Linking fire A a

with CAA compliance Power plant engineers face fast-track decisions under the CAA. Choices should acknowledge fire/explosion dangers. Guidance is on its way from NFPA

By R. C. Adcock, J. B. Biggins, R. E. Fringeli, L. R. Hathaway, and S. S. Pagadala, M&M Protection Consultants

The Clean Air Act of 1990 gives the Environmental Protection Agency (EPA) strong powers to enforce those changing rules. The rapidly advancing compliance dates thrust power plant management de- cision-making into a compressed time frame.

Adjustments in fuels or emissions con- trol systems in power plants can create unexpected fire hazards. Therefore, the fire protection community will need to develop a proactive strategy with respect to the fast-track decisions. This will en- sure that fire protection is considered in the conceptual design, construction, and operation phases of the new or retrofit project.

Scrubber fire prevention Experience tells us that shortcomings in fire protection often are exposed only af- ter a costly, but preventable, event. This

reactive posture should be avoided. Multimillion-dollar fires have devel-

oped in flue gas desulfurization (FGD) systems and some are linked to mainte- nance and construction work. FGD sys- tems, such as wet scrubbers, contain large quantities of combustible materials, in- cluding polypropylene or polyvinyl chlo- ride (PVC) packing. These plastics can be present in configurations up to 4 ft thick and 50 ft in diameter within the scrubber.

Fire hazards are most apparent during periodic maintenance. Open access hatch- es allow a high volume of air movement; combustible scaffolding adds to what fire professionals refer to as “fire loading;” and ignition sources may be present be- cause of cutting and welding activities.

NFPA 850, “Recommended Practice for Fire Protection for Fossil Fueled Steam and Combustion Turbine Electric Generating Plants,” recognizes the scrub- ber fire hazard during outage and con- struction. However, the NFPA committee responsible for this document is consider- ing a revision to enhance guidance for

iifies hazards in equipment with combusti- ble linings. It also suggests that the outlet damper be closed during cutting and welding operations to reduce airflow through the equipment.

Another area of concern for both dry and wet FGD systems is the likely in- crease in pressure drop through an operat- ing FGD system. This could change con- ditions for the induced-draft fans. In addi- tion, a booster fan may be required in high-draft-loss FGD equipment, such as scrubbers. A bypass or other appropriate means should be provided to counteract potential excessive negative pressure con- ditions resulting from the combined pres- sure differential at the induced draft and booster fans. Additional guidance can be found in NFPA 85C, “Standard for the Prevention of Furnace Explosions/Implo- sions in Multiple Burner Boiler-Fur- naces. ’ ’

Regenerative air heaters In addition to protection from the lubricat- ing oil hazard associated with regenerative air heaters, it also is desirable to protect their interior. Fires occur most frequently when a power plant is burning oil or shortly after it changes from oil to pulver- ized coal.

Remote control room monitoring of air heaters helps. Temperature sensors in the flue gas inlet and outlet ducts provide early warning of abnormal conditions. However, conditions, such as the varying sizes of the air heater and high air flow rates, can change the speed of sensor response and should be considered during design.

Another remote monitoring system, de- sirable on regenerative air heaters, is a zero-speed switch on the rotor shaft or on the output shaft from the fluid coupling or gear reducer. This alarm warns of rotor or air hood stoppage that could result in overheating and fire.

NFPA 850 provides specific guidance for regenerative air heater protection, in- cluding manual water spray system appli- cation densities, which is the preferred method of extinguishment. Other protec- tive measures should include at least one observation port at the inlet, and/or outlet ducts for flue gas and air. The ports should provide an unobstructed view of the rotor or stator surfaces. In addition, hatches for fire fighting with hose streams should be added and situated for clear access to the rotor or stator. Valves for drainage from air heaters and/or ducts also are needed.

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Fabric filters Fabric filters may be damaged by either overheating or fire. The filter media can be damaged by flue gases that exceed the design operating temperature. Incomplete fuel combustion in the boiler may cause carryover of burning particles that ignite

POWER ENGINEERINWMARCH 1992

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ed subsidiary of Niagara Mohawk Pow- er.

