Air Pollution Control Equipment Services, Coal

The Evolution of Carbon Capture Technology Part 1

Issue 3 and Volume 112.

Technologies are being developed that hold the promise of meeting future carbon capture mandates. They won’t be cheap.

By: Steve Blankinship, Associate Editor

This is the first of a two-part series on CO2 capture technologies and projects. Part two will be published in the May issue of Power Engineering magazine.

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Free market forces are flexing their considerable muscle devising ways to capture carbon dioxide (CO2) from coal-fired power plants. Driving the search is the imperative to reduce the amount of CO2 these plants produce, thus allowing them to continue to generate the lion’s share of electricity in the United States and other countries. Coal plants are the largest producer of CO2, a greenhouse gas presumed to be a major contributor to climate change.

An array of initiatives is underway by power sector original equipment manufacturers many of whom are working closely with electric utilities, government and industry research institutions to capture carbon produced by coal plants.

These aggressive—and largely private sector—efforts have achieved such tangible results that they may have helped short-circuit one high-profile project: FutureGen. The U.S. private/public funded consortium was to have built a zero-emissions coal plant that would have captured and sequesterd CO2 while simultaneously providing various commercially viable byproducts. Citing rising costs and technological advances since FutureGen first was announced in 2003, U.S. Secretary of Energy Samuel Bodman said earlier this year that a restructured initiative will build commercial-scale integrated gasification combined cycle (IGCC) power plants and provide funding for the addition of carbon capture and storage (CCS) to multiple plants planned to become operational by 2015.

“It appears that FutureGen in the past several years has morphed into being a standard IGCC plant with 90 percent capture and storage,” said Kevin McCauley manager of strategic planning for Babcock & Wilcox (B&W). “But in the years since, that basic IGCC plant has become commercially available.” At least one commercial IGCC is going forward at Edwardsport, Ind., for Duke Energy using GE Energy’s 630 MW reference plant design.

Catch & Release

Some estimates place the commercial potential for captured carbon in the United States at 35 to 50 million tons a year. But that would barely make a dent in the estimated 6.5 billion tons of CO2 that would have to be sequestered each year if all coal plants captured all of the CO2 they produce.

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CO2 has been captured for use in various commercial and industrial processes for decades. The largest single reason to separate CO2 has been to remove it from natural gas that has been extracted from the ground. Removing the CO2 boosts the heating value, necessary before the gas is placed into transmission pipelines. CO2 removed during this process was simply released to the atmosphere.

Limited markets exist for commercially produced CO2. It is used, for example, to make carbonated drinks and for a few processes at refineries and other industrial facilities. It is also injected into oil wells to increase production from declining fields. This application, known as enhanced oil recovery (EOR), represents perhaps the single largest commercial market for CO2. Once injected into declining oil-bearing formations, the CO2 remains permanently sequestered from the atmosphere.

Traditional approaches to separating CO2 from natural gas and other gases were amine-based. Amines are organic compounds whose key chemical element is nitrogen and whose atomic structure resembles ammonia. But traditional amine separation is not well suited to dealing with the vast amount of CO2 that would have to captured to dramatically reduce the amount of carbon coal-fired power plants produce. The cost of amine, the energy required to regenerate it and its degradation by sulfur dioxide (SO2) would make the cost of coal-fired generation prohibitive. That factor has pushed boiler and combustion turbine manufacturers, among others, to seek better ways of capturing carbon.

A Cool Approach

One such approach—which involves the use of chilled ammonia—is being pursued exclusively by Alstom and targeted for commercialization in 2011. Although the approach could be incorporated into new plant designs, a major advantage—as with all post-combustion approaches—is that it can be retrofitted onto existing coal plants.

Bob Hilton, global business development director for Alstom, described the traditional amine CO2 capture approach and compared it to using chilled ammonia. “In an amine process you take the flue gas at about 130 F as it comes out of the power plant and run it through an absorber with an amine solution in it,” he said. The CO2 is absorbed in the amine, then sent to a regenerator where a substantial amount of steam is needed to boil off the CO2. “That’s where the very heavy power consumption comes in,” he said.

Chilled ammonia reduces the temperature of the flue gas to about 40 F. “There’s a couple of reasons we do that,” said Hilton. “We chill it because at low temperature you can form solids that can carry CO2. Also, at those temperatures, if there is any free ammonia in the system, it doesn’t smell like ammonia, which at room temperature has a very strong odor.”

In February, Alstom and EPRI began field testing this chilled ammonia process at a 5 MW test site at We Energies’ Pleasant Prairie plant in Wisconsin. “We don’t have to clean the flue gas coming in as you do with an amine system,” Hilton said. “With amine, anything in the flue gas (such as SO2 or SO3 ) reacts with the amine and destroys it. By chilling it, we go below the dew point and drop those pollutants out, so we don’t have to put in a bunch of equipment ahead of the amine system.”

