TODAY’S STUDY: ANOTHER REPORT FINDS NO “CLEAN” COAL

2010 Carbon Sequestration Leadership Forum Technology Roadmap; A Global Response to the Challenge of Climate Change
November 2010 (Carbon Sequestration Leadership Forum)

“Clean” coal is a seductive concept but any disciplined evaluation, no matter how sympathetic, cannot avoid concluding it does not now exist and there are a lot of problems to solve before it ever can. The study below, from what is essentially a booster organization, is exemplary. Look at the list of “gaps” in every stage of the process.

The reasons "clean" coal remains a seductive come-on instead of a reality are simple: (1) Capturing and storing the carbon dioxide byproduct of burning coal are very expensive undertakings. Adding them to the process makes coal anything but cheap. Look at the cost statistics in the report. (2) Transporting and storing the carbon dioxide byproduct of burning coal are very risky undertakings. Even if the technology's proponents find storage sites, they will not find insurers. Look at the risk analyses in the report.

It has been said here before and with Congress now being run by Representatives owned by Big Coal it will no doubt need saying again (and again): There is no logic to investing in “clean” coal. The smarter and wiser thing to do is spend the same money to build New Energy and Energy Efficiency. The payoff will come sooner, last longer, be far less costly, much safer and have far more benefits.

Context

Carbon dioxide (CO2) capture and storage (CCS) can play a critical role in tackling global climate change. In order for it to be an effective part of the solution, CCS must be demonstrated as soon as possible with wide deployment before the target date of CCS commercialization by 2020. A prerequisite to this achievement is the establishment of the technical foundation for affordable capture, transport, and safe and effective long-term geologic storage of CO2 as quickly as possible.

This Technology Roadmap (TRM) has identified the current status of CCS technologies around the world; the increasing level of activity in the industry; the major technology needs and gaps; and the key milestones for a wide development of improved cost-effective technologies for the separation, capture, transport, and long-term storage of CO2.

Implementation of national and international pilot and demonstration projects is seen as a critical component in the development of lower-cost, improved capture technologies and safe long-term storage. The demonstration projects have to be built in parallel with research and development (R&D) efforts in order to close the technological gaps as cost effectively as possible.

The Carbon Sequestration Leadership Forum (CSLF) will continue to catalyze the deployment of CCS technologies by actively working with member countries, governments, industry, and all sectors of the international research community on the strategic priorities outlined in this TRM. The CSLF will also continue to work with existing and new support organizations, such as the Global Carbon Capture and Storage Institute, in order to efficiently utilize scarce world resources and effort and to ensure that key technology gaps are addressed and closed.

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The first CSLF TRM was developed in 2004 to identify promising directions for research in CCS. The TRM was updated in 2009 to take into account the significant CCS developments that occurred during the 2004 to early 2009 period and identify key knowledge gaps and areas where further research should be undertaken. This document is an update of the 2009 TRM. The main changes from the 2009 TRM are:

• Stronger emphasis on CCS integration and demonstration;

• Differentiation between demonstration and R&D; and

• Expanded and more detailed milestones for capture.

Since the last CSLF TRM update, significant international activity in the CCS field has occurred.

The International Energy Agency (IEA) issued a TRM in 2009 (IEA, 2009) that addressed not only the technological aspects of CCS but also financing, legal and regulatory issues, public engagement as well as education and international collaboration aspects. In early 2010, the European Technology Platform for Zero-Emission Fossil Fuel Power Plants (ZEP) issued recommendations for research to support the deployment of CCS in Europe beyond 2020 (ZEP 2010). This 2010 update of the CSLF TRM has benefitted from these two documents and supplements and expands on recent developments in technology.