DukelFluor Daniel reports that the re- powered plant went into commercial op- eration in October 1991. The plant pro- vides 74,000 lb/hr of process steam to local industrial users and 80 MW of electric capacity to Niagara Mohawk Power.

A major task facing the new owners was to improve the plant’s overall heat rate and reduce plant emissions. Original- ly there were seven boilers in the retired plant but only five have been refurbished. Boiler modifications included

new superheaters, burner upgrade for NO, control, FD fan rehabilitation, pulverizer modifications including coal

pipes and feeders, rebuilding of the air heater, construction of a new over fired air

system to help in NO, control, installation of new sootblower system

and controls, rehabilitation of the furnace bottom,

boiler casing, and refractory, non-destructive tube testing and replace-

ment of tubing where necessary, and refurbishing of air and gas ducts, and

windboxes . In addition to modifying the boilers, a

new 90-MW steam turbine-generator was added. Currently, the turbine can supply up to 74,000 lbh r of process steam at 200 psig. It has the capability to supply 200,000 lb/hr of process steam should the need arise in the future.

Three additional extraction points sup- ply steam to low-pressure and high-pres- sure closed feedwater heaters and a de- aerating heater. Two new 50% capacity motor-driven boiler feed pumps provide feedwater to the boilers. An existing 30% capacity boiler feed pump has been refurbished and is used as a spare.

The plant’s original once-through cooling water system has been replaced with a new system consisting of a wood counterflow mechanical draft cooling tower with two-speed fans.

Except for the tripper belt system, which has been refurbished, all of the original coal handling system has been replaced. In addition, the bottom ash handling system on each boiler has been replaced with new transition chutes and submerged drag chain conveyers. The new flyash system is a pneumatic vacu- um system with silo storage.

The plant substation’s 4160-V and 480-V systems have all been refurbished and modernized. Finally, a modem dis- tributed control system (DCS) has re- placed the 1950 vintage control system.

Reddy says that repowering is a viable alternative to the development of a “greenfield” power plant and it offers an attractive alternative when one con- siders the possible ramifications of the new Clean Air Act. END

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Niagara Mohawk. According to Malla Reddy, project

director, Duke/Fluor Daniel, repowering of oldhetired industrial facilities is a viable alternative to the construction of a “greenfield” power plant. One such re- powering project was the Salt City co- generation proiect developed by Duke/

Fluor Daniel. The retired industrial pow- er plant was originally owned and oper- ated by Allied Signal, Solvay, N.Y.

Industrial power plant repowering Repowering of the Salt City plant in- cluded addition of a new steam turbine, refurbishment of five existing pulverized

coal-fired boilers, con- struction of new balance- of-plant systems, and structural and architectural modernization of the old plant.

The new owner of the plant is Salt City Energy Venture, a general part- nership of Hydra-Co Gen- eration Inc., USEC-Salt City Power Corp., Hydro- Co Enterprises Inc., and Energy Investors Fund. Hydro-Co is an unregulat-

POWER ENOINEERINWMARCH 1992 27

the fabric filter. To prevent damage from high tempera-

tures: (1) install an automatic isolation valve and bypass duct to divert the inlet gas streams around the fabric filter (use this option only where permitted for emer- gency conditions), or (2) provide a flue gas tempering water spray system in the duct between the boiler and fabric filter.

Use of filters with relatively high igni- tion temperature can reduce the fire haz- ard. Filter units with operating tempera- ture limits exceeding 400 F should be subdivided by noncombustible partitions throughout the filter area.

NFPA 850 recommends an automatic sprinkler system. There is one note of caution if such a system is installed: Engi- neers should calculate the maximum al- lowable water loading for the structure

, and then provide adequate drainage from the hoppers.

As is the case for scrubbers, a means for manual fire fighting activities is need- ed in filter houses. This includes provid- ing access doors and hatches on all com- partments and at least one standpipe and hose station accessible for each compart- ment.