Additional energy required to release CO2 from coal using chilled ammonia is much lower than with traditional amine. And because parasitic load is an even bigger cost issue for carbon capture than capital cost, the amount of energy consumed rises to singular importance. Parasitic load using amine systems could be 35 percent. That means a 600 MW coal plant would be reduced to less than 400 MW net output if it uses traditional amine CO2 separation.

Compression represents another significant parasitic load cost for carbon capture. Amine processes generate CO2 at ambient pressure. That means, depending on what a plant operator plans to do with the captured CO2, compression will have to increase from 15 psi to 1,500 or even 2,000 psi, said Hilton, a compression ratio of more than a 100:1. “The advantage with ammonia is that we actually regenerate at pressure at about 300 psi, so we only have to compress from 300 psi to 1,500 psi, meaning it’s just 5:1.” That saves as much as two compression stages, he said.

So although chilling the ammonia requires extra energy, the cost may be more than recovered through CO2 regeneration and in compression. Alstom believes chilled ammonia can reduce a power plant’s parasitic load for carbon capture to about 15 to 18 percent of the output it would have without capture. “That’s why we’re excited about it and why we have put the money into it,” said Hilton.

Alstom’s 5 MW field test at Pleasant Prairie is expected to run 12 to 18 months. The CO2 captured (15,000 to 18,000 tons a year) will be released to the atmosphere. The next test phase will be at AEP’s Mountaineer plant in West Virginia and is expected to be running in 2010. That phase will capture about 90 percent of the CO2 from 30 MW of the plant’s output. Unlike the Pleasant Prairie test, all captured CO2 will be sequestered near the Mountaineer power plant site. AEP and the Battelle research institute will operate the sequestration portion of the test as part of a U.S. Department of Energy regional sequestration partnership. That pilot is expected to last about five years.

The third step will be to apply the process commercially at AEP’s Northeastern Station at Oologah, Okla. There, CO2 will be captured from about 300 MW of generation (about 1.5 million tons of CO2 a year ) and used nearby for enhanced oil recovery.

Not Chillin’

Powerspan is pursuing an ammonia-based carbon capture approach that doesn’t chill the ammonia. The company’s ECO2 post-combustion regenerative process, which evolved from its ammonia-based multi-pollutant capture approach, will be applied to a 125 MW slip stream from a 600 MW unit at NRG’s W.A. Parish plant in Sugar Land, Texas. The installation will include a 125 MW ECO2 multi-pollutant control system that will reduce SO2 to 1 to 2 parts per million (ppm). The system will capture and sequester 90 percent of the carbon in the 125 MW slip stream—meaning about 1 million tons of CO2 annually. The captured CO2 will be used in enhanced oil recovery operations near Houston. The pilot is expected to be operational in 2012.

“NRG is perhaps the most aggressive power provider in the industry in deploying low-carbon solutions and we believe we have one of the most promising post-combustion carbon solutions,” said Frank Alix, Powerspan CEO. Powerspan’s technology doesn’t need to chill the flue gas, thus eliminating one element of cost, he said.

“One reason for chilling is handling ammonia vapor and we have a proprietary approach that we think provides an advantage in that regard,” he said. No odor exists because the emissions level is on the order of 1 to 3 ppm, which is below the level of detectable odor. “We also think CO2 absorption in our process will be quite a bit more rapid.” By that he means that the size of the absorber and the liquid flow required to absorb 90 percent of the CO2 will be “quite a bit less” than for chilled ammonia. “We could design the system to capture more than 90 percent of the CO2 but the market is asking for 90 percent and we think we can do that in a conventionally-sized absorber such as what you’d see for an SO2 system.”

Powerspan’s parasitic load evaluation (caused by the CO2 regeneration and compression process) totals about 15 percent. On the capital cost side, models indicate a range of $500 to $750/kW. “That’s an indicative estimate at this stage,” Alix said. “We have sized our components and added in balance-of-plant compressors and that’s the ballpark.”

Alix said several reasons exist for why an ammonia-based multi-pollutant system may be ideal for CO2 capture. “Our system gets you to ultra-low SO2 emissions needed to install a CO2 system. That’s because SO2 gets picked up by a CO2 capture system and forms heat-stable salts. You have to purge a waste stream out of the CO2 system for any SO2 you capture. So whether it’s an amine or ammonia system, you have to get SO2 levels very low before you capture CO2 to avoid a lot of costly purging and waste.” The ECO2 system removes about 99.8 percent of the SO2, or about 1 ppm. This relieves the necessity to do additional scrubbing to add CO2 capture. “With other systems, you will have to add additional scrubbing if you are going to capture carbon,” he said.

