INDUSTRIAL BOILERS. CUSTOMIZED ENVIRONMENTAL TRAINING. WELCOME. INSTRUCTOR. Insert Instructor Name Here. OBJECTIVES. Define Industrial Boiler Size. Discuss How Nitrogen Oxide (NOx) is Formed. Discuss Factors Affecting NOx. Discuss Boiler Operational Factors. Discuss NOx Controls.
Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author.While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server.
Insert Instructor Name Here
The goal of this course is to provide supervisors with the tools needed to properly manage industrial boilers. It recommends practical, actions that can be carried out by facility management, maintenance personnel and building occupants. The course will help you to integrate good industrial boiler management activities into your existing organization and identify which of your staff have the necessary skills to carry out those activities.
WHAT THIS COURSE DOES NOT DO
The course is not intended to provide information to repair industrials boilers or to install or repair monitoring equipment or control devices. These specialties required training beyond the intended scope of this course. Where this expertise is needed, outside assistance should be solicited.
Clean Air Act Amendments (CAAA) of 1990, amended Title I of the Clean Air Act (CAA) to address ozone nonattainment areas
Stationary sources that emit oxides of nitrogen (NOx) which emit or have the potential to emit 25 tons per year or more of such air pollutant
40 CFR 63 – National Emission Standards For Hazardous Air Pollutants For Source Categories
40 CFR266-- Subpart H--Hazardous Waste Burned in Boilers and Industrial Furnaces
40 CFR 76 – Acid Rain Nitrogen Oxides Emission Reduction Program
Industrial boilers have been identified as a category that emits more than 25 tons of oxides of nitrogen (NOx) per year
Boilers include steam and hot water generators with heat input capacities from 0.4 to 1,500 MMBtu/hr (0.11 to 440 MWt).
Primary fuels include coal, oil, and natural gas
Other fuels include a variety of industrial, municipal, and agricultural waste fuels
Industrial boilers generally have heat input capacities ranging from 10 to 250 MMBtu/hr (2.9 to 73 MWt). The leading user industries of industrial boilers, ranked by aggregate steaming capacity, are the paper products, chemical, food, and the petroleum industries
Those industrial boilers with heat input greater than 250 MMBtu/hr (73 MWt) are generally similar to utility boilers
Boilers with heat input capacities less than 10 MMBtu/hr (2.9 MWt) are generally classified as commercial/institutional units
NOx is a high-temperature byproduct of the combustion of fuels with air
NOx formation in flames has two principal sources
1. Thermal NOx is that fraction of total NOx that results from the high-temperature reaction between the nitrogen and oxygen in the combustion air
The rate of thermal Nox formation varies exponentially with peak combustion temperature and oxygen concentration
When low-nitrogen fuels such as natural gas, higher grade fuel oils, and some nonfossil fuels are used, nearly all the NOx generated is thermal NOx
2. Fuel NOx is that fraction of total NOx that results from the conversion of organic-bound nitrogen in the fuel to NOx
When coal, low-grade fuel oils, and some organic wastes are burned, fuel NOx generally becomes more of a factor because of the higher levels of fuel-bound nitrogen available
Principal among these are:
The heat release rates and absorption profiles in the furnace
Fuel feed mechanisms
Combustion air distribution
Boiler operating loads
For example, steam pressure and temperature requirements may mandate a certain heat release rate and heat absorption profile in the furnace which changes with the load of the boiler.
Solid fuels can be introduced into the furnace in several ways, each influencing the rate of mixing with combustion air and the peak combustion temperature
These parameters are very unit specific and vary according to the design type and application of each individual boiler
NOx emissions from boilers tend to be highly variable.
The ranges in baseline NOx emissions for boilers are due to several factors including:
These factors usually influence baseline NOx in combination with each other, and often to different degrees depending on the particular boiler unit.
