1 thatpromising storage sites (shown as dark areas) are not uniformly distributed, that these sedimentarybasins 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 carbonstorage sites, making it hard for the international community to exert any form of pressure on them tostore CO2 from power plants, simply because they do not have such facility. The absence of policiesand legal frameworks makes it practically impossible to reach agreements with countries that do havestorage 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. Accordingto the international energy agency, deep saline aquifers offer potentially decades or hundreds ofyears’ worth of storage capacity with estimated 1,000-10,000 Gt of capacity available. This iscurrently the single most important underground storage potential. Around 920 Gt of CO2 could bestored in depleted oil and gas fields. Small leakages of CO2 may occur over an extended period oftime, 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 arelatively safe place to store CO2 provided exploration work did not entail excessive fracturing and


Figure 1. Global prospectivity for captured CO2 storage [5].

other forceful forms of enhancing hydrocarbons extraction. The problem for such reservoirs istherefore if the extraction activity has created leakage pathways, and if abandoned boreholes can beplugged properly so the CO2 cannot escape. Many projects for natural gas storage and acid gasstorage have worked well. Progress in modeling allows increasingly accurate forecasts of thelong-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 aftersuccessful operations of commercial scale facilities (in Salah, Algeria; Sleipner, Norway) anddemonstration 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 stageof commercialization, and is a long-term prospect rather than a short-term option. This is especiallytrue for CCS from natural gas power generation; nearly all existing or planned CCS power plantsworldwide are coal-fired. Moreover, because natural gas generation is 50 percent less carbonintensive 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 carboncapture from natural gas plants, the predominant means of power generation in the GCC, are limitedin comparison with those from coal power plants elsewhere. Anyhow, even in those markets that dohave a price on carbon, the financial incentive is currently nowhere near adequate to justifyinvestment 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 asuitable site to prove that CO2 can be safely stored in the required quantities. As experience in the oiland gas industry has shown, these activities can incur significant costs with no guarantees ofreaching injection targets. In the same manner, for CO2 storage, significant investments can be madein finding and appraising a potential storage site only to find that it is unsuitable for any number ofreasons, not limited to technical unsuitability. The costs associated with finding and appraisingpotential storage sites, whether they are successful or not, is referred to as the ‘‘finding cost’’, parallelwith 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 thesite under consideration, and emphasizes:


• 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 andcompression has received a great deal of attention in the CCS value chain. However, the finding andappraisal of CO2 storage sites is the critical path technology in the CCS value chain, and canpotentially 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 abandonedwells that could potentially act as leakage pathways to the surface. Detailed well integrity studies andrisk 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 similararea) due to the presence of residual, un-produced hydrocarbons and likely pressure limitationscaused 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 formationsduring 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 followingimportant points:

• Insufficient financial incentive to implement CCS

• High capital and operating costs and minimal experience with integrated operation on a largescale 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 potentialapplication in enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Currently, many of thecountries in the GCC increase the productivity of mature oil and gas fields by pumping in natural gasto increase well pressure. Given the projected spike in electricity demand in the region, and thecorresponding increase in the use of natural gas supplies for power generation, the use of gas for oilrecovery may become economically unfeasible. By pumping CO2 into declining oil wells in place ofnatural gas, the countries of the GCC can free up valuable volumes of hydrocarbons. The gas savedcan then be used either for domestic power generation or for export, earning additional income. It isimportant to recognize that EOR/EGR is not long term CCS. Given the status of CCS described in theprevious sections, what are the specific challenges and perspectives in the GCC?

CARBON MANAGEMENT CHALLENGES AND PERSPECTIVES IN THE GCCStatus of carbon capture and geological storage sites in the GCC regionSo far no public announcement has been made on an identified geological site in the GCC region forCO2 storage for a demonstration or commercial scale facility. Furthermore, no significant investmenthas been made to develop CO2 capture technologies from gas or oil fueled power plants. Theplausible reasons for this lack of progress in CCS in the GCC region stems from the fact that themajority of power plants are fueled by natural gas, considered as a clean fuel and having considerablyless carbon emissions than coal. In addition, carbon capture studies elsewhere have shown thateconomics are more favorable for coal than for natural gas as more CO2 is emitted from the formerthan from the latter. This is seen as a serious setback and negative incentive. Hence, if carbon capturehas no incentive for development and investment, it is highly unlikely that carbon storagedemonstration units would even be considered. However, as was pointed out in the introductionsection of this paper, there is a genuine intention in the GCC region to promote sustainability and


