David W. South, Technology & Market Solutions, LLC, USA
Approximately 26 gigatonnes (Gt) of carbon dioxide (CO2) are annually emitted from existing fossil fuel sources worldwide. It has been estimated that unconstrained economic and associated CO2 emissions growth during the next century could cumulatively add 9000 Gt of CO2 to the atmosphere.
The Kyoto Protocol called for cumulative greenhouse gas emissions during the next 100 years to be capped at between 2600 and 4600 Gt of CO2, in order – according to the United Nations Framework Convention on Climate Change (UNFCCC) – to stabilize CO2 concentrations in the atmosphere “at a level that would prevent dangerous anthropogenic interference,” with the climate system. But there is no silver bullet to reduce cumulative CO2 emissions growth by the targeted 50-70 per cent; all sources and options must make a contribution to make this level of emissions reduction a reality.
Since fossil fuels are the predominant source of CO2 emissions, there is considerable attention on possible mitigation options. These options include:
- Improved combustion & conversion efficiency
- Carbon capture and storage (CCS)
- Substitution to lower or zero-carbon fuels
- Carbon offsets (e.g. forest sequestration)
While each of these options exists to some extent today, none of them are equally applicable or cost-effective at each coal burning power plant.
Moreover, improved efficiency and carbon offsets are short-term solutions that “buy time” for a longer term, more permanent mitigation measure to become cost-effective.
Substitution to a lower or zero-carbon fuel source can reduce the rate of increase in or displace fossil fuel emissions, but often these sources cannot operate as baseload or distributed generation; thus, they may not be direct substitutes for fossil fuels.
The exceptions to this substitute condition are nuclear power and hydropower which to date have been problematic for adding new capacity in numerous countries, not least due to politics. Some of these new capacity restrictions are being revisited because of the need for baseload power and recognition that their “negative attributes” (i.e. long-term waste disposal and land use impacts, respectively) may be more manageable than the uncertainties and risks associated with CO2 emissions and global climate change.
There are various means to capture and concentrate CO2 emitted from new coal based power plants. The National Energy Technology Laboratory (NETL) conducted a study last year – Cost and Performance Comparison of Fossil Fuel Energy Power Plants – that examined the state of development and economics of several CO2 mitigation options on new subcritical and supercritical systems. They included: amine scrubbing (Figure 1), ammonia scrubbing, solid sorbents and CO2 membranes.
The NETL analysis concluded that the major CO2 capture challenges on new pulverized coal (PC) boilers were:
- Dilute flue gas (10-14 per cent CO2)
- Low pressure CO2
- Flow rate (1.5 million standard cubic feet per minute)
- Volume of CO2 processed (17 000 tonnes CO2day removed)
- Large parasitic load (steam + CO2compression)
Adding an advanced amine scrubber to either a new subcritical or supercritical system for 90 per cent CO2 removal is both energy-intensive and costly. NETL estimated that net efficiency (on either system) would be reduced by approximately 12 percentage points, and the cost of electricity (COE) would increase by approximately five cents/kWh (6.6 cents/kWh to 11cents/kWh; $2007). The average CO2 mitigation cost would be $41/tonne of CO2 removed; more than twice the current European Union Emissions Trading System (EU ETS) market price.
One option to improve the efficiency and reduce the mitigation cost for new PC units with CO2 capture is through oxyfuel combustion. NETL examined various oxyfuel combustion configurations in a report released in March 2007, entitled Avanced Pulverized Coal Oxyfuel Combustion.
Figure 2: Percentage increase in cost of electricity with alternative oxyfuel combustion options
Source: National Energy Technology Laboratory’s Advanced Pulverized Coal Oxyfuel Combustion report
The options assessed were: supercritical PC oxyfuel; ultra-supercritical PC oxyfuel; cryogenic and membrane oxygen; and co-sequestration (CO2/SOx). As depicted in Figure 2 above, the percentile increase in COE can be reduced substantially with CO2 capture options beyond conventional amine scrubbing.
Instead of combusting coal in a PC boiler, coal can be converted to a synthetic gas in an integrated gasification combined-cycle (IGCC) system. IGCC has several performance, efficiency and product configuration advantages relative to a PC system. With respect to CO2 capture these advantages are high pressure CO2, low volume syngas stream and CO2 produced at pressure.
Figure 3 illustrates where the three CO2 scrubbing components are inserted in a typical IGCC system – water gas shift, two-stage Selexol Process and CO2 compression. The gasifier design (dry feed versus slurry; quench versus heat exchanger) has a large influence on the water-gas shift requirement, steam turbine output and net plant efficiency. For example, NETL computed the following net plant efficiency effects with alternative gasifier types:
Figure 4 illustrates a cost comparison (prepared by NETL) of alternative gasifier systems with and without CO2 control systems. Depending on the gasifier, CO2 scrubbing costs (Selexol Process) add between $577/kW-$691/kW. The average COE without CO2 ranges from 7.5-8.1 cents/kWh, whereas with CO2 controls it ranges from 9.9-10.6 cents/kWh. The effect of CO2 controls increases the COE by between 27 per cent and 35 per cent, depending on the gasifier type. When translated into the average cost of CO2 mitigation, the cost is approximately $26/tonne of CO2 removed; a cost that is only slightly higher than recent CO2 prices on the EU ETS.
