Deregulation can play savior or spoiler for clean coal progress
By Timothy B. DeMoss, Associate Editor
The deregulation of the power industry (or re-regulation in some eyes) is affecting technology commercialization in interesting and sometimes unexpected ways. If you own a wind farm and have been selling your electricity to the local utility under PURPA, a free-for-all electricity market might keep you awake at night. But imagine for a moment that you own an oil refinery. With advances in gasification-to-power technology, being able to sell the electricity you generate on the open market would be a dream come true. Currently, projects combining gasification-to-power with refining or chemical production generate power for project owners` own needs, with little or no export power. Watch for this to change.
Integrated gasification combined cycle (IGCC) looks increasingly attractive for pure power generation and repowering applications, but it is cogeneration applications, particularly with oil refineries, which may be the boot to kick IGCC commercialization into high gear. Pressurized fluidized bed combustion (PFBC) is also enjoying continuing progress. R&D activities continue for both of these advanced power generation technologies (Figures 1 and 2), and success stories are accumulating. However, staying one step ahead of the technologies` problems is a battle not yet won.
The El Dorado project (a Texaco Gasification Power Systems project in El Dorado, Kan.) is an excellent example of why oil refineries may be gasification`s future. William Preston, a Texaco project manager , provided an El Dorado progress update at the Electric Power Research Institute`s 1996 Gasification Technologies Conference.
The project`s gasification unit started up last June with syngas transferred to the combustion turbine on Sept. 12. In addition to 35 MW net power and 180,000 pounds of steam per hour, the system fulfills other cogeneration roles by supplying pressurized air, nitrogen and oxygen to the refinery. The power island performs well as a cogenerator, but what makes the project significant to the refinery/gasifier relationship is hazardous waste. The U.S. Environmental Protection Agency (EPA) gave its blessing to the El Dorado project to gasify the plant`s hazardous refinery waste streams. In addition, the project`s gasifier will not be subject to the Resource Conservation and Recovery Act. Although the EPA`s ruling applied only to Texaco`s gasification system, there is no reason to believe the agency won`t extend this status to other similar systems.
“The implications of this ruling are significant,” said Preston. Because the project`s refinery wastes will be considered a fuel for the gasifier, the refinery can avoid disposal expenses and possible long-term liabilities for materials which otherwise would be considered hazardous.
According to Preston, the EPA has in this ruling made a clear distinction between burning hazardous wastes and gasifying them to produce valuable products. At El Dorado, the gasifier will convert petroleum coke and other waste streams to syngas while producing pure sulfur and fuel-grade solids as byproducts. Furthermore, the process results in minimal solid waste and exceedingly low air emissions.
Besides the positive environmental implications, the project also enjoys excellent economics. Preston said the refinery had investigated natural gas-fired cogeneration, but had rejected it due to poor economics. The gasification project is superior because all the gasifier feeds have low or negative costs to the refinery, the project has synergy with the existing refinery operation and the refinery will purchase no new natural gas for the project.
By eliminating price variability for fuel, the refinery maintains long-term control over its operating expenses. With a permanent home for its lowest quality coke, the refinery will also be able to process a wider variety of crudes. In addition, future changes in market or regulatory conditions would allow gasification expansion for co-production of hydrogen, methanol or other petrochemical feedstocks.
The combination of gasification with existing refinery infrastructure is certain to become a staple in the gasification diet. However, the IGCC commercialization effort has three commercial-scale projects in the United States which should be in full swing by the time this issue hits your desk. We highlighted one of those projects, the Wabash River plant in West Terra Haute, Ind., in the June 1995 Power Engineering. The Clean Coal Technology (CCT) program plant, which began commercial operation in November 1995, has been a successful demonstration thus far. The primary problem area has been the reliability of the particulate removal system, due mainly to breaking of ceramic candle filters. Solving this problem for advanced coal technologies is a high priority for the industry and for the Department of Energy (DOE), which has been a partner in bringing these technologies to market. Later we will discuss approaches being taken to find a solution.
Chlorides and traces of arsenic in the syngas have also caused a number of minor problems at Wabash, but these are being addressed by adding a scrubber system.