The firing type of the boiler influences the overall NOx emission level
Even within a particular type of boiler, other design details may influence baseline NOx
For Pulverized Coal:
Boiler Type Average lb of NOx / MM Btu
Low NOx Burners, Natural Gas Reburning, and Low NOx Burners with Staged Combustion Air are effective in controlling NOx in these units
Boiler Type Average lb of NOx / MM Btu
Overfeed Stoker 0.29
Circulating Fluidized Bed Combustion (FBC) 0.31
Bubbling FBC 0.32
Underfeed Stoker 0.39
Spreader Stoker 0.53
Air staging in coal-fired FBC boilers is very effective in reducing NOx from these units
For Residual Oil:
Boiler Type Average lb of NOx / MM Btu
Watertube (10-100 MM Btu/hr) 0.36
Watertube (>100 MM Btu/hr) 0.38
Low NOx Burners, Flue Gas Recirculation, and Staged Combustion Air have shown some reduction in NOx for residual oil
For Distillate Oil:
Boiler Type Average lb of NOx / MM Btu
Watertube (10-100 MM Btu/hr) 0.13
Watertube (>100 MM Btu/hr) 0.21
Low NOx Burners, Flue Gas Recirculation, and the combination of Low NOx Burners with Flue Gas Recirculation are used to control Distillate Oil NOx
For Natural Gas:
Boiler Type Average lb of NOx / MM Btu
Thermally Enhanced Oil Recovery
(TEOR) Steam Generator 0.12
Watertube (10-100 MM Btu/hr) 0.14
Watertube (>100 MM Btu/hr) 0.26
Low NOx Burners, Flue Gas Recirculation, and Staged Combustion Air and combinations of these methods are all effective in reducing NOx for natural gas
Boiler baseline NOx emissions are highly influenced by the properties of the fuels burned
Among each of fuel types, emissions will depend on highly variable factors such as fuel grade and fuel source
In particular, studies have shown that fuel nitrogen content — and for coal the oxygen content and the ratio of fixed carbon to volatile matter — are key factors influencing NOx formation
Nitrogen Content of Fuels
The following table gives ranges of nitrogen content for different fuels:
Fuel% by Weight
Coal.8 – 3.5
Natural Gas0 – 12.9
Sulfur can combine with oxygen and water to form Sulfuric Acid, H2SO4
Fuel% of Sulfur
Although lower sulfur content generally means lower nitrogen, there is no apparent direct relationship between these two fuel oil parameters
Fuel ratio is defined as the ratio of a coal's fixed carbon to volatile matter
Under unstaged combustion conditions, lower fuel ratios (i.e. higher volatile content of the coal) correlate to higher levels of NOx, because with higher volatile content coals, greater amounts of volatile nitrogen are released in the high temperature zone of the flame where sufficient oxygen is present to form NOx
Firing coal with high volatile content and lower fixed carbon generally results in less solid carbon to be burned out in the post-flame gases, meaning that the coal can be fired at lower excess air before combustible losses became a problem
Moisture content plays an important role in the formation of uncombustible emissions in Municipal Solid Waste boilers
Non-combustible content of Municipal Solid Waste can range from 5 to 30 percent
Moisture content of Municipal Solid Waste can range from 5 to 50 percent
Nitrogen contents of Municipal Solid Waste can range between 0.2 and 1.0 percent
Boiler heat release rate per furnace area is another influential variable affecting NOx formation
As heat release rate increases, so does peak furnace temperature and NOx formation
Boiler heat release rate varies primarily with:
Boiler firing type
Primary fuel burned
Boiler heat release rate per unit volume is often related to boiler capacity
Chief among these operational factors are the amount of excess oxygen in the flue gases and the combustion air temperature
Excess oxygen refers to the oxygen concentration in the stack gases, and is dependent on the amount of excess air provided to the boiler for combustion
Combustion air temperature, meanwhile, is dependent on the degree of air preheat used before the air is introduced into the furnace or burner
Air preheat is usually used to increase furnace thermal efficiency
Operation on low excess oxygen or air is therefore considered a fundamental part of good combustion management of boilers
Many boilers are typically fired with excess oxygen levels which are more than adequate to assure complete combustion and a margin of safety
Units often are operated at unnecessarily high excess oxygen levels that result in unnecessarily high NOx emissions and losses in efficiency
The greater degree that the air is preheated, the higher the peak combustion temperature and the higher the thermal NOx
Retrofitting existing generating units with low-NOx burners is the most frequently chosen compliance control because it is an economical way to limit the formation of NOx
Low-NOx burners control fuel and air mixing to create larger and more branched flames, reduce peak flame temperatures and lower the amount NOx formed
The improved flame structure also improves burner efficiency by reducing the amount of oxygen available in the hottest part of the flame
In principle, there are three stages in a conventional low-NOx burner:
1. Combustion - combustion occurs in a fuel-rich, oxygen-deficient zone where the NOx is formed
2. Reduction - where hydrocarbons are formed and react with the already formed NOx
3. Burnout - internal air staging completes the combustion. Additional NOx formation occurs in the third stage, but it can be minimized by an air-lean environment
Low-NOx burners can also be combined with overfire air technologies to reduce NOx further
Natural Gas Reburning
Another combustion modification technique involves the staging of fuel, rather than combustion air
By injecting a portion of the total fuel input downstream of the main combustion zone, hydrocarbon radicals created by the reburning fuel will reduce NOx emission emitted by the primary fuel
This reburning technique is best accomplished when the reburning fuel is natural gas
Application of these techniques on boilers has been limited to some municipal solid waste (MSW) and coal-fired stokers
Staged Combustion Air (SCA)
A technique that reduces flame temperature and oxygen availability by staging the amount of combustion air that is introduced in the burner zone
SCA can be accomplished by several means.