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Significant CSLF project activity occurred in the period from 2004–2009, and substantial progress has been made in all aspects of CCS, resulting in successful completion of the early completed CSLF-recognized projects demonstrating worldwide collaboration on CCS and contributing to the CCS knowledge base. Completed projects include:

• Alberta Enhanced Coalbed Methane Recovery Project
• CASTOR
• China Coalbed Methane Technology/CO2 Sequestration Project
• CO2 Capture Project (Phase 2)
• CO2 SINK
• CO2STORE
• Dynamis
• ENCAP
• Frio Brine Pilot Project

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Regional Opportunities for CO2 Capture and Storage in China Active projects include:

• CANMET Energy Technology Centre (CETC) R&D Oxyfuel Combustion for CO2 Capture
• CCS Bełchatów Project
• CCS Northern Netherlands
• CCS Rotterdam
• CO2CRC Otway Project
• CO2 Field Lab Project
• CO2 GeoNet
• CO2 Separation from Pressurized Gas Stream
• Demonstration of an Oxyfuel Combustion System
• European CO2 Technology Centre Mongstad
• Fort Nelson Carbon Capture and Storage Project
• Geologic CO2 Storage Assurance at In Salah, Algeria
• Gorgon CO2 Injection Project
• Heartland Area Redwater Project (HARP)
• IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project
• ITC CO2 Capture with Chemical Solvents
• Lacq CO2 Capture and Storage Project
• Quest CCS Project
• Regional Carbon Sequestration Partnerships
• SECARB Early Test at Cranfield Project
• Zama Acid Gas EOR, CO2 Sequestration, and Monitoring Project
• ZeroGen

At the time of this writing, several medium scale (10–50 MW) capture plants were being planned or launched as a result of extensive R&D, but there has not been sufficient experience upon which to draw operational conclusions. On the research side work has continued with existing absortion processes, solid adsorbents and membrane, and significant progress has been made at the laboratory scale. Some important learnings regarding capture technologies have been summarised in a forthcoming report from the IEA Greenhouse Gas R&D programme (IEA GHG, to be published). Although the summary is based on studies issued by IEA GHG in the period 2005–2009, the findings are universal. One finding is that for post combustion capture, solvent
scrubbing is considered the state-of-the-art and that solid adsorbents and membranes-based processes are considered to be second- or even third-generation technologies. The latter also holds for pre-combustion and oxyfuel. Further, efforts to improve the solvent scrubbing capture systems need to be continued, as the main challenge is reduce the capture cost. The report also concludes that CO2 capture has a net environmental benefit, due to the avoidance of CO2 emissions. However, there is a valid concern regarding environmental effects related to solvent losses and other wastes produced from the capture plants. The same IEA GHG report indicates that it is of utmost importance that governments provide financial support for storage resource exploration and for the development of the first commercial-scale CCS projects, to have robust CCS policies that provide certainty to investors and to support ongoing technical development.

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An important achievement in CO2 transport is the first off-shore CO2 pipeline that was built in the Snøhvit Field in the Barents Sea off Northern Norway. This pipeline, which has been in operation for two years, is about 160 km long and transports 0.7 million tons per annum of CO2.

The first commercial scale storage projects (Sleipner, In Salah, and Snøhvit) have shown that geological storage of CO2 in saline aquifers is technologically feasible and they have added significant knowledge on monitoring and verification technologies, including use of remote sensing.

Regulatory frameworks will influence technical decisions. There is still some concern as to whether CO2 is classified as a waste or not, and what types and quantities of impurities are acceptable in the stored CO2, but the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (http://www.imo.org/Conventions/contents.asp?topic_id=258&doc_id=681) and the OSPAR Convention (http://www.ospar.org/) have been amended to allow CCS.

Updates to this document will be made on a regular basis so that the TRM remains a living document and reference point for future CCS development and deployment.

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Preamble – Sources of CO2

Anthropogenic CO2 is emitted into the atmosphere from:
• The combustion of fossil fuels for electricity generation;
• Industrial processes, such as iron and steelmaking and cement production;
• Chemical and petrochemical processing, such as hydrogen and ammonia production;
• Natural gas processing;
• The commercial and residential sectors that use fossil fuels for heating;
• Agricultural sources; and
• Automobiles and other mobile sources.

Due to the relative scale of emissions from stationary energy production there is an emphasis on power station emissions, although other emission sources from the energy and petrochemical industries, and industrial and transport applications are considered in the document.

