By Steve Blankinship, Associate Editor
Gasifying coal and petroleum coke to make chemicals is nothing new. Yet only recently has the power sector begun considering gasifying coal to make electricity, notably by pairing gasifiers with combined cycle power blocks. The idea of forming a “combo”-that is, making chemicals and other products along with generating power-has existed only as one possible theme among many being considered by companies composing what amounts to the background music for utility-scale power fueled by gasified coal.
A few big-name utilities are looking to make big-time power from gasified coal. AEP has utility-scale integrated gasification combined cycle (IGCC) plants in the works for Ohio and West Virginia. Duke Energy Indiana plans to build a 630 MW IGCC plant at Edwardsport to replace the existing 160 MW coal-fired unit there. NRG hopes to build utility-scale IGCC plants in New York and Delaware. Tampa Electric has announced plans to build a 630 MW IGCC at its Polk site, already the location of a 260 MW IGCC.
In Taylorville, Ill., another power-oriented IGCC is under development, owned by individuals from original developer ERORA and Omaha-based Tenaska. And yet another power producing IGCC is being proposed by Tondu Corporation at Corpus Christi, Texas to be fired by petroleum coke, also known as petcoke.
Often asked is the question of whether or not the economic viability of new power-producing IGCC plants could be enhanced by making marketable byproducts in addition to power. The question essentially presupposes a willingness for a power project to set aside a solo career to learn how to swing in a combo.
It’s nearly impossible to attend a power industry event on IGCC where the subject is not broached. Some speakers state that such cogeneration is one of the technology’s inherent advantages. Among the most commercially viable byproducts are elemental sulfur, sulfuric acid, methanol and substitute natural gas (SNG).
Making SNG would allow converting some of the estimated 250-year coal supply in the United States into natural gas and placing it into the existing gas pipeline infrastructure to bolster the nation’s tightening gas supply. Making SNG would also require adding equipment to a power IGCC to convert the hydrogen and carbon monoxide in the syngas to methane.
Substitute natural gas is similar to natural gas. It could augment the U.S. gas supply and be used any way natural gas is being used today. That would include helping fuel the large combustion turbine fleet built over the past 15 years. It could also be used to fuel large industrial facilities, as feedstock for chemical manufacture, and heat both space and water in commercial buildings, schools and homes.
Although at least a half dozen utility-scale IGCC power plants have been announced and a few others are in various stages of development, none have yet broken ground. Some of those in advanced stages of development are now facing cost re-assessments and re-evaluations - especially due to economic considerations likely to affect construction for all kinds of power plants.
Such economic considerations and price escalations are significant in light of the fact that an IGCC is projected to cost at least 20 percent more than a pulverized coal (PC) plant of comparable size. Add to that the fact that uncertainties remain about what actual performance will be - a factor that utility regulators say they need to carefully assess before including a power plant in a utility rate base. In light of all this, it might seem that some developers should at least consider having their IGCCs swing to a cogeneration beat. Cogeneration means making both power and a marketable byproduct. In contrast, polygeneration means producing two or more commercially viable products and no electricity.
But it’s hard to predict the economic benefits of cogeneration. No one has ever done it on a utility power scale. And at a cost of about a $1 billion for a gasification block and perhaps another $1 billion for a utility-sized power block (600 MM to 650 MW), it’s not something investors or regulators view casually.
Asked if there is any way to quantify what viable economic and environmental advantages might be derived from cogenerating with an IGCC compared to simply making baseload power, Jim Jurczak, director of IGCC and gasification projects for Burns & McDonnell says he knows the answers “in a couple of areas.” Confidentiality agreements prevented him from disclosing them, however. Burns & McDonnell is the consulting engineer for ERORA/Tenaska’s Taylorville Energy Center.
Jurczak said the idea of a switch-hitting IGCC sounds appealing, at least in theory.
