Carbon capture and storage or sequestration (CCS) involves isolating carbon dioxide (CO2) from other power plant emissions before it is emitted from the stack, compressing it into a liquid, and pumping it into underground geological formations such as spent oil or natural gas wells, saline reservoirs, or inaccessible coal seams.
A 2007 study released by the Electric Power Research Institute (EPRI), found that U.S. electric utilities can help the nation cut its CO2 emissions to 1990 levels by 2030 by taking aggressive steps in seven areas. The most significant reductions, according to the study, would come from CCS technologies.
The National Energy Technology Laboratory (NETL), in its “NETL 2007 Carbon Sequestration Atlas,” reports that North America has enough storage capacity at its current production rate for more than 900 years of carbon dioxide.
A great deal of progress has been taking place during the last year related to CCS. Some activity is focused solely on the capture side, some solely on the sequestration side, and some on both. The two projects that have advanced the furthest involve a We Energies plant—which will demonstrate technology for capturing CO2 emissions—and an American Electric Power (AEP) plant—which will both capture and sequester CO2. These projects make up two phases of a three-phase rollout by Alstom, a French CO2 capture technology provider that was involved in both projects. But many types of organizations, from Battelle to Siemens, are moving CCS technology forward in different ways.
We Energies’ Pleasant Prairie power facility in Pleasant Prairie, Wisc., has two plants with combined generating capacity of 1,210 MW, burning low-sulfur pulverized coal.
Alstom and EPRI tested a pilot-scale version of CO2 capture on a 1.7-MW portion or slipstream (see Figure 1). The project started in early 2008 and wrapped up Oct. 8, 2009, capturing about 40 tons of CO2 each day. Although the project was a small-scale test, it was important because it showed how the technology would operate commercially in a state-of-the-art, base-load coal-fired power plant. “The plant has the latest air quality controls in place, similar to what will probably be the case in other coal plants when commercial CCS processes are in place in the future,” explains Brian Manthey, senior communications specialist for We Energies.
Alstom is working on three different CO2 capture technologies. The We Energies project used chilled ammonia technology. The chilled ammonia withdraws about one percent of the exhaust (flue) gas between the outlet and the stack. The gas is first cooled to condense and remove moisture and residual pollutants. It then enters a CO2 absorber, where the CO2 is absorbed by an ammonia-based solution, separating it from the flue gas. Then, the CO2-laden solution is heated, releasing a pure stream of CO2.
In a commercial-sized application, the CO2 stream would be compressed and transported for use in industrial processes, such as enhanced oil recovery, or for injection and storage (sequestration) in a suitable underground geological formation. In this pilot project, though, the CO2 was remixed with the treated flue gas, and the entire extracted gas volume reintroduced into the flue gas desulphurization (FGD) outlet transition duct, where it was mixed with the FGD exhaust gas.
Results are encouraging. The pilot performance improved steadily, to the point that stable absorber operation at 100 percent of design flue gas flow was established by April 2009. Overall, the project achieved the vast majority of its research objectives and demonstrated the fundamental viability of CO2 capture. “The process was able to successfully capture CO2 while it was integrated with the other air quality control systems that were in place,” Manthey says. “It was able to capture at about a 90-percent rate, so it was a very good first step.”
He adds that in the future, We Energies would consider using CCS as a technology tool for reducing greenhouse-gas emissions—albeit at a significant price. “One challenge that remains is energy consumption, which is a key cost driver,” he says. Another is that since Wisconsin doesn’t have the geological formations for sequestration, the utility would need to make sure there is a transportation system set up to send the CO2 to a place where it could be stored. “This likely would be a pipeline system, and we would need to look at the cost of doing this,” he adds.
Considering such costs will be part of the purpose of AEP’s validation-scale project in West Virginia.
AEP and Alstom partnered to install the first CCS project designed to capture and store CO2 at AEP’s 1,300-MW Mountaineer power plant, a pulverized coal-fired facility in New Haven, W.Va. Built in 1980, Mountaineer emits about 8.5 million metric tons of CO2 a year.
