By Steve Blankinship, Associate Editor
Only a few years ago, saying that a coal plant was carbon capture ready was a somewhat ill-defined statement at best. To some, it meant little more than providing space to make room for whatever form of capture might eventually be mandated or adopted.
But in today’s political and regulatory environment, the term must carry a far more detailed meaning. In August, a panel of seven power industry experts conducted a Webcast at COAL-GEN to discuss the true meaning of carbon capture ready and to offer details on the range of approaches and technologies being developed.
(Listen to the entire Webcast “The True Meaning of Carbon Capture” and view all the visuals in the presentation at the Power Engineering web site at www.power-eng.com.)
Panel moderator Ram Narula, vice president and chief technology officer of Bechtel, said that the panel of seven industry experts collectively “had more than 200 years experience inhaling and exhaling CO2 every day” and called the continued use of coal while capturing and containing CO2 the “mother of all challenges.”
Kyle Nelson, vice president of power production for Sunflower Electric Cooperative in Kansas reviewed Sunflower’s plan to build two 700 MW supercritical coal units at the site of an existing 360 MW unit. The expansion has been blocked by Kansas Governor Kathleen Sebelius and other state officials primarily over carbon dioxide emissions. That makes Holcomb the first coal plant to be rejected solely on the grounds that it will emit CO2. “That’s why it’s important to try to define and quantify what carbon capture really means,” said Nelson.
Justin Zachary, senior principal engineer for Bechtel, said uncertainty is a major factor, particularly when it comes to possible legislation and the scope of a carbon capture mandate. “Legislation is certain but not imminent,” he said. “So how much time is there and how does that affect our thinking? No one wants to get stranded with a technology that is obsolete.”
Zachary said developers must choose a technology that has the flexibility to accommodate future developments. Adding carbon capture, he said, will generally require an additional plant space of about 500,000 square feet. And every part of the plant will be impacted by the additional equipment that will be added later.
“You may well need an additional cooling tower to accommodate the additional load for the compression of the CO2,” he said. “This is a really an additional plant on top of the one you have.”
Robert Hilton, vice president and environmental marketing director for Alstom Power, said his company has active development programs underway in post-combustion, oxy-combustion and pre-combustion capture, focusing on commercialization in 2013 or 2014.
Capture technologies are not currently commercial, a factor that needs to be considered in legislation, he said. Alstom’s chilled ammonia process is now in operation at We Energies’ Pleasant Prairie plant in Wisconsin and (at the time of his COAL-GEN presentation) had logged 500 hours of operation at a scale of around 5 MW. The next phase with be at AEP’s Mountaineer plant in West Virginia that will scale up to about 30 MW. Tests there will start in the fall of 2009 with about 200,000 tons of CO2 slated for storage in one of several sequestration sites being operated by regional partnerships.
That will be followed by a commercial-scale project at AEP’s Northeastern plant in Oklahoma. Plans call for the project to store about 1.2 million tons of CO2 and is expected to start operating in 2013. The chilled ammonia process will also be tested at escalating scales in Sweden, Norway and Canada. Alstom is also moving ahead with testing of advanced amines and oxy-firing in the United States, Germany and France.
Hilton said the chilled ammonia process, while complex, uses heat from all sources and therefore has a relatively low steam demand, typically much lower than with amines. If it proves successful, he said, it will take just 10 to 20 percent the amount of steam as an amine process. He said attention must be concentrated initially on post-combustion technologies, such as chilled ammonia, but that all approaches are retrofittable.
“There’s no way we can just build new plants to capture,” he said. “We have to be able to add it to existing ones.”
Lionel Kambeitz, chairman and CEO of Canada-based HTC, discussed his company’s amine post-combustion approach. Amine post-combustion carbon capture technology is well-established and perhaps more reofittable than any other approach. “There is a great deal of technical certifiablity for amine capture because the chemical, oil and gas industries have used it for many decades,” Kanbeitz said. “We have passed the environmental and operational risk threshold on amine.”
Although traditional amines produced high parasitic loads, new amines have lowered the power drain. “We have developed a system that reduces steam consumption (parasitic load loss) another 30 percent compared to old amine systems,” he said. HTC’s Purenergy CCS 1000 can capture 1,000 tons of CO2/day and up to 3,000 tons/day is needed. The product is ideally suited for enhanced oil recovery (EOR).
EOR is critical, he said, because the U.S. Department of Energy has estimated that some 46 billion barrels of oil need CO2 to be produced. Kambeitz said that in North America, particularly in Canada’s western sedimentary region, a ton of CO2 will produce three to seven barrels of oil.
Denny McDonald, technical fellow for Babcock & Wilcox, said several pre-and post-combustion approaches are underway. He cautioned that advances are occurring at such a rate that premature selection may affect future plant requirements. B&W is involved in both oxy-combustion and post-combustion approaches. The company is performance testing various solvents and chemical looping approaches and has examined various configurations and integration options. “We plan to test on a 100 MW plant that will capture a million tons of carbon per year,” McDonald said. Retrofitting newer units, which represent about 50 percent of the existing coal fleet, is likely the most viable approach.
McDonald offered shopping lists of needs and considerations for various capture approaches. Those include SOX removal; particulate removal; mercury removal; space for an air separation unit; compression/purification unit; moisture removal; sufficient space for mixing oxygen in flues, cooling water and water treatment systems; provision for high plant power load; suitable CO2 storage site or market nearby; provision for high LP steam requirement (LP turbine and FW heaters or aux boiler); and cooling water/water treatment systems.
He said that capture ready design is possible today and that the greatest considerations are land and infrastructure. “Oxy combustion has less impact than post-combustion and requires no changes to the steam turbine,” he said. Post-combustion can be retrofitted to treat part of the plant emissions, while oxy- combustion treats all. In general, the ability to avoid stranded asset depends on the installation cost and value of CO2, he said.
Dr. Hermann Kremer, director of business development, emerging technologies for fossil power generation at Siemens, said technologies are being developed to help customers cope with the anticipated, but still unpredictable, CCS market. Siemens’ current focus is in the advanced amine post combustion approach.
He said a capture ready plant is one which can include CO2 capture when the necessary regulatory or economic drivers are in place. The aim of building plants that are capture ready is to reduce the risk of stranded assets or carbon lock-in. “Developers of capture ready plants should take responsibility for ensuring that all known factors in their control that would prevent the installation and operation of CO2 capture have been eliminated,” he said.
This might include, he said, a study of options for CO2 capture retrofit and potential pre-investments; inclusion of sufficient space and access for the additional facilities; and identification of reasonable routes to store CO2. Competent authorities involved in permitting power plants should be provided with sufficient information to be able to judge whether the developer has met these criteria. Among his other points: Specifying mandatory CCS requirements should be kept to a minimum and a capture-ready IGCC has only limited rationale due to high initial investment costs in overall plant. He said, however, that a coal-gas-ready substitute natural gas combined cycle plant might be attractive.
Dr. Norm Shilling, carbon leader, GE Gasification, said it is essential that any decision made today is done with the highest confidence that it will still make sense when CCS is mandated, and remain a good decision for 40 years in the future. He said that carbon capture features must be designed to accommodate later additions without a major cost penalty. “There should be no need to scrap anything; certainly not a gas turbine,” he said.
GE has drawn up a list of criteria for helping make the right decision on technology. Among them are:
- That all processes and components are in commercial application today and components should be at, or within accepted engineering limits of scale-up
- Incremental investment is needed only for addition of components and process
- Site utilities, such as once-through and makeup water are sufficient for CCS
- CO2 quality must be suitable for sequestration
- Deferring retrofit will not incur significant penalty in avoided cost of carbon.