Comments made to the Senate Committee

 On Commerce, Science, and Transportation

Science, Energy, and Innovation Subcommittee

 

Senator Kerry and Members of the Subcommittee.  Good afternoon.  My name is James Katzer, and I am a Visiting Scholar in the Laboratory for Energy and the Environment of Massachusetts Institute of Technology.  For about the last two years, I have been working with a group of MIT faculty who have been looking at the future of coal. I am pleased to have been invited to discuss key aspects of this work with you today.   I will focus on coal-based power generation technology combined with the capture and sequestration of carbon dioxide emissions.  I am submitting my written testimony herewith.

 

Coal presents the ideal paradox in power generation.  On one hand, it is cheap, abundant, and concentrated typically in countries with large human populations and limited oil and gas.  On the other hand, its use can have significant environmental impacts, requires capital-intensive generating plants, and produces large quantities of carbon dioxide.  Both U.S. and global electricity demand will continue to grow at a brisk rate, and coal is certain to play a major role in meeting this demand growth.  The U.S. has 27% of the total global recoverable coal reserves, enough for about 250 years at current consumption.  Over 50% of U.S. electricity was generated from coal last year.  Figure 1 shows the projected growth in coal consumption for the recent  EIA forecast under business as usual.  It is inevitable that we will see increased coal consumption and CO₂ emissions there from.

 

It is important to understand the magnitude of commercial CO₂ capture and sequestration associated with power generation because its scale offers unique challenges and opportunities in the research, development and demonstration arena.  A single 1000 MW_e coal-based power plant emits between 5 and 8 million tonnes of CO₂ per year, or about 130,000 bbls per day of supercritical liquid CO₂. This would become 200 to 300 million tonnes of  CO₂ over the 40 year life of the plant and require a reservoir storage volume of about 1.5 billion bbls of liquid CO₂.

 

The primary technology used to generate electricity from coal today is pulverized coal (PC) combustion.  It is well-established, mature technology.  The efficiency of generation depends on a number of design and operating variables, on coal type and properties, and on plant location.  New plant designs have significantly higher operating efficiencies than the current fleet average, but the limit for the near term is probably being reached.

 

Integrated Gasification Combined Cycle (IGCC) is a competitor to PC generation.  Four coal-based IGCC demonstration plants, each between 250 and 300 MW_e, have been built, each with government assistance, and are operating well.  In addition, there are 5 refinery-based IGCC units, two at 500 MW_e each, which are gasifying petroleum coke, or refinery asphalt, residua, tars, and other residues to produce electricity.  These units often also produce steam and hydrogen for the refinery.  IGCC is well-established commercially in the refinery setting.  IGCC can also be considered commercial in the coal-based electricity generation setting, but in this setting it is neither well-established nor mature.  As such, it is likely to undergo significant change as it matures.  Currently, a major concern with coal-based IGCC is gasifier availability.

 

Because a large number of variables, including coal type and quality, location, etc, affect generating technology choice, operation, and cost, the technology comparisons here center on one point-set of conditions.  This includes one coal, Illinois #6 coal, a high-sulfur bituminous coal and generating units designed to achieve criteria emissions levels somewhat lower than the lowest recent permitted plant levels.  For example, the designs used here achieve 99.4 % SO_x and 99.9+ % particulate removal.  These technologies are first compared without CO₂ capture and then with 90% CO₂ capture.  Plant capital costs are based on detailed design studies between 2000 and 2004, and on industrial experience during that period.  This was a period of relative cost stability.  No attempt has been made to account for recent cost escalations in materials, engineering, and construction costs.  These have been substantial.  However, the important issue here is the relative numbers among and between the various technologies, and these are probably best based on the 2000 to 2004 period.  Here the focus is on technologies that are either commercial or well on their way to becoming commercial.