Despite these snags, the Wabash plant has managed to meet its environmental goals for SO2 emissions. The gasification process has performed well enough to allow the plant to successfully operate below 0.2 lb/MBtu for SO2 emissions with instances of emissions less than 0.1 lb/MBtu. These numbers are significantly below the year 2000 limits set by the Clean Air Act Amendments (CAAA), which require SO2 emissions to be less than 1.2 lb/MBtu. This emissions performance is no surprise considering the IGCC goals (Figure 3) set by the CCT program. Its goals are more ambitious than the CAAA regulations, with 0.2 lb/MBtu SO2 set as a goal for 2000 and a reduction to 0.15 lb/MBtu by 2020.
Other IGCC demonstrations
Other IGCC projects are planned or under way nationwide (Figure 4). Two of these which should produce results this year are the Polk Power Station project in Polk County, Fla., and the Piñon Pine project east of Reno, Nev.
The Piñon Pine project will showcase the first full-scale integration of several advanced IGCC technologies, including: a pressurized KRW fluidized bed gasifier; full-stream hot-gas desulfurization using a transport reactor system with a zinc/nickel-based sorbent; full-stream, high-temperature ceramic filters; and an advanced GE MS6001(FA) gas turbine.
The Polk unit, partially funded under the Round III CCT Program and owned by Tampa Electric Co. (TEC), will provide much needed experience with a new commercial-scale hot gas cleanup (HGCU) technology. The system, developed by General Electric Environmental Services Inc. (GEESI), will accept syngas at 900-1,000 F, eliminating the need to cool the gas prior to sulfur removal. This will boost the efficiency of the 250 MW system because the syngas can be admitted to the combustion turbine without reheating. Traditional gas cleaning methods cool the gas to 100 F before attempting sulfur removal.
Because the emission control capabilities of the HGCU system have yet to be demonstrated, emission estimates for the system are higher than those for a cold gas cleanup system which will operate in parallel to the HGCU technology at the Polk site. TEC officials said because of permit requirements, the HGCU system must match the cold gas system emission rates after Polk Power Station has completed the two-year, phase-one demonstration period.
Besides demonstrating the capabilities of the HGCU system, the combined-cycle project is intended to integrate the various hardware and systems to attain maximum cycle efficiency. For example, low-pressure steam from the heat recovery steam generator (HRSG) supplies heat to the coal gasification plant. In return, the coal gasification syngas coolers supply the HRSG with steam energy to supplement the steam cycle power output. TEC officials Charles Black and John McDaniel said the most novel integration concept in the Polk project is the intended use of the air separation unit (ASU). The ASU will fulfill its traditional role as oxygen provider to the gasifier. But the system will also simultaneously provide what is traditionally excess or wasted nitrogen to increase power output, improve cycle efficiency and lower NOx formation.
Clean coal`s biggest problem
Most are familiar with the other major technology arm of the DOE`s CCT program–PFBC. The goals for the PFBC program are illustrated in Figure 5. Like the IGCC efforts nationwide, there are also several major PFBC R&D and demonstration projects across the country (Figure 6). Some of these, like the Tidd project in Ohio, have been featured in previous issues of Power Engineering. Although the Tidd project has been fairly successful, early problems emphasized how quirky a complex, advanced system can be. Tidd`s problems with coal and ash handling seem conquerable for PFBC in general, but the HGCU system problems which plagued Tidd (and Wabash River) have been brought center stage in the last several months. Control of hot gas contaminants dominated the discussion at last summer`s Morgantown Energy Tech nology Center (METC) Ad vanced Coal-fired Power Systems Review Meeting.
A presentation by Parsons Power Group Inc. provided an update on the status of particulate collection systems, hot gas desulfurization systems and trace contaminant removal systems. The systems` assessment was a result of a recommendation by the National Research Council`s (NRC) Committee on the Strategic Assessment of the DOE`s Coal Program. The committee was responsible for recommending the emphasis the DOE should consider in updating its coal program in response to the Energy Policy Act of 1992.
The NRC committee concluded that the components for the advanced IGCC and PFBC power plant systems which need the most development are the hot gas cleanup sections. This fact has not changed since Power Engineering`s report on advanced coal combustion in September 1995. However, the NRC recommended that the DOE look specifically at the ability of numerous programs to meet, within three to six years, all requirements for future high-temperature (2,300 F) turbine operation and environmental acceptability. This timetable seems short, but these technologies have seen progress.
