By Steve Blankinship, Associate Editor
Carbon capture may be the future, so technology development and testing are underway today.
Unless something dramatic happens to alter the political landscape within the next few years, it seems all but certain that coal-fired power plants will someday have to capture and sequester carbon dioxide (CO2). Power Engineering magazine’s March cover story, “The Evolution of Carbon Capture Technology (Part 1),” detailed the origins and advancement of some of the most promising carbon capture approaches.
Part 2 focuses on the status of pilot programs underway by original equipment manufacturers, utilities, research institutions and government agencies to demonstrate various approaches to carbon capture and sequestration (CCS). In addition to the commercial projects, two dozen pre-combustion, oxy-firing and post-combustion carbon capture research projects are underway, funded by the U.S. Department of Energy (Tables 1 and 2).
One approach for capturing CO2–chilled ammonia–is being pursued by Alstom and is targeted for limited commercialization by 2011 and full commercialization by 2015. Although the approach could be incorporated into new plant designs, a big advantage (as with all post-combustion approaches) is that it can be retrofitted onto existing coal plants. It also could require considerably less energy than traditional amine processes.
In February, Alstom in collaboration with the Electric Power Research Institute (EPRI) began field testing its chilled ammonia process at a 1.7 MWe test site at We Energies’ Pleasant Prairie Power Plant in Wisconsin. The field test is expected to run 12 to 18 months. EPRI will collect all emissions and performance data and will also prepare an economic evaluation of the process once the test is completed. The small amount of CO2 captured during the test (equal to 15,000 to 18,000 tons/year) will be released to the atmosphere.
A later test phase will occur at AEP’s Mountaineer plant in West Virginia, expected to be in operation in 2010. That phase will capture about 90 percent of the CO2 from 15 MWe of the plant’s output (equal to at least 100,000 tons of CO2/yr). In this case, all captured CO2 will be sequestered near the power plant site. AEP and the Battelle research institute will operate the sequestration aspect of the test, with possible DOE participation. The pilot is expected to operate about five years.
The third step in the planned process will be to apply the CCS approach commercially at AEP’s Northeastern Station at Oologah, Okla. There, CO2 will be captured from about 150 MWe of generation (equal to about 1 million tons of CO2/year) and placed into the ground nearby to bolster enhanced oil recovery, a primary economic use of captured CO2. That project is expected to be commercial in 2011.
In a related development, Alstom and Canadian power producer TransAlta announced last month plans to develop a large-scale CCS facility in Alberta, Canada, using the chilled ammonia process. The plan calls for retrofitting chilled ammonia technology at one of TransAlta’s coal-fired generating stations west of Edmonton and reducing CO2 emissions by one million tons a year. The first phase is aimed at advancing and improving understanding of CCS and will begin this year with engineering, stakeholder relations and regulatory work. That and subsequent phases are subject to partner and government funding over the next five years with testing expected to commence in 2012.
Powerspan is pursuing an ammonia-based carbon capture approach that, unlike the Alstom process, doesn’t first chill the ammonia. The company’s so-called ECO2 post-combustion regenerative process evolved from its ammonia-based multi-pollutant capture solution as well as CO2 capture research conducted by DOE’s National Energy Technology Laboratory. The technology is suitable for retrofit to existing coal plants as well as for new plants. The regenerative process may be integrated with Powerspan’s electro-catalytic oxidation process for multi-pollutant control of sulfur dioxide, nitrogen oxides, mercury and fine particulate matter.
In the Powerspan approach, CO2 capture takes place after NOX, SO2, mercury and fine particulate matter are captured. Following CO2 capture, the ammonia-based solution is regenerated to release CO2 and ammonia. The ammonia is recovered and sent back to the scrubbing process and the CO2 is in a state ready for geologic storage. Ammonia is not consumed in the scrubbing process and no separate by-product is created. The process can be applied both to existing and new coal-fired power plants and may be particularly advantageous for sites where ammonia-based scrubbing of power plant emissions is used.
The Powerspan process will be applied to a 125 MW slip stream from a 600 MW unit at NRG Energy’s WA Parish plant in Sugar Land, Texas. The system will capture and sequester 90 percent of the carbon in the 125 MW slip stream–equal to about one million tons of CO2 annually. The captured CO2 will be used in enhanced oil field recovery operations in the Houston area. The commercial demonstration is expected to be operational in 2012.
At AEP’s Mountaineer plant in W. Va., 90 percent of the CO2 from 15 MWe of the plant’s output will be captured and sequestered on site. Photo courtesy AEP.
The process will also be commercially demonstrated at Basin Electric Power Cooperative’s Antelope Valley Station near Beulah, N.D. There, roughly one million tons of CO2 will be captured annually from the 120 MW slipstream project. The captured CO2 will be fed into an existing compression and pipeline system owned by Basin Electric’s wholly owned subsidiary, Dakota Gasification Co.
The ECO2 process is also being pilot-tested this year in a 1 MW slip stream at FirstEnergy Corp.’s R.E. Burger plant in Shadyside, Ohio.
Siemens and German-based utility E.ON have agreed to cooperate on a new post-combustion solvent approach that is said to be environmentally harmless and biodegradable and that has no emissions. A pilot installation on an E.ON power plant site in Germany is slated to be operational by 2010. Further developments are planned through 2014 aimed at having the solvent approach ready for commercial deployment by 2020. That date was set by European Union countries as a target for when carbon capture from coal plants will be required.