environmental protection. This was for example articulated in the Qatar National DevelopmentStrategy 2011–2016. However, the pace of future CCS deployment in the GCC region may behindered by insufficient understanding of sequestration resource potential and infrastructure. Just likeelsewhere in the world, the GCC states currently have no policies or legal frameworks to regulatefuture 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 tocontinue to consume considerable amounts of energy to maintain the standard of living currentlyenjoyed, regardless of the source of energy. In the short term, it is likely that these sources willcontinue to be oil and natural gas. Hence it is quite understandable to accept the feeling ofdiscomfort at prospects that injected CO2 plumes in underground saline formations may displacebrine into strata containing resources like hydrocarbons or potable water. Furthermore the knownrock acidification and fracturing practices to enhance production only add to the risks associated withCO2 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 GCCstates citizens do not pay for the electrical power or water consumed, thus eliminating any incentiveto reduce waste in these precious resources. It is well known that water consumption in the GCC isamongst the highest in the world despite water being produced in energy intensive desalinationplants. The notion of global climate change does not seem to be a major concern in the GCC as mostpeople think that in an arid region, the climate cannot get any worse. Other aspects of climate changeconsequences are hardly discussed or even understood in general terms.

Carbon management opportunities in the GCCThe GCC region has accumulated considerable oil and gas exploration and processing experience inthe 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, andmay be an area where GCC states can make impressive efforts in cost reduction. In addition, severalGCC nations including the United Arab Emirates, Saudi Arabia and Qatar have pledged substantialfinancial 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 solarpotential in the GCC put the region’s annual average global radiation available to photovoltaic cells atabout 6 kWh/m2/day. Estimates of the direct normal irradiance (DNI, available to solar concentratingtechnology) are around 4.5 kWh/ m2/day [6]. These figures indicate that a land area of approximately1,000 km2, representing about 0.2 percent of the GCC may be covered with photovoltaic cells at 20percent efficiency, could produce 438 TWh every year which is more than the 400 TWh typicallyconsumed by the region [6]. Nations of the GCC have either initiated, or committed to, investments insolar projects, with solar photovoltaic (PV) and concentrated solar power (CSP) being the maintechnologies of choice. Other potential solar-related applications applicable to the region includesolar 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 usefulfor large oil and gas industries, it certainly has an outstanding potential for homes, especially forlighting and small electrical appliances. In remote housing compounds, solar energy (both PV andCSP) may prove to be not only economic in the long term, but actually essential. The massiveexpansion of oil and gas industries in the GCC was also accompanied by a substantial release of lowgrade heat into the environment. There is a need to evaluate both quantities and useful applicationsof such waste heat, especially in water desalination.

Carbon conversion opportunities

Carbon conversion is gaining more and more attention as an alternative to underground storagewhere this is not feasible in the short or medium term or at all. Given that the CO2 molecule is quite


stable, it is anticipated that a limited but effective number of processes to convert CO2 into a useful orharmless 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 valuableproduct or into a harmless solid form. Given that the GCC countries enjoy sunshine for most of thedays in the year, there are opportunities to exploit this free energy source to convert capturedCO2 into hydrocarbons through microalgae growth. The process engineering experience accumulatedin the past three decades in the GCC’s gas processing industries can also be put into action for thedevelopment of selective catalysts to activate and convert CO2 into hydrocarbons. This new industrycan be fully integrated with existing petrochemical industries to enhance energy efficiency.

CONCLUSIONSThe final solution to the carbon conundrum seems to be out of reach in the short term mainlybecause of the lack of policies and legal framework. A great deal of knowledge has been gained fromdemonstration CCS facilities in some countries. However, cost, risk management and liability preventfull CCS deployment. In addition, there are doubts about the global storage capacities to absorb allpotential captured CO2 from power plants worldwide. In the GCC states, no geological sites have beenidentified for demonstration or commercial CO2 storage. Some of the reasons for this lack of initiativeinclude the cost of CO2 capture that currently favors coal as fuel compared to natural gas, and thereluctance to experiment in operational oil/gas fields that are mainly well away from depletion. Thereare indeed genuine risks that need evaluating. At some point in the future, the GCC nations will needto rely on their capacity to address the carbon conundrum given their specific characteristics. Thefollowing recommendations may be put forward to assist in gaining experience ahead of future CCSdeployment 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

ACKNOWLEDGEMENTThis publication was made possible by an NPRP award [NPRP 08-336-2-123] from the Qatar NationalResearch Fund (a member of Qatar Foundation). The statements made herein are solely theresponsibility of the author


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;30:673–690.[8] Omae I. Aspects of carbon dioxide utilization. Catalysis Today. 2006;115:33–52.[9] Benyahia F. The Carbon Conundrum: Challenges and opportunities in the Gulf region, Downstream Technology

Conference, Kuwait (Feb 2012).