In 2009, the plant was retrofitted with Alstom’s chilled ammonia CO2 capture technology on a 20-MW slipstream of the plant’s flue gas. It was designed to capture 330 tons of CO2 per day, and is capable of removing about 100,000 metric tons of carbon emissions annually.
The project began capturing CO2 on Sept. 1, 2009, and began storing it on October 2 (although the sequestration process officially was launched October 30). The CO2 was transported from the plant by pipeline to a nearby well, where it was injected into permanent storage in two saline reservoirs 7,800 feet underground.
“It’s still new, of course, but it’s working as anticipated,” reports Melissa McHenry, an AEP spokesperson. “The data that’s collected and analyzed from this project will support efforts to advance CCS technologies to commercial scale and provide information to the public and industry.”
The project will operate for at least 12 months, but possibly longer, in order to help validate the effectiveness of Alstom’s capture technology, as well as the viability of storage in the local geology. “We will continue to monitor the sequestered CO2 for some time,” McHenry says.
Following the completion of product validation at Mountaineer, AEP plans to install a commercial-scale application of Alstom’s system on one of its other coal-fired plants.
The site of Alstom’s Phase III commercial-scale demonstration project has yet to be determined. When commissioned, though, that project is expected to capture 1 million to 1.5 million tons of CO2 per year for use in enhanced oil recovery or storage in an underground formation.
McHenry says AEP would like to see Phase III take place at Mountaineer. “We have the space available,” she says. Scale-up costs would be about $668 million, and AEP already has applied for Federal stimulus funds. “These stimulus funds would be about half the cost of the scale-up to 235 MW,” she says.
For the Mountaineer project, DOE’s Office of Fossil Energy contributed $7.2 million, while Alstom and AEP contributed $1.4 million for the initial phases. Geological investigation of the site cost $4.2 million. Battelle Memorial Institute (Ohio) served as the consultant to AEP on geological storage and is expected to continue in that capacity.
Several other utilities are participating in sequestration-only projects. In fact, more than 20 such tests have been, or are being, conducted nationwide under the U.S. Department of Energy’s Regional Carbon Sequestration Partnership Program, which has seven regional partnerships. Two of the participating utilities are Duke Energy and FirstEnergy, which have been involved in projects managed by DOE’s Midwest Regional Carbon Sequestration Partnership (MRCSP).
In September 2009, 1,000 metric tons of CO2 were injected in two 500 metric-ton well tests at Duke Energy’s East Bend Generating Station at Rabbit Hash, Ky. “We offered our East Bend plant, because it is one of our younger plants, and if we were to retrofit one of our pulverized coal plants in the future, East Bend would definitely be a candidate,” says Darlene Radcliffe, Duke Energy’s director of environmental technology and fuel policy. “East Bend is also located right over the Mt. Simon Sandstone geological formation, which is thought to have a very high potential to be a good CO2 sequestration reservoir.” As such, according to Radcliffe, when MRCSP was looking for a site, East Bend turned out to be a natural fit.
The plant didn’t actually produce the CO2 for the injection test. Rather, food-grade CO2 was purchased and trucked in by tanker trucks. “The test was very successful,” she states. “All indications are that this will continue to be a very good site.”
However, things didn’t go quite as well at FirstEnergy’s R.E. Burger plant in Shadysville, Ohio, the site of another MRCSP-sponsored CO2 injection. “We offered the Burger site to have a test well drilled,” reports Mark Durbin, a FirstEnergy spokesperson. “Battelle started doing injection testing there in 2008.” But according to a May 21, 2009 DOE press release on the R.E. Burger project, “Results of the formation evaluation indicated that the porosity, void space, and permeability of the target formations were lower than expected. The pressure in the formations also rose unexpectedly with very low injection rates.”
In sum: “The project didn’t seem to work out as we had hoped,” Durbin says.
