With the coal-fired power sector facing potentially fatal regulations, some visionaries think the future is in generating not just power but a range of products from coal gasification. Getting there will be no easy task.
This is the story of a power plant like no other.
The facility runs primarily on coal, but it can utilize petcoke and biomass when available. The front end resembles an integrated gasification combined cycle (IGCC) plant in which the fuel is gasified to a mix of carbon monoxide (CO) and hydrogen (H2)—syngas. Water for the gasification process is sourced from brackish, low-quality local supplies to avoid stressing freshwater resources. The syngas is cooled, scrubbed, and filtered before being passed through a water-shift reactor with more steam to adjust the H2-CO ratio.
It’s at this point that things get interesting. The CO2 from the gasification process is separated from the syngas, and about two-thirds of the syngas—by this point nearly all hydrogen—goes to the gas turbine, where it’s combusted to produce electricity and heat. The other third goes to an adjacent chemical plant, where it’s combined with some of the CO2 to produce ammonia and urea for fertilizer. The chemical plant is also capable of producing methanol and a variety of other liquid fuels and products, depending on market demand, all of it using output from the gasifier. Waste heat from the turbine is used to power the shift reactor and other plant processes, increasing overall efficiency.
The unused CO2, about 80% of what’s captured, is sent by pipeline to be used in enhanced oil recovery (EOR) in the area’s oil fields, where the plant has been strategically located to serve demand, while the fertilizer is sold to nearby farms. When demand for the plant’s electricity falls during the night, more of the syngas is sent to the chemical plant rather than ramping down the gasifier, which runs at full capacity nearly all the time.
A New Paradigm
The plant described here does not exist—yet. But it may be closer than you think.
It’s not exactly paranoia to suspect the days of massive coal-burning thermal power plants in the U.S. may be on their way out. On Jan. 8, the Environmental Protection Agency (EPA) published the latest version of its new source performance standards for carbon emissions from new power plants. The proposed limit of 1,100 lb CO2/MWh serves as an effective ban on new coal plants without some form of carbon capture and sequestration (CCS), because meeting that limit with a conventional coal plant is very difficult.
Yet carbon capture has not kept up with expectations, and the costs seem prohibitive: Mississippi Power’s Kemper County IGCC project, expected to start up late this year, has seen its total costs balloon to more than $4 billion—this for a 582-MW plant. Duke’s 618-MW Edwardsport IGCC plant in Indiana, built as “carbon-capture ready” but without CCS installed, came online in 2013 at around $3.5 billion. (The Edwardsport plant was a Top Plant Award winner; see “Edwardsport Generating Station” in the October 2013 issue.)
These numbers have experts looking for ways to improve CCS economics. Many of them believe the way forward is a new approach: polygeneration.
What is polygeneration? Simply put, it’s producing two or more marketable products from the same input, whether it’s electricity, hydrogen, fertilizer, synthetic natural gas, methanol, synthetic diesel, carbon dioxide, or something else (Figure 1). The basic processes are not new: Coal gasification has been around since the 1950s, and a variety of gasifier technologies are available.
|1. Waste not, want not. With polygeneration, gasified coal is used to produce a wide variety of outputs, from electric power to hydrogen to chemicals. Source: DOE/NETL
The chemical methods used to turn syngas into other products are well established and have been in use around the world for decades in numerous coal-to-liquids and gas-to-liquids projects. The process works just as well with natural gas, but there has been a renewed focus on coal because the emissions and efficiency benefits are potentially much larger. A polygeneration plant can theoretically achieve efficiencies as high as 55% to 60%, compared to a maximum of about 40% to 45% for a state-of-the-art ultrasupercritical coal-fired thermal plant.
Polygeneration has other benefits. One of the biggest is the potential for much lower emissions than from a conventional coal-fired boiler, because the impurities and pollutants, such as particulates, sulfur, mercury, and CO2, are removed from the syngas prior to combustion, where they are more concentrated and more easily captured.
Another benefit is that the chemicals and fuels produced from syngas are typically cleaner than those produced from petroleum, resulting in lower emissions further down the supply chain.
Coal gasifiers also are less sensitive to feedstock, and can generally use a wide variety of coals and biomass with less optimization than a conventional plant, allowing the owners to leverage fluctuations in fuel prices. Likewise, the chemical products such a plant can manufacture are flexible, allowing it to produce products with the highest current market value.