Traditional approaches to separating CO2 from fossil fuels got their start with industrial processes and the need to separate CO2 from natural gas. These were amine based, meaning they used amines, which are organic compounds whose key element is nitrogen and whose atomic structure resembles ammonia.
Traditional amine separation is not suited, however, to treating the large amounts of CO2 that would have to be captured from coal plants to dramatically reduce their carbon production. That is largely because the low efficiency of traditional amine approaches makes the cost of coal-fired generation prohibitively expensive. That factor has pushed boiler and combustion turbine manufacturers, among others, to seek better ways of capturing carbon. Advanced amine systems are lowering parasitic energy consumption as well, driven by the same need to reduce carbon from fossil fuel consumption. Amine advances have been so dramatic that data suggest new amines may be able to achieve cost efficiencies comparable to ammonia.
Mitsubishi Heavy Industries (MHI) has refined a post-combustion flue gas CO2 recovery system called KM-CDR (Kansai Mitsubishi carbon dioxide recovery). The process produces a 99.9 percent pure CO2 stream and has been commercially available to capture CO2 emissions from natural gas fired applications for several years. To develop and adapt the KM-CDR system for coal fired gas streams, MHI is operating a 10 metric ton/day demonstration facility in Japan.
Powerspan’s ammonia process will be demonstrated at Basin Electric Power Cooperative’s Antelope Valley Station where one million tons of CO2 will be captured annually from a 120 MW slipstream project.
Although the company’s experience to date has been largely in the chemical plant sector, Mitsubishi said the process can be applied to power plants as well. A Mitsubishi spokesman said the company will announce further details soon.
Fluor offers its so-called Econamine FG Plus amine process for removing CO2 from flue gas, an approach that has been demonstrated at some two dozen locations over the past 20 years. The solvent formulation is designed to recover carbon dioxide from low oxygen-containing streams that are at near-atmospheric pressure, such as burner flue gas streams. The process offers a post-combustion CO2 capture option that may be retrofitted to existing facilities.
Fluor is one of the only technology vendors with a long-term commercial operating experience in CO2 recovery from flue gas with a very high oxygen concentration. The Econamine FG Plus process removes 85 to 90 percent of CO2 contained in flue gas. Econamine FG Plus has been used commercially since 1989 on fossil fuel-fired boilers and steam reformers. Fluor also has done preliminary designs for power plants up to 1,000 MW. Process improvements include optimization of tower designs, reclaiming and improved solvent formulations. An installation in Bellingham, Mass., produced up to 330 metric tons per day of food grade carbon dioxide over 15 years of operation.
Fluor has improved the technology to operate with significantly lower capital and operating costs. Econamine FG Plus can also handle varying amounts of SOX, NOX and particulate contents in the fuel gas.
One of the most dramatic recent announcements for a commercial coal plant that would capture and sequester CO2 came in February when Omaha, Neb.-based Tenaska proposed building a new pulverized coal plant in west Texas that would capture and sequester CO2. Tenaska is considering using amine carbon capture technology at its proposed Trailblazer Energy Center near Sweetwater, Texas. The $3 billion, 600 MW supercritical coal plant would capture up to 90 percent of the CO2 produced. The captured CO2 would then be injected into West Texas oil deposits to boost Permian Basin oil production.
Oxy combustion (often called oxy-firing) introduces pure oxygen into the boiler instead of ambient air, thus eliminating nitrogen. Oxy combustion produces a flue gas that is mostly CO2 and water, making it easier to produce a highly pure CO2 stream.
In theory, oxy combustion is retrofittable to existing coal plants. It would require the addition of oxygen system, meaning conventional air separation, compression and purification. Oxy-firing might also be incorporated into an existing coal plant by replacing the existing boiler with a new one. In general terms, oxy combustion lends itself best to new construction or complete repowering.
All major boiler OEMs are looking into oxy firing. Alstom built the combustor for a 30 MW (thermal) test underway with European utility Vattenfall scheduled for startup this summer. A licensee of Babcock & Wilcox (B&W) built the flue gas desulfurization system.
In December 2007, B&W burned coal in full oxygen combustion mode at a 30 MW (thermal) demonstration at its Ohio test facility. The test operated in full oxygen-coal combustion mode for more than 250 hours burning in excess of 500 tons of bituminous coal. B&W will continue with oxy-fired research at its research center through this summer, also testing sub-bituminous, lignite and Powder River Basin coals. Project data will form the foundation to design a large-scale reference plant to implement the technology at commercial scale.
About half a dozen additional oxy-firing tests are being conducted at non-utility facilities. These include projects ranging in size from 1 MWth up to 20 MWth. An equal number of sorbent and amine studies are also underway at chemical and industrial facilities.
In April, Southern California Edison and the California Public Utilities Commission announced that SCE and the Southwest Regional Partnership for Carbon Sequestration will conduct a feasibility study to examine building a 600 MW coal-based hydrogen power plant using integrated gasification combined cycle (IGCC). The plant would emit 10 percent of the carbon released by an IGCC plant without carbon capture. In October, the U.S. DOE announced a grant of more than $65 million to SCE and other partnership participants.
The technology to be evaluated would gasify coal to produce hydrogen and carbon monoxide. The hydrogen would be used to fuel a combined cycle power plant and the carbon monoxide would be removed prior to combustion and sequestered underground. The process would capture as much as 90 percent of the carbon dioxide in the coal, the highest level targeted by a U.S. advanced coal initiative.
A handful of pre-combustion test projects also are proposed, some of which would be predicated on IGCC facilities. All are projected for the 2011 through 2014 timeframe.