Several viable alternatives
There are a large number of alternative CO2 control techniques (and combinations of techniques) that could be used instead of the Selexol Process (used in Figure 4). Some of the techniques are commercially available, but have not yet been tested on full-scale IGCC systems, while several others still require research, development and demonstration.
NETL examined 13 alternative CO2 controls systems, which were predominantly based on gas separation membranes, and determined that while the Selexol Process increases COE by approximately 31 per cent these alternative systems would only increase COE by between eight and 28 per cent. Consequently, continued development of alternative CO2 scrubbing systems is necessary for IGCC system economics to improve and decrease the $/tonne of CO2 removed.
Retrofitting for future control
While inclusion of CO2 scrubbing systems on new power plants would reduce the increase in CO2 emissions relative to systems without controls, to have a signicant impact on total annual CO2 emissions released to the atmosphere, controls are also needed on existing fossil fuel sources.
Retrofit of CO2 scrubbing systems on existing power plants is more cost effective – cost to “retrofit” additional control equipment at an existing site is more expensive, as the negative efficiency effect is more significant because of lower original efficiency level. Overall the mitigation cost variance is much larger due to the differences in boiler types, plant configurations, existing pollution control equipment and so forth.
The decision to retrofit a CO2 scrubbing system on an existing plant is not only based on the CAPEX, COE and $/tonne of CO2 removed, but also on the remaining lifetime of the unit (for cost recovery), related maintenance costs, and the need for additional generation capacity at that location. Replacing the boiler island with a gasification system could be more economic, plus it would also add capacity, improve net energy efficiency and reduce the level and cost to control multiple emissions, i.e. SO2, NOx, PM, Hg, as well as CO2.
Other mitigation costs
CO2 capture and control at the fossil fuel source is only the first stage in the mitigation process. The CO2 must then be transported and stored (sequestered) to complete the process. Transport and storage do not generally create a technological challenge, but can be a logistic issue.
The CO2 capture at the fossil fuel source could be a significant distance from a potential customer e.g. enhanced oil recovery operation (EOR) or long-term repository such as an abandoned oil well, or aquifer.
These costs, together with numerous issues related to liability, long-term storage, ownership and so forth are currently being explored. For example, the Interstate Oil and Gas Compact Commission’s (IOGCC) Carbon Capture and Geological Storage Regulatory Task Force is about to release a study that outlines a CCS management framework that proposes a state-administered system benchmarked on protocols developed for CO2 EOR projects and oil/gas extraction and reservoir management.
In addition, the USA Department of Energy is co-funding the Regional Carbon Sequestration Partnerships, which have been working to characterize their region’s opportunities and existing infrastructure for carbon sequestration.
The seven regional partnerships are as follows: the West Coast Regional Carbon Sequestration Partnership, the Southwest Regional Partnership for Carbon Sequestration, the Northern Rockies and Great Plains Regional Carbon Sequestration Partnership, the Plains CO2 Reduction Partnership, the Midwest Geologic Sequestration Consortium, the Southeast Regional Carbon Sequestration Partnership and the Midwest Regional Carbon Sequestration Partnership
Ample storage space
It has been determined that there are more than 3900 Gt of CO2 storage capacity in the continental United States of America dispersed amongst 230 potential reservoirs. The challenge as indicated earlier is to transport the capture and compressed CO2 to an end-user or long-term repository.
The USA’s biggest CO2 sources (releasing >100 kt CO2/year ) have been identified and total 1715 (approximately 61 per cent are electric power plants). In total these sources emit 2.6 Gt/year1 .
Carbon capture and storage is not new. CO2 capture technologies have been used at refineries and other chemical processing plants; the USA has more than 3500 miles of high pressure CO2 pipelines in operation, and the transport and injection of (natural) CO2 for enhanced oil recovery (EOR) has been done for almost 30 years in Texas.
What is new is the potential regulatory requirement to capture and process larger volumes of more diffuse CO2 in flue gas or syngas streams at power plants, transport it longer distances, and then inject the CO2 into reservoirs that need to retain it indefinitely. None of these challenges are insurmountable; many technologies and techniques currently exist or are being commercialized.
Since there is no silver bullet to meet the United States’ energy needs without reliance on coal, advanced coal technologies coupled with CCS must be deployed to obtain commercial experience and determine their ultimate cost-effectiveness.
1. J. J. Dooley, On the Potential Large-Scale Commercial Deployment of Carbon Dioxide Capture and Storage Technologies, Joint Global Change Research Institute, Pacific Northwest National Laboratory, 2007.
David W. South is president of Technology & Market Solutions, LLC, which devises innovative solutions for clients challenged by or looking to exploit the interface between technologies, financial markets and regulatory requirements.