If ammonia-based carbon capture becomes the low-cost solution, there would be an advantage to having an ammonia scrubber up-front. And it extends beyond merely getting SO2 emissions to ultra-low levels. “It’s using the ammonia vapor when it comes off the CO2 process,” said Alix. “When you capture vapor from the CO2 scrubber, you have to treat the ammonia vapor as a waste or find another way to deal with it. We deal with ammonia vapor by feeding that dilute ammonia into our SO2 scrubber. That interaction improves the ultimate dollar per ton of CO2 capture.”

A Solvent Approach

Siemens and German-based utility E.ON have agreed to cooperate on a new post-combustion solvent approach that is said to be both environmentally harmless and biodegradable and results in zero emissions. A pilot installation at an E.ON power plant in Germany is expected to be operational by 2010. Further developments will follow until 2014. Plans call for having the approach ready for commercial deployment by 2020, the year in which carbon capture from coal plants will be required by the European Union.

“The disadvantages to most processes is you lose solvent and it is released to the atmosphere,” said Tobias Jockenhoevel of Siemens. “You also lose solvent when you compress.” Solvents currently are not very chemically stable and are degraded by oxygen. “Our solution has almost no losses of solvent to the atmosphere,” Jockenhoevel said. “Degradation is very low and we believe we can optimally integrate this to the power plant.”

Since the solvent is integral to the technology, Jockenhoevel was tight-lipped on what it exactly is. He did say it is purely a post-combustion approach and that the key is the solvent itself.

When it comes to cost, Jockenhoevel said Siemens will benchmark to the market and then atempt to beat it. “In the first year we will optimize the design and solvent measurement,” he said. “Then we will build the pilot unit at a power plant and operate it for about 18 months. We have already been testing it in our lab for about two years. Then we’ll build a bigger pilot at a European plant, probably in Germany. We are also open to other pilots elsewhere at larger scales.”

Amines Advancing

Advanced amine systems are lowering parasitic energy consumption, too, driven by the same need to reduce carbon from fossil fuel consumption. Major players in the amine arena include Mitsubishi Heavy Industries (MHI) and Fluor, which offers its Economine FG process. And in February, Alstom and Dow Chemical (one of the world’s largest amine producers) announced a joint development and commercialization agreement for advanced amine scrubbing technology to remove CO2 from low- pressure flue gases in coal-fired plants and other industries. Advances have been so dramatic that technology developers claim new amines can achieve cost efficiencies comparable to ammonia.

Mitsubishi began CO2 capture R&D efforts in 1990 and has since developed and 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.

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The approach can be applied to petrochemical, industrial or a power plant, said Steve Holton, senior marketing manager for MHI of America. “Our commercial experience has mainly been on the chemical side, but we do have experience in the power plant segment and we are working with both oil and gas and power plant segments in the U.S.” He said the company would announce details soon.

Removing CO2 from Natural Gas

While much of the focus on CO2 capture is on coal, natural gas-fired generation also produces CO2, albeit roughly half as much CO2 per kilowatt as coal. And with large numbers of natural gas plants again being built in the United States, CO2 generated by existing and future gas-fired plants will likely grow as an issue.

Both pre- and post-combustion capture technologies can be applied to natural gas. “Post-combustion CO2 capture on natural gas will have no dust in the flue gas,” Jockenhoevel said. It’s also somewhat easier to apply with natural gas, which means that when the company’s process is ready for coal, it also will be ready for natural gas.

“For pre-combustion on natural gas, instead of using a gasifier you use a reformer,” he said. But with the high cost of natural gas in Europe, the added cost of capture will make it even more costly. “Still, if a customer ordered a gas unit to capture CO2, we can build it.”

Alix of Powerspan said an even larger problem exists in capturing CO2 from natural gas. Carbon dioxide concentration in a gas plant’s flue gas is 4 percent compared to 12 to 15 percent for coal. What’s more, the flue gas flow in a natural gas-fired power plant is around 50 percent greater than in a coal-fired power plant per megawatt of capacity because air is introduced to provide mass flow through the turbine. “With gas, you feed in a lot of excess air to drive the turbine,” Alix said. So the lower CO2 concentration combined with the higher flue gas flow could at least double the cost per ton of capturing carbon.

Oxy Combustion

Oxy combustion (often called oxy-firing) represents another approach to carbon capture. Introducing pure oxygen into the boiler instead of ambient air (eliminating nitrogen) produces an almost pure CO2 stream and makes it relatively easy to capture. In theory, oxy combustion can be retrofitted to existing coal plants. “There’s no technical reason you can’t do it,” said McCauley. “You simply add the oxygen system, meaning conventional air separation, compression and purification. But there’s a lot of considerations that would go into that decision and it would be very site-specific.”