 

PC Combustion:  PC generating efficiency is about 35% for subcritical generation, about 38% for supercritical generation, and about 44% for ultra-supercritical generation.  Increased generating efficiency means less emissions per unit of electricity, including less CO₂ emissions.  In moving from subcritical to ultra-supercritical generation, the coal required per unit electricity is reduced by about 22%, which means a 22% reduction in CO₂ emissions and also reduced criteria emissions.  Most PC units in the U.S. are subcritical.  We have no ultra-supercritical plants in operation, or under construction.  On the other hand, Europe and Japan, which have higher coal costs and stronger culture supporting high efficiency, have built almost a dozen ultra-supercitical units over the last decade.  These units are operating as well as subcritical units, but with much higher generating efficiency.  The key enabling technology here is improved materials to allow operation at higher severity conditions.  An expanded U.S. program to advance materials development and particularly improved fabrication and repair technologies for these materials would advance the potential for increased PC generating efficiency for our changing future.

 

Application of advanced emissions control technologies to PC units can produce extremely low emissions, and emissions control technology continues to improve, including the potential for high degrees of mercury control.  In general, the issue of PC emissions is not a question of technology capability but the breadth of its application.

 

For Illinois #6 coal at $1.50 per million Btu and detailed design study capital costs using  EPRI economic TAG guidelines and assumptions,  the estimated cost of electricity (COE) for a supercritical PC is about 4.75 ¢/kW_e-h [1] [2].  Table 2 summarizes the performance and cost parameters for the several generating technologies.  For supercritical generation about 1 ¢/kW_e-h, or about 20%, is associated with going from no emissions control to the high level of emissions control used here.  Reducing emissions by a factor of two further would add an estimated 0.2 ¢/kW_e-h increasing the COE to about 5.0 ¢/kW_e-h. 

 

IGCC:  The promise of IGCC has been high generating efficiency and extremely low emissions.  There are a number of critical options associated with gasification technology and its integration into the total plant that affect efficiency and operability.  Of these, the gasifier type and configuration are the most important. Table 1 summarizes the characteristics of gasifier types.  Entrained-flow gasifiers, which are extremely flexible, are the basis of each of the IGCC demonstration units.  Figure 2 shows the configuration of an IGCC employing full quench cooling of the gasifier exit gases.  This configuration with high quality coals will produce about 35-36 % generating efficiency.  Figure 3 illustrates the addition of a radiant syngas cooler to raise steam for the steam turbine, which increases the electricity output and raises the generating efficiency to 38-39 %.  Adding convective syngas coolers to recover additional heat as steam is also shown in Figure 3.  It can increase the generating efficiency to the 39-40 % range.  Existing IGCC demonstration units, which employ different practical combinations of these options, operate at generating efficiencies from 35.5 % (Polk) to 40 % (HHV) (Wabash, U. S. & Puertolanno, Spain).  IGCC is not yet mature, and there is still potential for efficiency gain.  However, commercial IGCC generating efficiency is unlikely to exceed that of ultra-supercritical PC in the intermediate time frame.  The design/engineering firms and the power industry need to gain experience with IGCC to develop better designs and achieve improved, more reliable operation.  Furthermore, gasifier designs for lower rank coals (subbituminous coal and lignite) are not well established, and costs seem to be relatively significantly higher for these coals than for PC units.  

 

An IGCC unit with radiant and convective syngas coolers using Illinois #6 coal, operating at 38% efficiency, and achieving high levels of criteria emissions control produces electricity for about 5.1 ¢/kW_e-h (Table 2) or about  0.3 ¢/kW_e-h higher than a supercritical PC [2, 3].  IGCC would not be the choice based on COE alone, independent of gasifier availability concerns.  Requiring high levels of mercury removal, reducing criteria pollutants by one half from the very low levels that we are already considering and including the cost of emissions credits and offsets increases the COE for the PC, narrowing the gap, but does not suggest a shift in technology choice based on COE in the absence of  CO₂ capture.  However, IGCC has the potential for order-of-magnitude criteria emissions reductions, 99.5+ % levels of mercury and other toxic metals removal, lower water consumption, and highly stabilized solid waste production.  These may become a larger factor in the future.  Achieving these order-of-magnitude criteria emissions reductions is expected to increase IGCC COE, but this increase is not expected to be large.  Companies considering construction of a new coal-based generating facility need to bring all these considerations into their forward pricing scenarios to help frame the decision of which technology to build.  CO₂ will probably be an added consideration shortly.