For multiple burner boiler, the most practical approach is to take certain burners out of service (BOOS) or biasing the fuel flow to selected burners to obtain a similar air staging effect
Generally, SCA is not considered viable for retrofit to packaged boiler units due to installation difficulties.
Flue Gas Recirculation (FGR)
Involves recycling a portion of the combustion gases from the stack to the boiler windbox
These low oxygen combustion products, when mixed with combustion air, lower the overall excess oxygen concentration and act as a heat sink to lower the peak flame temperature and the residence time at peak flame temperature
These effects result in reduced thermal NOx formation.
It has little effect on fuel NOx emissions
FGR is currently being used on a number of watertube and firetube boilers firing natural gas
The CO emissions from boilers are normally near zero, with the exception of a few boilers that have poor combustion air control or burner problems
Oil-fired units were found to have the lowest baseline CO emissions than either coal- or gas-fired units
CO emissions are generally caused by poor fuel-air mixing, flame quenching, and low residence time at elevated temperatures
In some furnace designs, CO emissions can also occur because of furnace gas leaks between furnace tubes
Other air pollution emissions that are a concern when NOx controls are applied to boilers are: ammonia (NH) and nitrous oxide (NO), unburned hydrocarbon (HC), particulate matter (PM), and air toxic emissions
Ammonia and NO emissions are associated with the use of the Selective Non-Catalytic Reduction (SNCR) controls and with Selective Catalytic Reduction controls to a lesser extent. With either urea or ammonia hydroxide, unreacted ammonia emissions escape the SNCR temperature window resulting in direct emissions to the atmosphere
Increases in HC, particulate matter (PM) and air toxic emissions are primarily of concern with the application of combustion modification controls
HC emissions do not change when NOx controls are implemented
HC emissions are the result of poor combustion conditions such as inefficient fuel-air mixing, low temperatures, and short residence time
These emissions are most often preceded by large increases in CO, soot, and unburned carbon content
By limiting CO, smoke and unburned carbon in the flyash, HC emissions are also suppressed
Studies of industrial boilers and particulate matter (PM) reveal the following trends:
Low excess air reduced PM emissions on the order of 30 percent
Staged combustion air increased PM by 20 to 95 percent
Burner adjustments and tuning had no effect on PM
Lower CO emission levels generally achieved with these adjustments would tend to lower PM as well
Flue gas recirculation resulted in an increase in PM from oil-fired packaged boilers by 15 percent over baseline levels
NOx reduction techniques that have a potential impact on the disposal of solid waste are combustion controls for Pulverized Coal-fired boilers and flue gas treatment systems for all applicable boilers
Combustion controls for Pulverized Coal-fired boilers are principally Low NOx Burners. These controls can result in an increase in the carbon content of flyash that can preclude its use in cement manufacturing.
The only increase in water use is associated with the use of Water Injection or Steam Injection and potentially with the use of flue gas treatment NOx controls, especially Selective Non-Catalytic Reduction
The amount of water used does often not exceed 50 percent of the total fuel input on a weight basis
Catalysts used in the Selective Catalytic Reduction process can be hazardous
Examples are vanadia and titania catalysts
Many catalyst vendors recycle this material thus avoiding any disposal problem for the user
Some of the catalysts, especially those that use rare earth material such as zeolites, are not hazardous and their disposal does not present an adverse impact
40 CFR 266.100, Subpart H allows for burning hazardous waste in industrial boilers
Prior to burning hazardous waste in a boiler, owner/operators must receive a permit
The destruction of hazardous waste in a boiler is considered treatment
A hazardous waste analysis must be performed prior to receiving a permit
General Requirements – Fugitive emissions.