To appreciate the volumes of CO2 generated, a typical 500 megawatt (MWe) coal-fired power station will emit about 400 tonnes of CO2 per hour, while a modern natural gas-fired combined cycle (NGCC) plant of the same size will emit about 180 tonnes per hour of CO2 in flue gases.

The respective CO2 concentrations in flues gases are about 14 percent (by volume) for a coal fired plant and 4 percent CO2 for an NGCC plant. By comparison, the concentration of CO2 in the flue gas of a cement kiln can be up to 33 percent by volume.

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As seen in Figure 1 for global emissions, stationary energy/electricity generation from fossil fuels is responsible for just over one-third of all CO2 emissions. The emissions from other, large industrial sources, including iron and steelmaking, natural gas processing, petroleum refining, petrochemical processing, and cement production, amount to about 25 percent of the global total.

As the CO2 emitted from such processes is typically contained in a few large process streams, there is good potential to capture CO2 from these processes as well. The high CO2 concentrations of some of these streams, such as in natural gas processing and clinker production in cement making, may provide ideal opportunities for early application of CO2 capture technology.

The global iron and steel industry is assessing carbon capture in the iron ore reduction process (principally the blast furnace and electric arc furnace routes) as one of a number of pathways for a low carbon future. The European Ultra Low Carbon Dioxide Steelmaking (ULCOS) program (http://www.ulcos.org/en/about_ulcos/home.php) is one such initiative that includes CCS as an element of technological developments.

The remaining anthropogenic CO2 emissions are associated with transportation and commercial and residential sources. These are characterised by their small volume (individually) and the fact that, in the case of transportation, the sources are mobile. Capture of CO2 from such sources is likely to be difficult and expensive; storage presents major logistical challenges, and collection and transportation of CO2 from many small sources would suffer from small-scale economic distortions. A much more attractive approach for tackling emissions from distributed energy users is to use a zero-carbon energy carrier, such as electricity, hydrogen, or heat.

CO2 capture is, at present, both costly and energy intensive. For optimal containment and risk related reasons, it is necessary to separate the CO2 from the flue gas so that concentrated CO2 is available for storage. Cost depends on many variables including the type and size of plant and the type of fuel used. Currently, the addition of CO2 capture can add 50–100 percent (or more) to the investment cost of a new power station (OECD/IEA, 2008).

CO2 capture systems are categorised as post-combustion capture, pre-combustion capture, and oxy-fuel combustion.

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...Capture of CO2…Post-combustion Capture…Pre-combustion Capture…Oxyfuel Combustion…Type of Capture Technology…Chemical Solvent Scrubbing…Physical Solvent Scrubbing…Adsorption…Membranes…Cryogenics…Other Capture Processes…Further Work Required...

CO2 Transmission/Transport…Pipelines…Ship Tankers…

Storage of CO2…General Considerations…Geologic Storage…Deep Saline Formations…Depleted Oil and Gas Reservoirs…Unmineable Coal Beds…Other Geological Storage Options…Mineralisation…Deep Ocean Storage…Security of Storage…Natural Analogues of CO2 Storage…Commercial Analogues of CO2 Storage…Understanding Leakage…Risk Assessment…

Uses for CO2…Enhanced Oil and Gas Recovery (EOR and EGR)…Biofixation…Industrial Products…

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The Potential for CO2 Storage

Economically, once the more profitable offsets for CO2 injection have been exploited, the storage of CO2 will need other cost drivers to ensure its financial viability such as a price on carbon. Storage of CO2 in oil and gas reservoirs will have the advantage that the geology of reservoirs is well known and existing infrastructure may be adapted for CO2 injection. The same does not apply to unmineable coal seams or storage in deep saline formations, which collectively may be exposed to higher overall storage cost structures because of lack of offsets.

Figure 7 indicates the theoretical global storage capacity for deep saline formations, depleted oil and gas reservoirs, and unmineable coal seams. Note that these capacity estimates are broad indications only, with high ranges of uncertainty, and include non-economical options.