The overall synergy between the gasifier, power plant, and chemical plant means greater overall efficiency and lower emissions and production costs than for standalone facilities.
There are significant challenges to making all this work, however. High capital costs for coal gasifier technology have thus far been the largest deterrent. By comparison, AEP’s 600-MW ultrasupercritical John W. Turk, Jr. plant in Arkansas (POWER’ s 2013 Plant of the Year, see the August issue), which came online a few months before Edwardsport, cost about half as much, at $1.8 billion.
Though IGCC technology has been around for several decades, it is still not in common usage, especially with coal. Only two other full-size IGCC plants are currently operating in the U.S., Tampa Electric’s 250-MW Polk Power Station and the 262-MW Wabash River plant in Indiana (operated by Duke but owned by the Wabash Valley Power Association), both of which suffered substantial operational issues in their first years of operation; neither incorporates CCS. Meanwhile, only a few other utility-scale IGCC plants are in operation worldwide. Several are planning to test or incorporate CCS, but none involves polygeneration.
Another challenge is the multi-faceted nature of the plant, which significantly increases its operational complexity. Few if any utilities or merchant plant owners have the experience or expertise to operate an associated chemical plant. Early entrants are more likely to come from the petrochemical industry, which has the experience in that field—though with petrochemical residuals rather than coal—as well as in operating refinery-based power plants. Still, it is likely that successful coal-based polygeneration projects will require partnerships between power and chemical companies.
Challenges or not, the plant described in the opening to this article is by no means a fantasy. In fact, it’s the plan for two approximately 400-MW projects currently in development: The Texas Clean Energy Project (TCEP), near Odessa, and Hydrogen Energy California (HECA), planned for a site near Bakersfield. Both locations are in the heart of their state’s oil industry and close to substantial commercial agriculture.
TCEP, being developed by Summit Power Group, plans to employ two Siemens SFG-500 gasifiers and a Siemens SGT6-PAC 5000F gas turbine. Fluor will provide the engineering and construction, and Linde Group subsidiary Selas Fluid Processing will supply the syngas, CCS, and chemical processing equipment. TCEP will be sized to produce at least 400 MW gross, though normal baseload operation will be 377 MW. Of that, about half will be used on site: 105.7 MW to run plant equipment, 15.7 MW for CCS, and 42.2 MW for producing fertilizer. The remaining 214 MW will be sold to the grid.
The TCEP plant will use low-sulfur Powder River Basin coal. It will capture around 90% of its CO2 emissions and produce almost 3 million tons of CO2 for EOR. The Permian Basin area where TCEP will operate has been employing EOR for more than 40 years and has a robust pipeline infrastructure for transporting CO2, but demand for it currently exceeds supply by about 300%. According to project documents, the largest chunk of the project’s revenue will actually come from fertilizer sales—about 700,000 tons per year—rather than power sales.
HECA will be located in one of California’s oldest oil basins, the Elk Hills play (Figure 2) in the Central Valley. Most of the oil from that field has been extracted, however, and increasingly energy-intensive methods are necessary to get out what’s left—thus the potential for CO2 EOR. Unlike TCEP, HECA will use a mixture of coal and petcoke from Southern California refineries. HECA will also be built by Fluor, using Mitsubishi Heavy Industry gasifier technology and gas turbines.
|2. Multitalented. The Hydrogen Energy California project will supply about 280 MW to the California grid as well as fertilizer for Central Valley farms and CO2 for enhanced oil recovery in the Elk Hills oil field. Courtesy: Hydrogen Energy California
HECA is being developed by Massachusetts-based SCS Energy, which acquired it from original developers BP and Rio Tinto. HECA will be able to generate around 280 MW of electricity for the grid, with the balance being used on-site. The facility is projected to capture about 3 million tons of CO2 and produce about 1 million tons of fertilizer each year.
Despite the attractive synergy of these projects, both are relying heavily on public support. TCEP has received $450 million from the Department of Energy’s Clean Coal Power Initiative, while HECA has received $408 million. TCEP will also receive substantial tax exemptions for its CCS and EOR sales from the State of Texas. In both cases, the DOE grants are only a fraction of the approximately $2.5 billion to $3 billion the plants will cost.