“It’s easy to say it’s a non-peak power period and I’m going to have one of the (gasification) trains not running, so the gasifier and the associated equipment is a dead asset. So I might as well use it. In that kind of scenario, the cost to make SNG would appear to be attractive. If you’re a utility with combined cycle or simple cycle capacity and you need gas, it may make a lot of sense. You can make gas while you’re not putting power on the grid. Just keep the facility operating and save some money on natural gas on the spot market.”
Indeed, the idea does seem appealing and Duke considered it for Edwardsport. “We looked at ammonia and urea,” said Dennis Zupan, senior project director for Edwardsport. “Based upon our analysis, it would be necessary to commit a minimum of 20 percent of the syngas produced by gasification to producing byproducts on a full-time basis to facilitate the swing between processes and to keep from incurring significant start-up and shut-down costs. In our particular case, the IGCC would be one of the lowest variable cost plants in our fleet and would dispatch as base load unit 24-7. We ultimately determined that the electrical output is far more valuable to Duke as a regulated public utility and the loss of 20 percent of plant output did not represent the best economic choice.”
Another big consideration, said Zupan, is the added capital cost, design and operational complexity demanded by polygeneration. He says Duke has worked for the past two years with the GE/Bechtel alliance, whose plant design Duke will use, to develop the IGCC plant as a reference design for electric production that could eventually result in reduced cost and uncertainty for future units. “We are satisfied that the best solution for Duke Energy Indiana is to press on with a pure electric design for the Edwardsport IGCC,” he said.
FutureGen
AEP also remains committed to keeping it simple, at least for now. “We have no plans for cogeneration with an IGCC,” said AEP spokesman Pat Hemlepp. “Our IGCC plant is being engineered strictly as a power producer. The goal is have the process as simple as possible on the first-generation IGCCs we build. We’re not pushing the technology to its maximum capability. That’s what FutureGen will do.”
FutureGen refers to the large-scale demonstration plant being funded by a consortium of industry and government entities to produce power and byproducts, including hydrogen. FutureGen is also intended to capture and sequester carbon dioxide.
“We’re not adding anything that could become a complicating factor that could impact reliable operations,” said Hemlepp. “The first ones will be about as basic as an IGCC can get. Once we’re more comfortable with the technology, later plants will be designed to enhance efficiency and other things.”
Tampa Electric Co. (TECO) has announced plans to build Polk 6, a full-scale IGCC power plant to provide electricity. TECO already has a 250 MW demonstration IGCC plant at the Polk site, which began commercial operation in 1996. TECO said it has not done detailed studies on adding equipment to Polk 6 that would be needed to make anything other than electricity and the two materials that occur naturally from the power process: slag and recovered sulfur. “We have looked at polygeneration options at a high level in the past,” said Mark Hornick, general manager of the Polk Power Station. “Conceptually, the value of an IGCC plant could be increased by producing power during times of high demand and high incremental pricing for electricity, then swapping over to production of co-products during periods of low power prices.”
But because the power facilities and co-production facilities would have to be sized to use full capacity syngas flow from the gasification plant, the utility would be paying for full load capability for both power and a co-product, but using only a portion of the capacity over time. “Those fixed costs of each production facility are amortized over a smaller production volume which hurts the project economics,” he said. TECO’s view is that an efficient IGCC unit in central Florida using low-cost coal and petcoke should dispatch early and operate with a high capacity factor, making it more efficient and cost-effective than it would be in a co-production mode.
A Possible Niche
NRG Energy Executive Vice President Steve Winn said his company has thought about building its proposed IGCC plants as swing units. “We want to make these plants as economical as possible so we consider the ‘swing’ potential at certain sites. That means it has to be close to a natural user of the alternative output.”
He said that if an IGCC were placed near an existing petrochemical complex and if the ancillary commodities or hydrogen had a ready market for resale, then the company would sell the most valuable commodity (be it SNG, pure hydrogen or electricity) whenever possible. “But because the entire country needs power, not all IGCCs will be built where there’s a ready market for chemicals,” he said. “So most companies would build IGCC as baseload units. In all cases, however, we would want to sell the standard byproducts of gasification - carbon and sulfur - whenever possible.”