One other consideration in filter design is the physical characteristic of the flyash.

Electrostatic precipitators Fires occur when products of incomplete combustion collect on electrostatic precip- itator (ESP) plate surfaces and ignite due to arcing.

Another fire hazard to consider in- volves transformer-rectifier sets. This haz- ard can be reduced greatly by having (1) a high fire point dielectric fluid or (2) dry transformer-rectifiers. If the T-R sets use a mineral oil-based dielectric fluid, a standpipe and hose system should allow at least one hose stream to reach them. In addition, the sets should have a fire barri- er, spatial separation and automatic sprinkler or water spray systems.

It also is best to install temperature sensors on the inlet and outlet ducts of precipitators with alarms transmitted to a constantly attended location. The sensors in ESPs must meet the demands of the different equipment size, configuration, and ambient air flows.

Wet FGD systems Wet FGD technologies present some unique requirements in addition to those needed for the protection of dry FGD processes. For example, unlike dry FGD technologies, wet systems usually need lining material in the exhaust ductwork and chimney to protect the system from the severely corrosive environment. Most of these usually proprietary materials are plastic or rubber compositions. Some are more difficult to ignite than others, but all are considered to be combustible. Note that a noncombustible material should be used for duct lining whenever possible.

POWER ENGlNEERlNGlMARCH 1992

If combustible linings are used, they should be protected by an automatic water spray system. A spray system designed for normal scrubber operations may be usable, or a specially designed fixe protec- tion system may be needed. In either case, the system design should provide unobstructed spray patterns that cover the liner completely. Also, the spray nozzles need extra protection with corrosion-re- sistant blow-off caps.

An appropriate means of fire detection will depend on several factors associated with the liner material, including ease of ignition and flame spread rating. It may be possible to limit the spread of a fire in duct lining materials by sectionalizing the ductwork. Blanks used for the isolation of the scrubbers or absorber vessels can be

proach, which has been adopted for the boiler involved, must be initiated when there is a loss of flame.

In a case where a boiler is retrofitted with NO, controls, the range of operation for stable flame can be altered. However, new tests must be conducted to redefine that range. Changes in the burner flame resulting from NO, control modifications may also require re-aiming of the flame scanners.

Because methods of NO, control tend to increase the possibility of unburned combustibles, it is recommended that car- bon monoxide analyzers be placed in the flue gas flow.

Where there is flue gas recirculation, adequate mixing and uniform distribution of the recirculated gas and air must be

used for this purpose. Fine tuning a system to meet the CAA

causes myriad subtle operational changes that could increase fire risks. For exam- ple, it may change at least one common practice at coal-fired power plants-that of energizing the e!ectrgst.?tic precipitater (ESP) only after establishing a stable fur- nace fire. If the ESP is energized during start-up, carryover products of combus- tion or dust from the back passes of the furnace could ignite in an energized ESP. Therefore, even changes to operating se- quences are needed.

Combustion hazards Another operating change, a move to low excess air and air staging, can increase the likelihood that unburned fuels will accumulate in the furnace during combus- tion upsets or flame-outs. These could cause an explosion. The tripping ap-

assured to avoid a combustion hazard. Instrumentation is needed here to monitor the availability of adequate amounts of combustion air in the mixture.

Ammonia Axas =f pewer p!x,,:a where annoii ia is used call for special handling and storage systems. Ammonia’s lower explosive lim- it is 16% and its upper limit is 25%. The chemical is difficult to ignite and a rela- tively stable compound. It begins to disso- ciate at about 850 F at atmospheric pres- sure. In the laboratory it does not ignite at less than 1562 F. Conditions favorable to ignition are seldom encountered in actual use. However, an accumulation of a flam- mable mixture of the gas in an inade- quately ventilated space can explode if a high temperature ignition source is present. Its DOT classification is non- flammable gas.

