Emissions Compliance Gets Tougher
Existing and pending environmental regulations are compelling generating asset owners to consider both capital-intensive emission reduction systems and novel control technologies.
Power plant emissions and the Caribbean limbo dance share a common refrain today: How low can you go? Government regulations–existing, pending and proposed–are forcing utilities to contort their operating plants into unusual positions in order to squeeze under the falling limbo bar. And the threat of Kyoto-induced carbon dioxide emission regulations raises the difficult question of whether many plants should approach the limbo bar at all or just gracefully bow out of the dance. Technology is available and evolving that can address many of the emission standards; the acid test, however, is whether such technologies can achieve their purpose without rendering a plant uneconomical.
The Good: SO2
By most any measure, the Title IV acid rain provisions of the 1990 Clean Air Act Amendments (CAAA), particularly for SO2, have been effective. All Phase 1 affected units achieved 100 percent SO2 compliance, primarily through fuel switching and banked allowances. When Phase 2 begins in 2000, with tighter constraints on all emitters in order to meet the CAAA`s 8.95 million ton per year cap, additional scrubber retrofits may be required as banked credits are used up. An EPRI report, SO2 Compliance and Allowance Trading: Developments and Outlook, estimates the depletion of the 10 to 15 million tons of banked allowances around 2005 will usher in a “second wave” of FGD retrofits. To be competitive with current allowance prices (approaching $150/ton), retrofit capital costs down around $100/kW will be necessary to justify large FGD investments.
The proposed revisions to the National Ambient Air Quality Standards (NAAQS) for fine particulate matter (PM2.5) also might require additional SO2 control. The existence of a reliable relationship between fine sulfate emissions from power plants and ambient PM2.5 concentrations is still debatable but, if demonstrated, could have serious repercussions. In analyzing the potential impacts of meeting an SO2 cap at one-half the CAAA level, the EPRI report cited above provides some startling predictions: 124 GW of FGD retrofits, marginal SO2 reduction costs of $1,470 per ton and total additional compliance costs of $4 billion per year. These predictions were developed in the absence of competing alternatives, however, so they only represent what could occur, not what will occur.
Predicting the course of market forces is obviously impossible, but there does appear to be some recent renewed interest in FGD retrofit projects, possibly buoyed by the recent rise in Phase 2 SO2 allowance prices to around $140/ton. Tampa Electric recently committed to install a wet FGD system at the 440 MW Big Bend Units 1 and 2 to complement the scrubber system already in place at Units 3 and 4. The design features a high-velocity dual flow tray absorber using limestone forced oxidation chemistry with a dibasic acid additive. The system will achieve 95 percent SO2 removal capability and produce high-quality gypsum for wallboard manufacturing. Raytheon Engineers and Constructors and Wheelabrator Air Pollution Control are collaborating to design and install the system, which is scheduled to be completed by mid-2000, in time to assist Tampa Electric in meeting its Phase 2 obligations.
Tampa Electric chose the FGD system over the conversion of the Big Bend units to handle cleaner-burning fuels, partly because of experience gained from the FGD systems in place on Units 3 and 4. According to Tampa Electric President John Ramil, the project`s estimated cost of about $90 million, or $100/kW, is less than one-half the industry average for comparable FGD installations. Regulated consumer power bills, however, will have to rise 2 to 5 percent in the next two years to pay for the project.
At plants equipped with FGD systems, back-end residual solids management is gaining in economic and environmental importance. If tighter SO2 regulations result in additional scrubbing, producing larger quantities of byproducts, and if, as expected, cost pressures arising from deregulation continue to increase, land disposal as a Phase 2 solids management practice may not be feasible in the future. Dravo Corp. is upgrading the Thiosorbic FGD system at a large West Virginia power plant to a ThioClear system to maintain the front-end benefits afforded by magnesium lime-based scrubbers–high removal efficiency and low susceptibility to plugging and scaling–while adding the benefits afforded specifically by the ThioClear technology: (i) wallboard-quality gypsum production; (ii) magnesium hydroxide recovery, which may prove commercially viable as a boiler injection material for SO3 control; and (iii) reduced recirculating slurry solids content (1 to 3 percent, compared with 3 to 5 percent for a Thiosorbic system and 15 to 20 percent for a limestone scrubber), thereby reducing component wear and abrasion.
The retrofit, which is scheduled to be operational by early 2000, will require the installation of external oxidizer vessels for scrubber blowdown oxidation, a regeneration tank for crystallization of gypsum and magnesium hydroxide, and dewatering equipment for byproduct recovery. According to Dravo, powering these new components will increase the FGD system`s parasitic power load, from about 0.4 to 0.6 percent for the Thiosorbic system to 0.8 to 1.0 percent for the ThioClear system. Such values are still below the typical 2 percent parasitic loads experienced by limestone scrubbers.