OPEN ACCESS


Published: 19 December 2012c� 2012 Al-Hitmi, licenseeBloomsbury Qatar FoundationJournals. This is an open accessarticle distributed under the termsof the Creative CommonsAttribution License CC BY 3.0which permits unrestricted use,distribution and reproduction inany medium, provided the originalwork is properly cited.


Review article

QAFAC: Carbon dioxide recoveryplantKhalid Mubarak Rashid Al-Hitmi

Qatar Fuel Additives Co, Ltd., Doha,Qatar

ABSTRACTThis short report outlines Qatar Fuel Additives Company (QAFAC) plan to reuse the carbon dioxideemitted from their methanol plant. It is estimated that 500 tn/day of CO2 will be recovered from itsMethanol Reformer stack which will be injected into the Methanol Synthesis unit to enhance theproduction capacity. The Recovery Unit will be constructed under license from MHI (Mitsubishi HeavyIndustries, Japan) and will be a specific and novel application of CO2 recovery focused to optimizemethanol production. Overall, since operations are designed to produce 982,350 tonnes per annumof methanol and 610,000 tonnes per annum of MTBE, the QAFAC Plant will be one of the world’slargest commercial-scale CO2 capture facilities.

Cite this article as: Al-Hitmi KMR. QAFAC: Carbon dioxide recovery plant, SustainableTechnologies, Systems and Policies 2012 Carbon Capture and Storage Workshop:22http://dx.doi.org/10.5339/stsp.2012.ccs.22

of 3Al-Hitmi, Sustainable Technologies, Systems and Policies 2012.CCS.22

THE METHANOL PLANTA schematic of the methanol production from natural gas feedstock is shown in Fig. 1.

Natural Gasfrom QP-NGL

MeteringStation

Hg RemovalVessel

InletCompression

Feed Preparation

HydrodesulfurizationFuel Gas

Steam

Saturator

Flue Gas

Steam Reformer

Waste Heat Section

Reformed GasSynthesis Gas

SteamReformingCondensate

CDRPlant

Syn GasCompressor

RecirculatorCompressor

ARC Convertor

Fuel Gas

MeOHCatch Pot

Crude MeOH

MethanolSynthesis

CrudeTank

Flare

Heavy EndColumn

Light EndColumn

Distillation

MeOH

Fusel Oil

Water

Check Tanks

MeOH Storage Tanks

PureMeOH

SlopTank

ProductStorageTanks

To Export

CO2 Gas

To MTBE

To QAFCO

De-Saturator

METHANOL PLANT BLOCK DIAGRAM

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 theinlet of the plant. Sulphur is completely removed in the desulphurization section.

• Reforming Section: The desulphurized hydrocarbon is reformed together with steam toproduce the synthesis gas containing hydrogen, carbon monoxide, and carbon dioxide.

• Methanol Synthesis Section: The synthesis gas is, after compression to a pressure of about7,700 kPaG, converted into methanol by a catalytic reaction. Finally, dissolved gases andimpurities are removed from the methanol by distillation.

• Distillation Section: The crude methanol is distilled to separate the product methanol fromdissolved gas and the impurities.

This procedure is standard and based on the reversible reaction at the reforming stage:

CH4 + H2O ! CO + 3H2.

And, for the methanol synthesis, one has,

2H2 + CO ! CH3OH.

Further, however, carbon monoxide will react with water in the reforming process to yield carbondioxide and hydrogen:

CO + H2O ! CO2 + H2.

At the synthesis stage, the CO2 reacts with excess hydrogen to synthesize methanol,

CO2 + 3H2 ! CH3OH + H2O.