 

CO₂ Capture:  CO₂ capture will add significantly to the COE, independent of which approach is taken.  Today, CO₂ capture would appear to change the choice of technology in favor of IGCC for high rank coals.   For lower rank coals this choice may not be so clear, particularly as the PC CO₂ capture technology improves.  Thus, it is too early to declare IGCC the winner for all situations at this time.  History teaches us that one single technology is almost never the winner in every situation.  The options are: 

·        Capture the CO₂ from PC unit flue gas.  In this case, the CO₂ is at a low concentration and low partial pressure because of the large amount of nitrogen from the combustion air.  To capture and recover the CO₂  using today’s amine (MEA) technology requires a lot of energy.   Energy is also required to compress the CO₂ to a supercritical liquid.  This large energy consumption reduces plant electricity output by almost 25% and reduces generating efficiency by about 9 percentage points.  The added capital and the efficiency reduction increase the COE by about 60% or about 3.0 ¢/kW_e-h to about 7.7 ¢/kW_e-h[1] (Table 2).   In this situation a marked reduction in the CO₂ capture and recovery energy would have a significant impact on PC capture economics.  Focused research on this issue is clearly warranted.

·        Combust coal with oxygen( Oxy-fuel combustion) to reduce the amount of nitrogen in the flue gas. This allows the flue gas to be compressed directly liquefying the CO₂ without a costly separation step first, reducing energy consumption.  However, the technology requires the addition of an air separation unit which consumes significant energy substantially offsetting the energy gains achieved by eliminating the CO₂ separation step.  This technology is in early development stage, is advancing well, and at this point appears to hold significant potential for both new-build capture plants and for the retrofitting existing PC plants.  The estimated COE for oxy-fuel combustion is about 7.0 ¢/kW_e-h[1], includes compression to supercritical liquid, but not transport or sequestration.  This is about 0.7 ¢/kW_e-h less than for air-blown PC combustion with capture.  The technology requires further development and demonstration along with detailed design studies to allow effective evaluation of its cost and commercial potential.

·        Use IGCC, shift the syngas to hydrogen, and capture the CO₂  before combustion in the gas turbine.  IGCC should give the lowest COE increase for CO₂ capture because the CO₂ is at high concentration and high partial pressure, and this is what design studies show.  The needed technologies are all commercial in refineries and natural gas processing plants, although they have never been fully integrated on the scale that it will need to be applied here.   For Illinois #6 coal, the estimated COE is 6.5 ¢/kW_e-h [1, 2] which is a 1.4 ¢/kW_e-h increase over non-capture IGCC and is about 1.2 ¢/kW_e-h less than supercritical PC with capture.  Oxy-fuel combustion falls in between these two.  However, an IGCC unit designed for power generation without CO₂ capture is significantly different from one designed for power generation with CO₂ capture.  Retrofitting the former to a capture unit is not straightforwardly simple.

 

Lower Rank Coals:  As Figure 3 shows, moving from bituminous coal to sub-bituminous coal and to lignite results in an increase in the capital cost for a PC plant and a decrease the generating efficiency (increased heat rate).  However, for IGCC, these trends are significantly larger, such that currently-demonstrated IGCC technologies become more substantially disadvantaged relative to PC  for subbituminous coals and lignite without CO₂ capture, and their advantage with CO₂ capture is eroded somewhat.  Over half of the U.S. recoverable coal reserve is either subbituminous coal or lignite.  Thus, there is a substantial need for improved IGCC technology performance on lignite, other low rank coals, and biomass.  Options include, but are not limited to, improved dry-feed injection into the gasifier, coal drying, fluid transport reactors and other gasifier configurations.  Development should be at the PDU scale before moving to demonstration.    