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A proposed OSHA regulation, sched- uled to become effective in 1992, will require users of extremely hazardous ma- terials (EHM) such as ammonia to under- take process hazard analyses and conse- quence analyses. There also will be a requirement for a process management safety system to cover operations, mainte- nance, training, quality assurance, and other aspects of use of the EHM.

Fuel switching Sulfur dioxide and nitrogen oxides emis- sion reductions to meet the CAA can be accomplished by changing to a different fuel at some power plants. The choices include a change from high to low sulfur coals if not to natural gas. Fuel switching may have an impact on nearly every piece of equipment in the plant.

The design and performance of a coal- fired electric generating unit depends on its fuel characteristics. When burned, low-sulfur coal produces far lower sulfur emissions than high-sulfur coal. The heat- ing value for western low-sulfur coal is lower, hence the plant must consume more coal for the same electrical output or operate at a lower rating. The ash content of the coal also is different.

Specifically, the boiler-furnace, super- heater, reheater, economizer, pulverizer, sootblowers, induced draft (ID) fans, air heaters, precipitators, and ash handling systems are affected by the coal’s ash content and properties.

The equipment affected by the heat value of the coal are the furnace; cy- clones; pulverizers; burners; coal feeders; and forced draft (FD), primary air (PA), and induced draft (ID) fans (combustion and exhaust air); precipitators and coal handling systems.

A change in coal also means that there is a difference in hardness and grindability of the coal. Pulverizers and the coal and ash handling systems are directly affected. These and other types of power plant equipment are exposed to hazards such as fire, explosion and arcing.

Fire and explosion hazards Westem coals, for example, fracture easi- ly and produce more fines (coal dust) than other coals. This makes them more sus- ceptible to spontaneous ignition and spe- cial provisions are needed to reduce fire and explosion hazards. Incidentally, an increased amount of handling of coal in this more ignitable form is common to cyclone boilers, which makes the poten- tial for fire and explosion even greater here.

One way to reduce these risks is to control concentrations of coal dust with dust collection systems or dust suppres- sion systems. Dust collection systems re- move dust from the air before it is dis- charged outdoors. They provide control by spraying a fine mist or foam on the coal where dust is generated. Such sys-

30

tems also control and dilute methane gas- es in coal bunkers or silos.

Conveyor systems must be designkd to minimize dust generation. This includes enclosures to contain the generated dust, and skirt modifications and belt wipers to minimize coal slippage and coal dust car- ryover. Dust control systems and enclos- ures also must be maintained to keep them effective. Even if all these condi- tions are met, a dust control system can- not reduce coal fine spillage and cannot be a substitute for a well-managed house- keeping program.

Improving protective measures Good housekeeping at coal handling facil- ities is critical to fire and explosion con- trol. Even the best-designed dust control system can’t completely eliminate all nui- sance dust. Capital expenditures may in- clude installation of manual washdown and approved vacuum cleaning systems, as well as replacement with dust-tight electrical equipment.

Ventilation systems in the coal handling areas also may need to be improved. Fresh air ventilation and positive pressure areas in such locations as electrical equip- ment rooms will help to minimize dust infiltration and reduce explosive dust or gas concentrations. NFPA 850 offers guidance on the right choices.

An automatic fire protection system that is in place may need modification to cover additional areas. Such systems should be installed in coal-handling areas where none exist. The coal dust collectors themselves should be protected with auto- matic water spray systems. The dust col- lectors should have explosion venting and be instrumented with temperature and flow monitors.

Repowering and improvement Repowering of aging generating stations recently has gained considerable interest among electric utilities. This choice is a means to use the latest technology and meet expected electrical demands at less cost than building a new facility. Repow- ering takes advantage of fluidized bed combustion (FBC) technology, recently applied as a successful means of rescuing inactive or aging stations dating back to the i94Gs.