Winn also said that selling SNG either for power or as commodity gas could be attractive because the gasifier and combined cycle power block would not have to be in the same place. “It could allow for building gasifiers near coal fields and combined cycles near load. At current gas prices, we would not be surprised if creating and shipping SNG in this manner is economically attractive.”
He said the likely developer of this strategy would be a chemical or a coal company with well-placed reserves and good alternatives for sequestering CO2 removed during the gasification process. “It is conceivable we would consider partnering or securing offtake from facilities like this, but have not done so to date.”
Of course IGCC makes electricity, even if there’s not enough to sell to the grid. That power is used to generate most or, usually, all of the very substantial amount of power needed to run a gasification plant. Therein lies the allure that has made IGCC a popular technology for chemical manufacturing for almost 100 years. Therefore, any IGCC making “SNG exclusively” or any other product “exclusively” is also, in effect, a co-production facility.
And David Shwartz of the ERORA Group, which started the Taylorville project and is now developing the Cash Creek plant in Henderson County, Ky, does not agree with most project developers interviewed for this story who believe that co-producing power and other products on a commercial scale would be a very risky proposition in the near term. Initial plans call for Cash Creek to make electricity and substitute natural gas.
“We’ll look at the markets and let them determine what we can do,” he said. Cash Creek has already received its air permit. Construction on the 630 MW (nominal), 770 MW (gross) plant could start by the end of this year. The project is expected to be commercial by 2010 or 2011. GE Energy Financial Services has purchased a 20 percent interest in The ERORA Group developing the project.
Coal by Pipe?
Duke Energy’s Dennis Zupan said that through affiliate companies, Duke will continue to evaluate opportunities that might have merit under different circumstances. He suggested that making SNG from coal may be one such circumstance that presents an economical way to better use already installed combustion turbine and combined cycle units across the Midwest. “Strategically located SNG plants in or very near coal fields, and at a cross-road of high pressure interstate natural gas pipelines, may be an attractive offering,” he said. “SNG makes it possible to have coal by pipe instead of the traditional coal-by-wire.”
Several such plants are already in development. And Illinois, with its large coal deposits in the southern portion of the state, its location at the geographical center of the U.S. near a confluence of existing and proposed natural gas pipelines and with an aggressive state-supported program that encourages coal production, appears to be at the epicenter of coal-to-SNG project development.
The largest project announced to date is the Cardinal coal-to-SNG plant, which would be located at a yet-to-be determined site in central Illinois. Cardinal is being developed by Peabody Energy. As currently envisioned, the plant would produce about 100 million cubic feet per day of substitute natural gas.
Within the next few months, construction is expected to begin on a $250 million coal-to-SNG plant developed by St. Louis-based Secure Energy on property previously owned by Archer Daniels Midland and Caterpillar in Decatur, Ill. The project, which received its air permit in April, will initially convert up to 1.4 million tons a year of high sulfur Illinois coal into 45,000 million Btu/day of pipeline-quality natural gas. The Decatur facility will eventually increase its output to 67,000 MMBtu/day. “The Decatur plant will serve as Secure Energy’s reference plant that we intend to replicate at similar sites,” said Lars Scott, president.
An Expensive Idea
And a third Illinois coal-to-SNG plant, to be located in Jefferson County, could break ground within the next nine months and be in operation within four years. The Southern Illinois Coal to Synthetic Natural Gas Project being developed by Chicago-based Power Holdings, LLC could produce up to a billion cubic feet of SNG annually. CFO Steve Shaw said the company looked at making power, but decided SNG was a better strategy in a stand-alone business model, one requiring little or no special tax incentives or government subsidies.
“We looked at a lot of possibilities that included polygeneration,” said Shaw. “There have been projects proposed to sell power during the peak daytime, then switch to making a byproduct. That sort of arbitrage is a really good idea. But we found that it’s also an expensive idea. You have to build the facility to do everything. We couldn’t figure out a way to make that work.”