HECA is about two-thirds of the way through the permitting process and is still negotiating purchase agreements for its electricity, fertilizer, and other products. Jim Croyle, CEO of SCS Energy, told POWER he expects construction to begin some time in the fourth quarter of 2014.
Laura Miller, Summit Power’s director of projects, told POWER that TCEP had hoped to close financing in December, but its engineering, procurement, and construction contractors (Siemens, Linde, and Sinopec Engineering Group) are having difficulty staffing the project because of the oil and gas boom in Texas, which has made skilled labor extremely expensive and hard to find. Its plan is to break ground as soon as possible in 2014.
TCEP suffered a setback on Jan. 6, when CPS Energy, which supplies power to the San Antonio area, allowed its power purchase agreement (PPA) with Summit to expire. It blamed repeated delays in getting TCEP built and the changing power market as a result of falling natural gas prices. Still, CPS said it would “consider the possibility of an updated PPA with the Texas Clean Energy Project in the future” and that it “remain[s] hopeful this project can proceed.”
Only one other polygeneration project is under development, but it’s one with some structural advantages not enjoyed by TCEP or HECA. India-based Reliance Industries is planning to add what may be the world’s largest gasification complex to what is already the largest oil refinery in the world, Jamnagar in Gujarat. Reliance has thus far run Jamnagar’s 1.5-GW cogeneration power plant on imported liquefied natural gas, but transitioning to syngas from the refinery’s excess petcoke (as well as coal) will allow it to reduce its fuel costs. With the refinery already in place, the polygeneration plant will have a captive customer for it output. The project, to be built by Fluor using CB&I’s E-Gas technology and Linde air separation units, is planned in two phases of eight gasifiers each with initial start-up in mid-2015.
The Way Forward
The companies working on polygeneration are frank about the need for better policy support if the sector is to take off. Speaking to a 2012 meeting of the Interstate Oil and Gas Compact Commission, Summit Power Vice President Jeff Brown openly conceded that the market does not currently support the extra costs of carbon capture, even with additional revenues from selling CO2, fertilizer, and other products. But the current system for carbon sequestration tax credits under Section 45Q actually makes the situation worse.
“As the tax credit is currently structured, no individual facility can predict the number of years it will be able to receive sequestration tax credits,” Miller said. “As there is no assurance that a facility will be able to receive sequestration tax credits for a set number of years, lenders are unwilling to assume the risk that the tax credits will be available.”
Summit and other groups working in CCS have been pushing for an amendment that would allow a CCS project to reserve credits once construction begins. Right now, the credit is capped at 75 million tons on a first-come basis, and those credits are being used up by oil and gas companies conducting conventional EOR rather than true CCS. “We can’t put the $10/ton we ought to be getting for doing EOR with 2.5 million tons per year of captured CO2 because there is no protocol for reserving credits for individual projects, we don’t know how much has been claimed already—and, worse, the IRS won’t tell anybody how much has been claimed or who is actually eligible to make claims,” Miller said.
Jeff Phillips, manager of advanced fossil generation and CCS R&D for the Electric Power Research Institute, said the advantage in polygeneration is likely to go to early entrants with existing infrastructure and expertise in chemical processing, such as Reliance. One challenge is financing projects that are unfamiliar to the investment community because they operate in both the power and chemical markets. “It’s difficult to find investors who want to be involved in all of that,” he said, given how it can take many of them out of their comfort zone.
Another challenge that will need to be addressed is selling polygeneration to public utility commissions in regulated markets, because it’s difficult to separate out the power costs from the chemical costs in calculating the ratebase. Here, the integrated nature of the plant is actually a problem because of the amount of equipment used for both power and chemical production and how operators will shift back and forth depending on market fluctuations. “You can get complicated in a hurry,” he said. “There’s a bigger regulatory hurdle” in building polygeneration plants in those markets.
Croyle agreed, noting that polygeneration is a learning process for regulators as well as developers. “This is something that a myriad of local, state, and federal agencies are dealing with for the first time, and it’s easy to understand their challenge,” he told POWER.
Phillips expects it to be the mid-2020s at the earliest before polygeneration in the U.S. progresses beyond the TCEP and HECA projects. But as with everything in the power sector, things could easily change if the economics shift. “If gas prices surprise the prognosticators and go up, that might spark earlier interest,” he said. ■
— Thomas W. Overton, JD is a POWER associate editor.