 

Thus, when CO₂ capture is considered, the differences among IGCC, oxy-fuel PC and air-blown PC become significantly less than discussed above for bituminous coal..  In this situation all three of the technologies with CO₂ capture must be considered to be in the early stages of development, and it is simply too early to select one of these technologies as the winner vs. the others

 

Capture and compression of CO₂ to a supercritical liquid-like fluid was considered above.  Next, CO₂ transport by pipeline and injection for geologic sequestration are considered.  For more details on the geological aspects of sequestration, refer to the recent testimony of Dr. Julio Friedmann before the House Energy Committee, Energy and Air Quality Sub-committee Hearing, March 6, 2007[4] and the recent MIT Coal Report[1]. 

 

The good news is that the U.S. appears to have enough geological storage capacity to deploy CO₂ Capture and Sequestration (CCS) at a large scale for a long time.  The best projected storage sites are deep saline aquifers which can hold large volumes of CO₂.  Further, many of these potential geologic storage areas are under sites with large coal-fired coal plants and where additional coal plants are expected to be built.  This suggests that transporting CO₂ long distances, via pipeline will not be required, but that sequestration will be within a reasonable distance from a power plant capturing it.   Further, pipeline transport of CO₂ ^­ is well established; there are about 3,000 miles of  dedicated CO₂ pipelines used for commercial CO₂-EOR projects today in the U.S.  The cost of transport is also well understood and predictable.

 

Figure 4 illustrates what a potential CCS power plant project, with appropriate siting might look like.  For a good reservoir the radius around the plant  for sequestration may be less than 25 miles.  Longer transport distances to use CO₂ for EOR may occur in some cases, but because of the scale of CCS, it is expected to be a relatively small contribution to CO₂ sequestration, although the oil recovered from CO₂-EOR would add value to the project, offsetting some of the cost.

 

Today, there are three commercial projects using CO₂ storage (Sleipner in Norway, In Salah in Algeria, and Weyburn in Canada) each injecting over a million tonnes of CO₂  per year.  Sleipner has been injecting CO₂ into a deep saline aquifer under the North Sea for seven years.  Other projects are planned, including FutureGEN.

 

Although there are a large range of questions related to sequestration, they all appear to be resolvable with the appropriate work.  Importantly, there do not appear to be any irresolvable open technical issues related to geologic CO₂ sequestration.  In fact, it appears that geologic CO₂ sequestration is likely to be safe, effective, and competitive with other options on an economic basis. CCS is actionable almost immediately and can be sustained for many years while our energy base undergoes transition to new carbon-free technologies.  CCS is one method of reducing CO₂ emissions growth from coal-based power generation or even reducing total coal-based CO₂ emissions over time while maintaining the contribution of coal, a cheap, domestic energy source, can make in providing a substantial portion of our base-load power.

 

Table 3 summarizes estimated costs for CCS as applied to Illinois #6 coal-based power generation.  Costs are given in $ per tonne of CO₂ and in ¢/kW_e-h.  The capture and compression costs vary with coal type and with generating technology.  When they are added to the COE generation without CO₂ capture, the result is the COE for generation with CO₂ capture.  The higher capture cost for PC generation is evident, compared with IGCC. 

 

The cost of transport and injection will vary with site (location) and with reservoir properties.  Transport costs for the configuration in Figure 5 could be from less than a $ per tonne to several $ per tonne; $2/tonne was chosen.  Estimated sequestration costs including drilling the needed wells and the CO₂  injection operation range from $5 to $8 per tonne CO₂; $7/tonne was chosen.  The table shows how these costs translate to ¢/kW_e-h, assuming the same site (Figure 5).  PC transport and sequestratrion costs are marginally higher because more CO₂ is involved.  However, in both cases the transport and sequestration cost is less than 0.9 ¢/kW_e-h.  In overview, for PC generation with Illinois #6 coal the cost of CCS is about 3.8 ¢/kW_e-h; for IGCC the cost is about 2.3 ¢/kW_e-h.  Each step in CCS adds cost, but there are no economic show stoppers present.   For IGCC, CCS increases the bus bar cost of electricity by about 50%.   These costs will most likely come down significantly when CCS begins to become practiced industrially.  The innovative spirit of industrial practitioners and competitive pressures will bring a lot of innovation to every step in CCS.  However, this will not happen until there is a real need to practice it commercially.  It is important to note that to achieve today’s best emissions performance (99.9+% PM reduction,  99.4+% SO_x reduction and 95+% NO_x reduction) adds about 1 ¢/kW_e-h to the cost of electricity generation with no emissions control.  This area has seen a tremendous improvement in performance and in cost reductions since these technologies began to be applied.  The same can be expected for CCS.  This area offers the U.S. a chance to develop technologies that can be marketed to the rest of the world.