Conversely, he believes industrial gasification facilities are more straightforward. “The power market has a power curve and you have to respond instantaneously. There’s no storage and you have a somewhat unpredictable demand. That adds a level of complexity that’s tough. An industrial gasification facility just starts up and runs very well at very high availability. You don’t have to turn them down because everyone’s going to bed.”
Shaw said that offtake customers for SNG are sophisticated gas system operators who have storage, understand how to manage pipelines and have strong relationships with the interstate transmission systems. That makes them “quite able to handle the production fluctuations,” he said. Power Holdings said it has customers lined up in Illinois and other states.
An ‘Illusion’?
Joe Tondu, an independent developer who plans to file for permits by the end of this year to build the 600 MW Nueces IGCC plant at Corpus Christi, Texas to supply power to the ERCOT grid, said he too believes that cogenerating byproducts is not harmonious with making electricity. Tondu, whose plant would be fueled primarily with petcoke, is already in discussions with customers for power purchase agreements. He hopes to begin construction next year.
“You hear all these stories about how you can make all these products and that’s not true, he said. “Polygeneration with IGCCs is illusionary. A chemical or liquid product from syngas is not a co-product. It’s an ‘either/or’ product, unlike conventional cogeneration that generates power and thermal energy at the same time.”
Tondu is basing his current design on a single Shell slagging gasifier fueling a 600 MW 2 X 1 system consisting of two 7F-class gas turbines and a single heat recovery steam generator. Shell uses a dry feed technology that Tondu said he believes will provide availability in range of 85 percent to 90 percent. He said he believes the project can produce power for $65 a MWh, plus or minus 10 percent using 100 percent private money. “I think that’s the cheapest IGCC power project in the U.S.,” he said.
Versatility is one of gasification’s most-touted advantages, and someday, that versatility may well mean the ability to swing from various levels of power production to various levels of co-producing one or more by-products.
But for now, it appears the IGCCs being built will produce power only, along with the elemental sulfur and slag that naturally accompany power production. FutureGen may teach later-generation IGCCs how to swing, but in the meantime, IGCCs will make power and gasifers will make chemicals and SNG. The sweetest music is yet to come.
AN IGCC Pioneer in North Dakota
Although several coal-to-SNG projects are racing to be the first to go into commercial operation, one facility has been producing pipeline grade SNG since 1984 and today is the world’s largest carbon dioxide sequestration project.
The Great Plains Synfuels Plant near Beulah, N.D., began as a government response to the energy crisis of the 1970s. Since it began operations, the plant (now operated by the Dakota Gasification Co. - DGC), has been producing substitute natural gas from the state’s lignite deposits. It currently makes more than 54 billion cubic feet of natural gas a year using 6 million tons of lignite. The gas leaves the plant through a 2-foot-diameter pipeline and travels 34 miles south to the Northern Border Pipeline, which transports the gas to four pipeline companies for distribution in the eastern United States.
In addition to natural gas, Great Plains makes fertilizers, solvents, phenol, carbon dioxide and other chemicals. Carbon dioxide captured by the gasification process is placed into a pipeline and sent to Canada where it is used for enhanced oil recovery (EOR). Carbon dioxide is now part of an international venture for enhanced oil recovery in Canada. To date, the plant has captured more than 10 million tons of CO2 and sequestered more than 7.2 million tons.
Purchased from the U.S. Department of Energy in 1988 by Basin Electric and operated by DGC, Great Plains struggled for years to achieve economic viability, due largely to low natural gas prices. But an uninterrupted period of much higher natural gas prices has helped the project turn the corner. In the last three years, project owners have repaid its loans and generated substantial revenue.
In May, Dakota Gasification paid DOE $39.2 million - the seventh payment under the terms of a revenue-sharing agreement. That lifted the total amount paid to DOE to date to $285.2 million. Taking into consideration the tax credit given up by Basin Electric, the total benefit to the federal government of selling the plant is $1.1 billion.