Several other plants have begun or recently committed to FGD retrofits. The Salt River Project`s three-unit, 2,250 MW Navajo Generating Station is in the midst of a large-scale scrubber retrofit project–collaborating with Stone & Webster, ABB Environmental Systems and H.B. Zachry Co.–to comply with some of the most stringent air emissions standards ever set by the U.S. Environmental Protection Agency (EPA). Public Service Company of New Mexico is working with Babcock & Wilcox in upgrading an aging Wellman-Lord desulfurization system at the San Juan Generating Station into a limestone forced oxidation unit to improve sulfur reduction and cut costs. And Edison Mission Energy, which recently bought the 1,884 MW Homer City Power Plant from GPU and New York State Electric & Gas, has indicated that it plans to install scrubbers to reduce emissions and enable the use of cheaper coal.
The Bad: NOx
The CAAA acid rain provisions for NOx, despite reducing emissions 40 percent below required levels, will not be sufficient in certain areas to achieve air quality goals established in Title I of the CAAA or the new NAAQS standards for ozone. Utility power plants are facing tremendous capital outlays in the next 10 years to comply with pending NOx regulations. The McIlvaine Company reports that annual orders for low-NOx burners, selective catalytic (SCR) and selective non-catalytic (SNCR) reduction systems, reburn systems, instrumentation and controls, catalysts, and chemicals for NOx reduction will expand to $2 billion per year within 10 years (Figure 1).1 Annual orders for SCR systems, for example, are projected to pass the $1 billion mark by 2006, while catalyst and ammonia purchases will reach $280 million and $100 million, respectively.
Various pieces of environmental control regulation impact NOx emissions. Direct NOx regulations through Title IV of CAAA, ozone mitigation through Title I of CAAA and the new NAAQS, and the NAAQS regulations for fine particulate matter all influence (or may influence) NOx emissions control at power plants. Title IV Phase 2 restrictions will impose tighter NOx controls on tangential and wall-fired boilers (to 0.40 lb/MMBtu and 0.46 lb/MMBtu), and establish emission limits for cell-burner, cyclone, wet bottom and vertically-fired boilers (to limits ranging from 0.68 lb/MMBtu to 0.86 lb/MMBtu). Ozone stipulations are causing bigger headaches, however, particularly in the Northeast. Regulations established in 1994 for 65 percent NOx reductions (to 0.20 lb/MMBtu) at utility power plants in the Ozone Transport Region (OTR) have led to a lawsuit against Maryland regulators by Potomac Electric Power Co. and Baltimore Gas and Electric Co. Both utilities claim there is insufficient time to retrofit plants with NOx control technologies before the May 1, 1999 deadline, especially since the final rule was not adopted until May 1998.
The larger NOx concern is the EPA`s “SIP Call,” issued in October 1997, in which EPA proposed to require 22 states and the District of Columbia to submit state implementation plans (SIPs) addressing regional ozone transport. Although the proposed rule does not mandate which sources must reduce emissions, power plant reductions of up to 85 percent below 1990 rates or a 0.15 lb/MMBtu emissions rate by 2003 were listed as viable goals. The Alliance for Constructive Air Policy (ACAP) and a coalition of Midwestern governors have each proposed alternative ozone control regulations. ACAP recommends 55 percent reductions from 1990 levels by 2004. The governors recommend a 55 percent reduction by April 2002 and a 65 percent reduction by April 2004. Both groups call for additional air quality monitoring by 2007 to determine the need for lower emission standards.
“To meet the [governors`] 65 percent reduction requirement, American Electric Power (AEP) will spend up to $1 billion to retrofit over half of its coal-fired generation with advanced emission control equipment,” said James Markowsky, executive vice president-power generation for AEP. “This is a major expense, but it`s more reasonable than EPA`s proposal, which will cost us an additional $600 million if imposed.” Michael Geers, senior engineer of environmental services for Cinergy Corp., contends that half of the costs associated with the SIP call will fall on six Midwestern states, despite an unsubstantiated relationship between Midwest emissions and downstream ozone levels. Geers also questions the stringency and timing of the SIP Call, citing the difficulty in scheduling the 8 to 12 week control retrofit outages within the three-year window between SIP submission and regulation enforcement.
Both Cinergy and AEP have licensed NOxOUT systems from Nalco Fuel Tech to gain experience with SNCR technology burning Midwestern high-sulfur coal. Cinergy is installing its system on the 163 MW Unit 6 at the Miami Fort station. AEP is participating with several partners in the largest domestic coal-fired SNCR demonstration to date, at the 600 MW Cardinal Plant Unit 1. Start-up is expected in early 1999. The project is expected to achieve NOx emissions reductions 30 percent beyond those obtained through low-NOx burners.