Particulate collection systems
IGCC systems require particulate removal at the gas stream temperature, and PFBC requires it at the exit temperatures of the combustor and carbonizer. For PFBC, this temperature can be as high as 1,600 F. R&D programs have developed several devices to meet this challenge, including advanced electrostatic precipitators and candle filters. However, until such devices see long-term service at commercial-scale conditions, advanced PFBC and IGCC are relegated to the lab. Two pilot plants, the 8 MW Wilsonville Power Systems Development Facility (PSDF) in Alabama and the 10 MW Karhula plant in Finland, should provide needed data in this regard. But there is only one active demonstration-scale plant testing the filters (the 71 MW Wakamatsu plant in Japan), and it is testing only the Japanese manufactured Asahi tube filter.
Ceramic monolithic candle filters have undergone the most extensive testing of the high-pressure/temperature particulate filters. However, like the Japanese Asahi filters, tube failures are still too common. To solve creep and brittleness problems with the ceramic filters, METC is sponsoring a program to build and test a modified ceramic candle filter with embedded ceramic fibers. There are also several other advanced materials (Dupont Lanxide PRD-66, 3M CVI silicon carbide/Nextel, Dupont Lanxide silicon carbide, Westinghouse/Techniweave continuous fiber ceramic composite, and Pall iron aluminide and stainless steel sintered metal) and filtering techniques (granular bed filters) under development, but long-term, in-service testing remains dependent on the construction of more demonstration plants.
Late last October, the DOE approved relocating two of its CCT demonstration projects to Lakeland, Fla., combining them into one project. The two projects, originally planned for construction in Des Moines, Iowa, and Calvert City, Ky., faced diminishing prospects at those sites due to uncertainties regarding regional power requirements, according to the DOE.
Foster Wheeler will design the nominal 170 MWe Lakeland project, incorporating the company`s topped, pressurized circulating fluidized bed (PCFB) combustion system. If the first-generation PCFB is successful when test operations begin in mid-2000, the project will “upgrade” to the advanced or topped PCFB system by adding a carbonizer for the topping cycle. The project will provide much-needed operations data for topped-PCFB and hot-gas filter technology at commercial scale. However, until the Lakeland facility is operational in 2002, the Wilsonville PSDF will be crucial to maintaining progress toward an acceptable commercial filter system.
The PSDF will enable tests on a variety of particulate control devices and filter designs. There are plans in the future to test desulfurization technologies at the facility, and to eventually attempt to integrate fuel cells into the design. It will also serve as a main bridge for topped PCFB between Foster Wheeler`s Livingston, N.J., pilot plant and commercialization of the technology, according to James McClung, a Foster Wheeler project manager. The Livingston plant began operation in 1991. McClung said the PSDF will provide invaluable scale-up data for the topped-PCFB process and represents the first time that a number of the topped-PCFB components will be put together and operated in an integrated fashion.
Hot gas desulfurization
Another factor affecting HGCU performance in an IGCC system is the HGCU system`s ability to capture sulfur gases before syngas combustion. PFBC systems remove sulfur in the fluidized bed, using limestone or dolomite as a sorbent. This method depends on the ready availability of limestone, which is relatively inexpensive and poses few problems. On the other hand, IGCC systems require a sulfur capture system which uses a regenerable sorbent. Similar to the status of particulate filters, although hot gas sulfur sorbents have been available for years, sorbent developers have yet to test a sorbent for extended periods at commercial scale which meets the needs of current IGCC technology.
The key issue in sorbent development is the sorbents` ability to retain their reactivity and physical integrity during repeated sulfidation and regeneration cycles. There are about a dozen sorbents under development, but at least three of those have no additional testing planned.
Hot gas desulfurization process development is in the same boat as sorbent development; no commercial-scale demonstrations have been completed. The processes with the best chance of seeing commercial-scale testing in the near term are the M.W. Kellogg transport reactor, due for full-scale 100 MWe demonstration in the Piñon Pine project, and GEESI`s 1,000 F moving bed system slated for operation in TEC`s Polk project. The TEC demonstration will use a 10 percent slip stream at the 250 MWe plant and is for physical checkout only.
One more system targeted in the HGCU assessment is the trace contaminant removal system. Control of hazardous air pollutants (HAP) is a growing concern, and research into HAP control for IGCC and PFBC is in its infancy. This summer, Power Engineering will look at HAP control in depth. Other trace contaminants which affect IGCC and PFBC include alkali metals, chlorides and ammonia. Based on EPA studies thus far, mercury is the only HAP likely to require control.