The MRCSP effort—including its successes and its failures—illustrates the variety of groups working on CCS technologies. In addition to the vendor companies and utilities, the Battelle Memorial Institute in Columbus, Ohio, serves as leader of the MRCSP while also working on individual companies’ CCS projects. Battelle was involved in AEP’s Mountaineer project by itself (AEP being a Battelle client), and in the Duke and FirstEnergy projects in its role as leader of the MRCSP. The MRCSP is working on CCS projects in nine states, according to Charles McConnell, vice president of carbon management for Battelle.
“This project development can be defined as geological study work, mapping, and data gathering,” he says. The MRCSP is now in the process of developing a Phase III project, which will involve a significant increase in the amount of CO2 introduced into a geological formation, with a target of 1 million tons over a four-year period. Battelle currently is evaluating several sites for this Phase III injection, and will make that announcement by the end of 2009.
What will be the future of sequestration? The ideal, of course, would be for every power plant that emits CO2 to sit atop a geological formation that allows safe and permanent sequestration. And in fact some such plants exist, such as AEP’s Mountaineer and Duke’s East Bend. However, most power plants aren’t so fortunate, such as We Energies’ Pleasant Prairie.
“Liquid CO2 will need to be transported to other locations, where it can be sequestered,” McConnell says. “During pilot projects, this is being done via truckload, because the quantities aren’t that large.” However, as a permanent solution, Battelle envisions a network of pipelines, most of which will be in and around the Midwest, particularly the Ohio Valley. One benefit of this, according to McConnell, is that not only are large numbers of the nation’s coal plants located in the Midwest and South regions, but most of the geological formations that can accept CO2 sequestration are also in these regions, meaning that while CO2 may need to be pipelined from some plants to other sequestration locations, the distances won’t be as long as they might be if plants were located in other parts of the country.
“We believe that the economic decisions of running pipelines for the whole commercial framework will become a reality when the legislative framework and policies come together,” McConnell says. “In the meantime, we are working hard at advancing the technology and the experience.” For these projects, Battelle is focusing on locations that have both the source (the plant) and the geology (sequestration reservoirs).
Another important player in CCS development is the Electric Power Research Institute (EPRI). “We are involved in a number of CCS projects, some of which use chilled ammonia, some of which are using other technologies,” says Hank Courtright, a senior vice president at EPRI. For example, EPRI is working on one project in cooperation with Southern Co. and MHI (Mitsubishi Heavy Industries) that’s about the same size as the Mountaineer project. It’s located at Southern’s Plant Barry in Alabama, and startup is planned for the first quarter of 2011. It will use MHI’s technology, which also uses a solvent to capture the carbon at the end of the combustion cycle.
Courtright sees the next scale-up for CCS being in the 200-MW to 300-MW range. “Alstom is thinking about this for Mountaineer, but it also recently announced a project with TransAlta in Canada, so it could happen anywhere,” he continues. “The keys are to have a plant that is operating very efficiently and has a reasonable enough storage capability at the plant location.” EPRI’s research suggests that carbon-sequestration locations in the United States have enough capacity to meet the requirements of about 60,000-MW of generating capacity.
As to the challenges of CCS going forward, two are of particular concern. One relates to capture technology’s installation costs. While costs would be significant for a new coal-fired plant, they are even higher for a retrofit at an existing plant. “I think CCS will end up being a combination of both retrofits and new plant installations in the future,” Courtright says. “As we prove the technology and bring the cost down to the target levels we want, and if carbon legislation does pass, there may be some early retrofits to get the most value out of these existing assets.” At the same time, he says there also could be some new locations coming on board.
A closely related challenge is the problem of parasitic energy demand—the energy required to operate CCS capture technology at a plant. “Our goal is to get down to the 10-percent to 15-percent range, which would be a very economically attractive option,” Courtright says.
As EPRI sees it, CCS is not the end-all and be-all of carbon management, but it is a significant component. “It’s important to have a full portfolio of options in order to meet the targets of CO2 reduction,” Courtright says. “CCS will need to be an important part of this.”