Duke Power has spoken up in opposition to the EPA SIP call, contending that emissions from the Carolinas have no downwind impact on current ozone nonattainment areas elsewhere in the Mid-Atlantic and Northeast. “The Eastern United States could face power outages if plants are forced to comply with the tight schedule proposed in the EPA SIP call,” said Kris Knudsen, manager of air quality for Duke Power. “We would have to install SCR or SNCR at most of our fossil units to reach the 0.15 lb/MMBtu standard.” Duke Power has already made significant NOx reductions at its 29 tangential-fired units and is scheduled to install low-NOx burners on its remaining two cell-fired units. Low cost (less than $5/kW) hardware and operating modifications have enabled Duke to reach Phase 2 Title IV NOx limits three years ahead of schedule.
Power plant owners are investigating the gamut of NOx reduction technologies to identify the least-cost strategy. Finding the proper mix, however, is complicated by several factors: the site-specific reduction capabilities of various systems, the unproven viability of certain technologies (e.g., large-scale SCR and SNCR on high-sulfur coal) and by uncertainties over the availability of NOx emission credits. Low-NOx burners and gas reburning are technically mature technologies. In an effort to minimize costs, however, novel NOx control technologies are being evaluated, such as Orimulsion firing/reburning, A-55 Clean Fuels for firing/reburning and water injection for cyclone boilers.
A-55 Clean Fuels are a blend of water and petroleum fuels, such as residual fuel oils, diesel and naphtha, with a minor amount (about 0.5 percent) of a proprietary additive. A-55`s initial business focus is the No. 6 fuel oil market for power generation. A number of oil-fired plants are being asked to increase load to meet peak demand, but are limited by concerns over higher NOx emissions. A-55 Clean Fuels, as a replacement for No. 6 fuel oil, reduces NOx emissions 30 to 50 percent, thereby allowing higher loads. There is a higher fuel throughput requirement because of the 30 percent water content of A-55 fuels, but the fuels are lower in cost than No. 6 fuel oil on an energy equivalent basis. Currently, A-55 is working with electric utilities and petroleum refineries to develop the most effective strategy for manufacturing and supplying the A-55 products to utilities. A typical 500 MW oil-fired plant will require 28,000 barrels of A-55 fuel per day, which can be blended either at a refinery or on-site at a power plant.
As shown in Figure 1, SCR systems are expected to gain market share in the next decade. To meet regulatory limits, a growing number of plants will adapt the experience gathered at the handful of domestic SCR installations–and the nearly 200 sites worldwide–to reduce NOx emissions from coal-fired power plants. The most significant recent development was the Tennessee Valley Authority`s (TVA) announcement that it would be installing SCR systems at five plants: Allen, Cumberland, Bull Run, Paradise and Widows Creek. TVA based its decision on an evaluation of the impact of TVA plants on local and regional air quality under the proposed NAAQS regulations. “While we have consistently told EPA that we don`t believe TVA plants have long-range transport impacts, we recognize that significant portions of the Tennessee Valley will have difficulty meeting the new 8-hour ozone NAAQS standard,” said Jerry Golden, TVA senior technical manager for advanced production technology. In selecting the five plants, TVA took into account their geographical significance. Paradise, for example, depending on the prevailing wind patterns, can impact the downwind metropolitan areas around Louisville, Cincinnati and Nashville. TVA is currently in the procurement process for the SCR systems, which should be installed and operational by 2003. The Paradise SCR will be arranged in a high dust configuration. At the other plants, low dust, high dust, tail end and even in-duct SCR configurations are being considered.
The Ugly: CO2
Nothing strikes more fear into a power plant operator`s heart than the threat of emissions regulations for greenhouse gas emissions, particularly carbon dioxide (CO2). Under the terms of the December 1997 Kyoto agreement, the developed countries committed to reduce greenhouse gas emissions by 5 percent below 1990 levels over the 2008 to 2012 period.
If regulations are eventually enacted for CO2 emissions, coal-fired power generation will likely shoulder the lion`s share of the burden. According to Cinergy`s Geers, a 30 percent CO2 reduction would require fuel switching to natural gas at 80 percent of Cinergy`s coal units or retirement of 50 percent of the coal units. It is important to note that the 30 percent reduction is not an absurd target; if current consumption trends continue, such a reduction will be necessary to achieve the 7 percent reduction below 1990 levels that was agreed to by U.S. negotiators in Kyoto.
Interestingly, much of what is going on in the industry is already contributing to fewer CO2 emissions. The popularity of natural gas combined-cycle plants, sporting high efficiencies, results in fewer CO2 emissions per net kWh; such efficiency improvements will not be enough, however, to offset the sheer increase in electricity generation fueled by demand growth. Other options may need to be considered, therefore, including CO2 reuse and sequestration.