It turns out that about 50% of the carbon oxides contained in the synthesis gas is converted intomethanol per pass under the condition of excessive hydrogen. Hence, the unconverted synthesis gasis recycled as indicated in the figure.

of 3Al-Hitmi, Sustainable Technologies, Systems and Policies 2012.CCS.22

THE CO2 RECOVERY PLANTThe flue gases from the reformer are vented to the atmosphere at a rate of⇠600 to 620 tn/hr. Sincethe flue gas composition during normal plant operation on a volume/mol percent basis isCO2-5.49%, O2-1.83%, N2-65.90% and H2O-26.78%, approximately 55 tonnes of CO2 are emittedper hour. But, the chemistry indicates that adding CO2 to the synthesis gas mixture can increase thecapacity of the methanol plant due to excess hydrogen available in the synthesis loop. Clearly, then, itwould be advantageous to recover and use a significant proportion of the waste CO2. This is thedescribed 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 PowerCo., Inc. MHI’s technology features considerably lower energy consumption compared with otherprocesses and has won high evaluations for its performance. It is noted that, following the first plantin Malaysia in 1999, MHI has licensed and delivered its CO2 recovery technology to nine commercialCO2 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 theCO2 absorber, it is quenched by water then mixed with the KS-1 solvent on a packed bed. TheCO2 free gas is washed and emitted to the atmosphere. The CO2 rich gas is then sent to a packedcolumn regenerator where the solvent is heated and the CO2 is stripped from the column. Theregenerated CO2 is washed to remove any traces of solvent, compressed, and send back to theMethanol 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%.

SUMMARYEstablished in 1991, QAFAC is a joint venture between Industries Qatar, OPIC Middle EastCorporation, International Octane LLC and LCY Middle East Corp. The Company commencedoperations 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 projectdemonstrates the intent to be a leader in cutting industrial greenhouse gas pollution, and to play afront line role as an environmentally conscious company.

[continued from back cover]

CCS from industrial sourcesPaul S Fennell, Nick Florin, Tamaryn Napp, Thomas Hills

Introduction to market challenges in developing second-generation carbon capture materialsJason Matthew Ornstein

Shipping and CCS: A systems perspectiveN Mac Dowell, N Shah

Green shippingTalal Al-Tamimi

The carbon conundrum: GCC perspectivesFarid Benyahia

QAFAC: Carbon dioxide recovery plantKhalid Mubarack Rashid Al-Hitmi

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We are very pleased to offer this promotional print copy of this special issue of Sustainable Technologies, Systems and Policies. Please note, however, that the definitive version of the article is the electronic publication available online via the article DOI, i.e. http://dx.doi.org/10.5339/stsp.2012.ccs.9

The page numbering may cause some confusion. Since we publish articles online, we do not usually compile print issues such as this. Each article has a HTML and PDF version, with page numbers in the PDF version given for the reader’s benefit only. As a result, each article starts at page 1. Page numbers should not be used for citing the articles. For citation information, please refer to the ‘Cite this article as’ box at the bottom of the first page of each article.

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TABLE OF CONTENTS: SPECIAL ISSUE ON CARBON CAPTURE AND STORAGE (2012)

Preface and overviewHoward JM Hanley

Carbon capture: An introductionHoward JM Hanley

Industrial requirementsPatrick Linke

Pre- and post-combustionFedaa Ali

Industrial procedures and problemsFedaa Ali

Alternatives to amine-based capture & new technologiesFarid Benyahia

TransportFarid Benyahia

Economic and social issuesIain Macdonald

Carbon capture and storage: The way aheadGeoffrey C Maitland

Carbon capture and storage: The industry viewpointMarcus 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 UKAnne Korre, Zhenggang Nie, Sevket Duncan

Gas turbine related technologies for carbon captureR Peter Lindstedt

An overview of carbon capture technologyBruce R Palmer

The Lacq industrial CCS reference project (France)Jacques Monne

Ionic liquids as novel materials for energy efficient CO2 separationsRichard D Noble, Douglas L Gin

Metal-organic frameworks and porous polymer networks for carbon captureJulian Patrick Sculley, Jian-Rong Li, Jinhee Park, Weigang Lu, Hong-Cai Joe Zhou

[continued on inside back cover]

carbon capture & storage

Documents

university of oxford

qatar proceedings

salle university

sustainable generation

uk adisa azapagic university

qatar hans muellersteinhagen

qatar raymond r tan

scope of journal