Many factors influence the costs of storage and these are very site-specific (e.g., the number of injection wells required, on-shore versus off-shore, and so on). However, the storage component of CCS is generally held to be the cheapest part of the process, in which the costs of capture dominate. Figure 8 (table) shows estimates of CO2 storage costs.

Economic modeling in the Global CCS Institute 2009 Strategic Analysis of the Global Status of CCS, which is summarized in Figure 11, determined that the cost of CCS for power generation, based on the use of commercially available technology, ranged from US$62 to US$112 per tonne of CO2 avoided or US$44 to US$90 per tonne of CO2 captured. The lowest cost of CO2 avoided was at US$62 per tonne of CO2 for the oxyfuel combustion technology, while the highest cost at US$112 per tonne of CO2 for the NGCC with post-combustion capture. This compares with the lowest cost of captured CO2 for the oxy-combustion and IGCC technologies at US$44 per tonne of CO2 and the highest of US$90 per tonne of CO2 for NGCC technologies. The metrics are determined for the reference site in the USA with fuel costs based on values typical for 2009.

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Figure 11 also shows the percentage increase in costs that the application of CCS has over non-CCS facilities. For power generation, facilities that had the lowest cost increases were IGCC (39 percent), NGCC (43 percent), followed by oxyfuel combustion (55–64 percent) and PC supercritical (75–78 percent) technologies.

The application of CCS for first-of-a-kind (FOAK) industrial applications shows that cost of CO2 avoided is lowest for natural gas processing (US$18), and fertiliser production (US$18) followed by cement production (US$50) and blast furnace steel production (US$52).

Figure 11 enables comparisons to be made across industrial applications in regards to the percentage increase in costs arising from the application of CCS. The lowest cost increase is for natural gas processing (1 percent) followed by fertiliser production (3–4 percent). This is unsurprising given that these industries already have the process of capturing CO2 as a part of their design. The production of steel (15–22 percent) and cement (36–48 percent) have the highest percentage cost increases with the application of CCS because the capture of CO2 is not inherent in the design of these facilities.

The margin of error in comparative CCS technology economics, however, makes it difficult to select one generic technology over another based on the levelised cost of electricity (LCOE). Projects employing different capture technologies may be viable depending on a range of factors such as location, available fuels, regulations, risk appetite of owners, and funding.

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Cost reduction will occur through the progressive maturation of existing technology and through economies of scale, as well as from technology breakthroughs with the potential to achieve step reductions in costs. For example:

• Capital costs of capture equipment will decline 6–27 percent for power generation projects with implementation of lessons learned from FOAK projects. These reductions result in potential generation and capture capital cost savings of 3–10 percent and a resulting decrease in the LCOE of less than 5 percent.

• Process efficiency improvements both in the overall process and the energy penalty for CO2 capture will result in significant savings. The introduction of technologies such as ITM for air separation for oxy-combustion, which reduces the auxiliary load and thus improves the overall efficiency, leads to a 10 percent decrease in the cost increase (LCOE basis) resulting from the implementation of CCS. Capital costs are reduced through the plant size decreasing to produce the same net output. The operating costs decrease through a reduction in the fuel required per unit of product.

• Industrial processes which currently include a CO2 separation step (natural gas processing and ammonia production, for example) have greatly reduced incremental cost increase related to CCS deployment. Projects employing these processes can be considered as early movers of integrated systems. In this case the CO2 separation costs are currently included in the process and do not represent an additional cost.

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• Pipeline networks, which combine the CO2 flow from several units into a single pipeline, can reduce cost of CO2 transport by a factor of three.

• The initial site finding costs and characterisation represent a significant risk to the project and can increase storage costs from US$3.50/tonne CO2 to US$7.50/tonne CO2, depending on the number of sites investigated.

• Reservoir properties, specifically permeability, impact the ease that CO2 can be injected into the reservoir and the required number of injection wells. Reservoirs with high permeability can reduce storage cost by a factor of two over reservoirs with lower permeability…