Some property hazards presented by FBC are common to those of any pulver- ized coal-fired boiler. These include:

Coal preparation -The hazards involve pulverizing/crushing and conveying of coal and limestone to the boiler. Automat- ic water spray systems should be installed to protect critical conveyor systems and should be designed in accordance with NFPA 15, “Water Spray Fixed Systems” and NFPA 850. Automatic sprinkler sys- tems should be installed to protect all levels of coal crushing buildings and bun- ker tripper floor galleries. These could be wet pipe or preaction, and should be in

accordance with NFPA 13, “Sprinkler Systems’’ and NFPA 850.

Dust collection-Baghouses used for collection of dust generated in coal prepa- ration and conveying should be protected by automatic water spray or sprinklers as recommended in NFPA 850.

Burner management- Protection of boilers from explosions and implosions should be provided by structural design and burner control management systems in accordance with NFPA 85C and NFPA 85H.

Unique hazards- Some other property loss hazards, while similar to all fossil fuel fired boilers, present unique chal- lenges in FBC design. Cyclones, for ex- ample, are threatened by solid particles carried over from the combustion cham- bers. Any plastic or combustible liner material in the cyclone could present a fire hazard, and clear access into the cy- clone for manual fire fighting efforts is needed.

Flue gas solids emitted by an FBC differ from those of other boiler designs. Any moisture can cause the calcium sul- fite to become cement-like. Also, the ash product tends to have a greater carbon content in some FBC designs. The build- up of solids could create a fire hazard within the precipitator. This calls for pro- visions for manual fire fighting efforts.

Combined-cycle PFBC The use of a pressurized fluidized bed boiler in a combined-cycle operation pre- sents unique hazards for property loss prevention. Operating pressures of 10 to 16 atmospheres open the potential for leakage and subsequent explosion within the pressure boundary. Pressure relief controls and monitoring should be provid- ed.

The boiler exhaust gases are expanded in a turbine that drives the air compres- sors and generator. These exhaust gases must be extremely clean to prevent fuel canyover to the turbine. Multiple stage cyclones have been used successfully to separate solids from the gas train. If elec- trostatic precipitators or fabric filters are used for gas cleaning, they should be protected as discussed previously.

IGCC ana its hazards The integrated gasification combined cy- cle (IGCC) is another technological appli- cation for burning coal. In this process, coal is converted to an intermediate gas product often called syngas. Syngas can produce thermal energy by being fired in a combustion turbine. Prior to firing, it is cleaned of sulfur and other particulates. After firing, the hot exhaust gases are used to produce steam and drive a second- ary generator to produce additional pow- er.

From a fire protection standpoint, there are several hazards associated with the IGCC process. Coal preparation and stor-

POWER ENGlNEERlNGlMARCH 1992

*

age hazards are the same as for any coal- fired power plant and protection should be in accordance with applicable NFPA stan- dards.

Peculiar to the gasifier, proper purging and air flow must be established prior to start-up. Any leakage must be detected while the combustible gas is being pro- duced. The structure that houses the gas- ifier should have combustible gas detec- tion monitors installed at the ceiling. Proper controls must be maintained to prevent any detonation within the gasifier itself.

The combustion turbine section should be protected by an automatic extinguish- ing system. Combustion controls to sense flame conditions and turbine controls should be provided in accordance with NFPA 850.

Stratospheric ozone protection Title VI of the CAA deals with strato- spheric ozone protection by restricting use and production of compounds such as chlorofluorocarbons, halons, and carbon tetrachloride that are used for fire protec- tion.

The act passed by Congress provides for a phase-out schedule similar to that adopted by the Montreal Protocol; 50% production of halon by 1995 and zero production by 2000. Allowances are made for aviation safety, national security, fire suppression and explosion prevention, if it is determined that no safe and effective substitute is available for these purposes. Congress also is levying excise taxes of perhaps 250% beginning in 1994. These taxes are intended to be a disincentive to produce halon and, therefore, no new use of halon is anticipated.

Under the provisions of the CAA, the EPA is scheduled to issue regulations re- garding the recovery, recycling and dis- posal of halons by January 1992. Com- bined with a reserve of 70 million pounds of Halon 1301, recycled agents could rep-

POWER ENGINEERINGIMARCH 1992

resent a significant source of halon for several years.