 

The remaining issue with respect to CCS is the establishment of a monitoring, regulatory, legal, and permitting framework under which this can  be done in a business-like context.  This can be done along with demonstrating the full-scale, integrated operation of CCS.  This will require an effective Research, Development and Demonstration program aggressively applied to 3 -4 demonstration projects.  These projects should apply different CO₂ generation and capture technologies and involve sequestration of CO₂ in different geologies at the rate of 1 million tonnes CO₂ per year for several years.   

 

Considering CO₂ capture and sequestration from coal-based power generation, there are no apparent irresolvable technical problems in the entire CCS chain from coal-in to power-out and CO₂ in geologic storage.  There do not appear to be any economic show stoppers in the chain either, although at the current time it appears that applying CO₂ capture and sequestration will increase the bus bar cost of electricity by about 50 %.  Today, this would put coal-based power generation with extremely low air emissions (99.9+ % reductions) and 90+ % CO₂ emissions reduction in the same cost range of wind power (range 6-10 ¢/kW_e-h in the U.S.). However, to make CCS an accepted reality that can be smoothly applied, it is necessary to demonstrate the integrated CCS system for the major generation technologies with CO₂ sequestration in several different geologies.  This requires three or four major demonstration projects in the U.S. combined with appropriate R&D to support them.   These need to be moved forward aggressively.

 

With respect to the generation and capture part of the CCS chain, the technology systems to capture CO₂ from coal-based power production are all available, but they require further development and integrated demonstration.  Of the three competing systems (PC with CO₂ recovery from flue gas, Oxy-fuel combustion with flue gas direct compression, and IGCC with pre-combustion CO₂ capture) it is too early to choose winners because it is not possible to predict how technology development and commercial innovation may evolve.  Further, one technology system may be well suited for bituminous coals, whereas another may apply best to low rank coals and lignite.

 

With respect to sequestration, there is enough technical knowledge today to select safe and effective storage sites for large volumes of CO₂ storage over extended time periods.  However, national deployment of commercial CCS involves technical challenges and concerns due to the operational scale that is required.  The aggressive research, development, and demonstration program recommended here could resolve both the technical and legal issues within 10 years and provide the foundation for a legal and regulatory framework to protect the public without undue burden to industry.

 

In the program recommended above the generation and capture, and the sequestration demonstration components should be integrated together as much as possible to facilitate learning for actual CCS as it will need to be applied commercially.  This program could be viewed as an insurance policy that the U.S. is investing in so that the technologies and legal/permitting framework are available when needed.  Further, as this moves into commercial practice it is expected that innovations and cost reductions will occur. Enabling CCS is critical to the use our domestic coal supply in an environmentally positive manner, as we will need to do.   Establishing a commercial, innovative CCS technology base in the U.S. should provide marketing opportunities to the rest of the world.

 

Thank you again for the opportunity to present this material to you and your committee.  We face many energy challenges in the future, and I firmly believe CCS will help us meet them.

 

 

 

 

 

Citations and Notes

 

1.         MIT, The Future of Coal; Options in a Carbon-Constrained World. 2007, MIT: Cambridge.

2.         Dalton, S., The Future of Coal Generation, in EEI Energy Supply Executive Advisory Committee. 2004.

3.         NCC, Opportunities to Expedite the Construction of New Coal-Based Power Plants. 2004, National Coal Council.

4.         Friedmann, J., Technical Feasibility of Rapid Deployment of Geological Carbon Sequestration, in House Energy and Commerce Committee, Energy and Air Quality Sub-Committee. 2007: Washington, DC.