In many cases, these contaminants will probably be controlled by condensation and filtration. However, several organizations are studying and testing the use of sorbents or catalytic decomposition to achieve the same end.
One of the problems facing anyone studying HAP control for IGCC and PFBC is the same problem facing HAP control studies for any power generation technology–lack of data and lack of a suitable sampling technique. One study by METC and the Energy & Environmental Research Center at the University of North Dakota had to rely on thermochemical equilibrium predictions to evaluate advanced control systems because good emissions data were so scarce. Actual test data for the study came from Tidd, GE, Louisiana Gasification Technology Inc. (LGTI) and the Cool Water gasification plant. The average collection efficiency shown in Figure 7 would be meaningful were it not for a combination of sampling errors and trace element probe contamination among the advanced-control-system plants.
The study concludes that the overall emission of trace elements from advanced power systems appears to be equal to or lower than that of conventional systems on average. However, that these conclusions assume only two data sets (Tidd and LGTI) are valid, highlights the need for better sampling techniques. Unfortunately for advanced coal-fired systems commercialization, the EPA is expected to hand down regulations on mercury emissions as early as next year. Conventional systems will face the same burden, but if more HAP emissions regulations are drawn up during the IGCC and PFBC commercialization timetable, these technologies could see unexpected delays coming to market.
HGCU cost impact
How HGCU research affects the cost of electricity (COE) is of primary importance with regard to the commercialization potential of IGCC and PFBC technologies. The Parsons report reviewed this aspect of HGCU systems, looking at the sensitivity of baseline plant design and cost figures to changes in system parameters.
Using two 400 MWe plants as baseline designs for the IGCC evaluation, the assessment group calculated the changes in IGCC COE resulting from 10 percent increases in selected HGCU parameters (Table 1). One plant was based on a Destec oxygen-blown entrained-flow gasifier with a hot gas desulfurizer. The other was based on the KRW air-blown gasifier with in-situ desulfurization and a hot gas desulfurizer. Both designs assumed ceramic candle filters for particulate control. The results showed that HGCU systems account for between 10 and 15 percent of total IGCC plant costs, and desulfurizer and particulate filter costs account for 8 to 11 percent and 2 to 4 percent of the total cost respectively.
The group did similar assessments for a 535 MWe PFBC plant. The plant was based on a Foster Wheeler design with a carbonizer and a PCFB combustor. For PCFB, the capital cost of the particulate filter is about 10 percent of the total plant cost. Other studies quote this number as high as 15 percent. PCFB systems have no hot gas desulfurization costs because sulfur is controlled in the carbonizer or fluidized bed combustor. The COE results for PCFB are in Table 2.
These costs represent significant portions of total plant costs, but as environmental regulations tighten, the costs will become necessary evils.
Savior or spoiler
As these advanced technologies come of age, we are certain to witness even further modifications, additions and innovations to their design. The DOE`s Advanced Turbine Systems program will play an important role in improving the systems` efficiencies. And other advanced systems such as a supercritical bottoming cycle, the Kalina cycle and even fuel cell integration will take clean coal designs to the next level. Many predict 60 percent efficiencies or higher for these coal-fired technologies within the next quarter century. Deregulated power production could provide CCT developers with a ready-made market for these advanced designs.
Seeing this potential makes projects like the PSDF and Lakeland seem that much more important. However, just as deregulation can open new markets for these advanced technologies, uncertainty about the direction deregulation will take could potentially cause significant delays to the technologies` commercialization. Utilities have yet to again start building new plants in large numbers; some companies are risk averse in such an industry climate. This fact coupled with a trend toward less government involvement in helping commercialize new technologies means advances in some plant components are straggling behind the development curve.
For example, the group designing and building the Wilsonville PSDF has run into problems with seemingly minor components like high-pressure/temperature valves and piping, among others. One source involved with the facility said these problems are unlikely to halt progress because they appear solvable. Nonetheless, if the companies with the expertise to manufacture these “minor” components are unwilling to invest in their development until a market exists, commercialization progress could be slowed significantly. This scenario seems unlikely, but let`s hope that the pioneers in advanced coal-fired technology keep the faith so the technology is ready when the power generation industry needs it. z
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