From a fire hazard point of view, the restrictions in the use of halons will cur- tail fire protection usage. Halon manufac- turers are developing alternative agents that are estimated to become available in the late 1990s. Releasing halon after July 1, 1992 is not allowed per the CAA, except in an actual fire. Halons are used primarily to protect sensitive electronic equipment where water damage from automatic sprinklers is not acceptable.

Increased cost and decreased availabil- ity of halon in the coming years will have to be filled by either automatic sprinklers, carbon dioxide or new extinguishing agents. In some cases, carbon dioxide systems pose a threat to personnel due to their oxygen displacing characteristics in a confined space. In many applications, the only alternative may be automatic sprink- lers. A thorough understanding of auto- matic sprinkler history, technology, and experience dispels the water damage myths.

In electric generating facilities, halon systems are used to protect confined cable spreading areas, control cabinets for peak- ing combustion turbines, and other sensi- tive instrumentation rooms such as scrub- ber controls. In the future, these areas may need to be protected with automatic sprinkler systems.

Without careful planning, the time may come when the accidental discharge of a halon system could render an important fire protection system instantaneously ob- solete.

Summary The CAA gives the EPA new authority for criminal penalties. Knowing violation of the CAA can be punished as a felony and may result in imprisonment. As pow- er plant engineers speed up their decision- making efforts to adjust operating systems to the new requirements, the fire protec-

tion community will need to develop a proactive strategy with respect to these fast-track decisions. This will ensure that fue protection is considered in the con- ceptual, design, construction, and operat- ing phases of the project.

History reveals that fire protection shortcomings are exposed following a costly, but preventable, event. This reac- tive posture should be avoided. The time to act is now. END

References Clean Air Act, Power Engineering, January 1991. “The Economic Impact,” Keith Mason, EPA Journal January-February 1991. “Clean Air Response: A Guidebook to Strate- gies,’’ EPRI GS-7105. NFPA 850, “Recommended Practice for Fire Protection for Fossils Fueled Steam and Com- bustion Turbine Electric Generating Plants 1990,” National Fire Protection Association. ‘‘Considerations for switching from high-sul- fur to low-sulfur Coal,” R.L. Rupinscas, P.A. Hiller, Proceedings of the American Power Conference, Volume 53, 1991. NFPA 85H, “Standard for Prevention of Combustion Hazards in Atmospheric Fluid- ized Bed Combustion System Boilers,” Na- tional Fire Protection Association. NFPA 85C, “Standard for the Prevention of Furnace Explosions/Implosions in Multiple Burner Boiler-Furnaces,” National Fire Pro- tection Association. NFPA 58 , “Standard for the Storage and the Handling of Liquefied Petroleum Gases,’’ National Fire Protection Association. NFPA 59, “Standard for the Storage and Handling of Liquefied Gases at Utility Plants,” National Fire Protection Associa- tion. NFPA 85B, “Natural Gas-Fired Multiple Bumer Boiler-Furnaces,” National Fire Pro- tection Association.

AUTHORS Ronald C. Adcock is an assistant vice president and consultant for M&M Pro- tection Consultants. He holds a BS de- gree in fire protection and safety engi- neering from the Illinois Institute of Technology.

James B. Biggens is an assistant vice president and consultant for M&M Pro- tection Consultants. He holds a BS de- gree in fire protection and safety engi- neering from IIT.

Ronald E. Fringeli is a consultant for M&M Protection Consultants. He holds a BS degree in physics from Xavier University.

Leonard R. Hathaway is a vice president and managing consultant for M&M Pro- tection Consultants. He holds a BS d e gree from the university of Rhode Island and an MBA degree from the university of Chlcago.

S. Sam Pagadala is a consultant for M&M Protection Consultants. He holds a BS degree In mechanical engineering from Osmanla University and an MS degree in mechanical engineering from the Unlver- sity of Missouri.

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