Carbon capture and sequestration is the other main method proposed for CO2 control. As shown in Table 1, there is ample ocean, aquifer and reservoir capacity to accommodate the annual worldwide CO2 production of 22 billion tons. Unfortunately, capacity does not equal feasibility, and it is unclear how much, if any, of this capacity could be cost-effectively exploited for carbon sequestration. In April, the U.S. Department of Energy approved funding for 12 projects that could offer potential breakthroughs in inexpensive CO2 capture and disposal technology. The projects range from sequestration feasibility studies in deep ocean, mine and saline environments to the use of novel algae species and polymers that convert and/or collect CO2 for alternate use or disposal.
The economic impact of potential CO2 emissions control legislation is the crux of all global warming debate. Many question the political and practical sanity of legislation that binds the United States and its economy to a treaty from which the world`s economic juggernauts of tomorrow are exempt. The White House`s own Council of Economic Advisers estimates that the Kyoto treaty could add $70 to $110 to the average American household`s annual energy bill; the council tempers these figures by stating that any increase in energy prices would amount to a small premium for an “insurance policy” against what could be a serious environmental threat. Other economic analyses have not found this silver lining. Studies by Resource Data International (RDI), WEFA Inc. and CONSAD Research Corporation conclude that meeting the terms of the Kyoto protocol would be impossible without sharp increases in energy costs and job losses, and a diminished standard of living. RDI projects a loss of coal-fired generation by 36 percent, leaving a 19 percent shortfall in U.S. generating capacity by 2010. CONSAD projects a workforce decline of approximately 3.1 million workers by 2010.
Power plant owners obviously prefer voluntary efforts at CO2 reduction. TVA, like many other utilities, is involved in several projects that provide CO2 reductions, but that also are economically justifiable: nuclear plant optimization, heat rate improvement, hydro system upgrades, landfill methane utilization, dual fuel conversions of peaking units to accommodate natural gas, biomass co-firing and green power programs. Modifying one`s generation mix is also an option. While Duke Power`s decision to seek license renewal for its Oconee Nuclear Station was strictly based on economics, its low-emissions contribution to the generation portfolio is also significant.
A key component of any emissions control legislation, particularly for CO2 and particularly for increasingly deregulated electricity markets, is an emissions credit program. Already proven viable for SO2, such programs are being proposed for widespread application for NOx and CO2 emissions. In advance of the May 1999 Northeast NOx deadline, several auctions and transactions of NOx allowances have already taken place under the OTR NOx Budget Program. Natsource Inc. brokered the first trade in March, coordinating the sale of 600 tons of NOx allowances at a price of $1,700/ton. A cap and trade program is also a centerpiece of the EPA SIP call. This program will build on the lessons learned from the Budget Program, employing a cap on total emissions and a flexible credit policy to improve cost-competitiveness.
Watching the limbo bar drop, generation owners are striving to ensure it doesn`t fall so low that passage is impossible. “We`re dealing in a great time of uncertainty,” said TVA`s Golden. “Since we can`t know what`s going to be required when, we don`t want to make any significant capital expense that will leave our plants stranded.” That sentiment is undoubtedly being reiterated in executive offices around the country. p
The Cumberland Fossil Plant is one of five TVA facilities being retrofit with selective catalytic reduction technology to address NOx emissions. Photo courtesy of TVA.
The Stanton Energy Center in Orlando, Fla., is equipped with selective catalytic reduction technology for NOx emissions control. Photo courtesy of Black & Veatch.
Fine Particulate Agglomerator
Tightening emission regulations for particulate matter, coal switches, concerns over opacity and economic pressures are leading many power plant owners to re-evaluate their particulate control strategies. In one such effort, Wisconsin Electric (WE) is testing Environmental Elements Corp.`s Fine Particulate Agglomerator (FPA) technology at its Presque Isle plant. The test program, which began in late June and was scheduled to run through September, will enable WE to determine whether an electrostatic precipitator-based system can improve fine particulate collection and eliminate the need for flue gas conditioning to reduce opacity. Presque Isle provides an ideal test bed because the similarity of two of its coal-fired units permits a direct comparison between the retrofitFPA technology and anexisting three-field conventional ESP technology equipped with flue gas conditioning.
FPA requires the replacement of one field of a three- or four-field ESP. A flat-plate center electrode is closely spaced (about 2.5 inches) between two flat-plate collector electrodes to generate laminar flow conditions, which facilitate higher particulate collection efficiencies. As fine particles pass through the laminar FPA field, close contact and residual moisture content promote the formation of large agglomerates, which can be more easily collected in downstream fields. Based on preliminary results from Presque Isle, the retrofitted unit is operating–without flue gas conditioning–at opacity levels that can only be achieved at its sister unit using flue gas conditioning. FPA is expected to improve collection efficiencies to levels that would be obtained through the addition of another ESP field, atlife-cycle costs competitive with alternativesolutions.
1 McIlvaine Company, U.S. NOx Control Market 1997-2006, Northbrook, Ill., 1997.