Oxy-firing might be incorporated into an existing coal plant by replacing the existing boiler. The economics of such a strategy would be daunting: it likely would entail a new boiler coupled with the existing turbine generator and everything else at the plant that is decades old. Thus, the consensus appears to be that oxy combustion lends itself best either to new construction or complete repowering projects.

All major boiler OEMs are looking into oxy firing. For example, Alstom built the combustor for a 30 MW (thermal) test with European utility Vattenfall scheduled for startup this summer. A B&W licensee built the flue gas desulfurization system. And in December, B&W burned coal in full oxygen combustion mode at a 30 MW (thermal) test at its research facility in Ohio. The test operated in full oxygen-coal combustion mode for more than 250 hours and burned more than 500 tons of bituminous coal.

B&W said it will continue its oxy-fired research through this summer, also testing sub-bituminous, lignite and Powder River Basin coals. Data gathered will form the foundation to design a large-scale reference plant to implement the technology at commercial scale. B&W has been seeking parties to conduct further oxy-coal combustion testing at a large demonstration plant in which more than a million tons of CO2 could be captured in a single year.

Reducing Carbon

Hitachi is attacking the carbon issue on multiple fronts. The company is actively developing its own oxyfuel combustion and CO2 capture technologies. Hitachi’s current emphasis is on building ultra-efficient coal plants that produce less carbon per kilowatt-hour produced, new nuclear plants that produce no carbon and various renewable technologies that either produce no carbon or are carbon-neutral. Those include hydroelectric, wind and biomass.

“We need conservation and CO2-neutral generation,” said Dr. Song Wu, director of advanced technology commercial applications for Hitachi. With its nuclear joint venture with GE (GE Nuclear Hitachi), the company is poised to be a major player in nuclear plant development. “We need a multi-pronged approach,” said Wu. “And one of the most cost effective approaches is efficiency. We are leading the new wave in sliding pressure supercritical plants.”

To date, Hitachi has provided supercritical boilers and turbnes for Genesee 3 and Keephills 3 in Alberta, Council Bluffs in Iowa, Elm Road in Wisconsin and the boiler for the Cliffside expansion in North Carolina. When complete, Cliffside will replace four old coal units. Eskom in South Africa recently ordered six supercritcal Hitachi boilers. Europe has taken a liking to supercritical coal plants as well. In recent years, Hitachi Europe has received orders for more than 14,000 MW of supercritical units. Hitachi Japan has supplied 50 supercritical units, including the 1,050 MW Tachibana-wan 2, one of the largest single-boiler coal units in the world.

“These plants with state-of-the-art boilers, turbines and air-quality control systems are very efficient,” said Wu. For example, Hitachi Tachibanawan 2 has a net efficiency of 42 percent. “Compre that to the current U.S. coal fleet that is about 33 or 34 percent efficient and you see the latest supercrtitical plants use 20 percent less fuel and produce 20 percent less CO2. We think this is the most cost-effective means of CO2 reduction,” Wu said. “And it’s a mature technology that’s commercially avalable.” He said that supercritical plants are more likely to be retrofitted with CO2 capture and sequestration technologies as they become proven.

“It’s interesting that in the 10 years since Europe signed the Kyoto Protocol, they have come to the conclusion that an effective way to help meet their Kyoto goals is to build an 800 or 1,000 MW supercritical power plant to replace old plants,” he said. “Supercritical is now recognized as best available technology in Europe. From a life cycle and cost point of view this is certainly the best near-term solution without causing too much economic penalty.”

Hitachi is also moving toward developing ultra-supercritical plants that would boost efficiencies considerably above its supercritical offerings. Those ultra-supercritical plants could be available by 2015. “We are heavily involved in R&D on both the boiler side and turbine side,” Wu said. The biggest issues still to resolve involve materials that can operate at very high temperatures and pressures. Wu said he expects the first ultra-supercritical coal plant to be built in Europe, where carbon reduction has a date-certain and where supercritical technology is already accepted.

B&W’s McCauley said that reaching supercritical and ultra-supercritical steam temperatures “gets us into the 40 percent-plus efficiency range and we can eventually get even higher than that.” B&W is supplying the supercritical boiler for the 600 MW AEP Turk plant in southwest Arkansas that will achieve a steam temperature of 1,115 F, the highest-temperature boiler to date in the United States. “That’s the quickest route to lowering CO2 emissions,” he said.

As to which capture strategies hold the most promise, McCauley said it’s still too early to tell.

“I don’t think anyone can say today conclusively what the capital cost of a full-fledged version of a carbon capture plant will be.” Recent government reports tend to bear that out. Regardless of which metrics you look at, each of the technologies seems to be in the same general area. At-scale demonstrations are also needed to determine where those costs may end up. Then industry will need to work to reduce costs still more.

“We’re all ready to do some large at-scale testing,” McCauley said. “If funding from FutureGen is freed up to do five or 10 CCS projects, it’s a great step forward.”