Fugitive emissions must be controlled by:
(A) Keeping the combustion zone totally sealed against fugitive emissions; or
(B) Maintaining the combustion zone pressure lower than atmospheric pressure; or
(C) An alternate means of control demonstrated to provide fugitive emissions control equivalent to maintenance of combustion zone pressure lower than atmospheric pressure.
General Requirements – Automatic waste feed cutoff
A boiler must be operated with a functioning system that automatically cuts off the hazardous waste feed when operating conditions deviate
The permit limit for minimum combustion chamber temperature must be maintained while hazardous waste or hazardous waste residues remain in the combustion chamber
Exhaust gases must be ducted to the air pollution control system
Operating parameters for which permit limits are established must continue to be monitored
General Requirements – Changes
A boiler must cease burning hazardous waste when changes in combustion properties, or feed rates of the hazardous waste, other fuels, or industrial furnace feedstocks, or changes in the boiler or industrial furnace design or operating conditions deviate from the limits as specified in the permit.
Asbestos was used in fire brick and gunnite used for internal insulation of boilers and other vessels
Asbestos is dangerous when it becomes “friable”
Asbestos materials are health hazards because:
Inhaled asbestos fibers can be trapped in the lungs
Inhaled asbestos fibers have been linked to cancerous cell growth in the lungs
If asbestos is in your older boiler, have workman alerted to its presence. Any friable asbestos should be removed by qualified workers.
An overheating boiler can quickly be identified by steam or a mixture of steam and water being discharged at the safety relief valve or from an open hot water faucet
If this condition is found at a faucet, close the faucet
Immediately shut down the water heater's source of heat
Allow the water heater to cool naturally without the addition of excess cold water
An overheating boiler may exhibit the following conditions:
1. A discharging safety relief valve.
2. Pressure and/or temperature readings above the maximum allowed for the boiler.
3. Low or no water in boilers equipped with water-level gage glasses.
4. Scorched or burning paint on the skin casing.
When a water heater or boiler is overheating, the only safe intervention is to remove the heat source by stopping the supply of fuel or air.
1. Do not try to relieve the pressure.
2. Do not add cool water into the vessel.
3. Do not try to cool the vessel with water.
Let the vessel cool down naturally. Get away from the vessel. Call a qualified repair company.
1. Exterior shell and/or insulation - Look for indications of overheating
2. Leaks - Look for water on the floor or steam escaping
3. Flue gas leaks - Look for black dust (soot) around sheet-metal joints
4. Controls - Look for open panels, covers, and signs of rewiring on floor or bottom of panels
5. Electrical - Ensure that covers are installed on overlimit switches, temperature sensors, and controls
6. Safety valves - Ensure that a safety valve is installed with full-sized discharge piping properly supported and directed to a point of safe discharge
7. Fuel sources - Check for the ability to shut off the fuel source to the vessel
8. Gauges - Make sure temperature and pressure gauges are operational and are located for proper monitoring
9. Proper piping - Check for proper supports and allowance for expansion and contraction
10. Operating certificate - Observe certificate noting last date of inspection and expiration date when required
Post a copy of the air operating permit near the boiler
All boiler operators know how to operate the boiler within the permit limits
At the beginning of each shift, make sure the equipment is operating properly
Boiler operators should be familiar with the boiler’s operating and maintenance manual
Regular service should be performed on schedule and recorded
Operating records and inspection records should be reviewed regularly to ensure compliance
EPA’s Acid Rain Program has established special monitoring and reporting requirements for all units over 25 megawatts and new units under 25 megawatts that use fuel with a sulfur content greater than .05 percent by weight
The new units under 25 megawatts using clean fuels are required to certify their eligibility for an exemption every five years
All existing coal-fired units serving a generator greater than 25 megawatts and all new coal units must use CEM for SO2, NOx, flow, and opacity.
Units burning natural gas may determine SO2 mass emissions by three ways
Units burning oil may monitor SO2 mass emissions by one of the following methods:
1. daily manual oil sampling and analysis plus oil flow meter (to continuously monitor oil usage)
2. sampling and analysis of diesel fuel oil as-delivered plus oil flow meter
3. automatic continuous oil sampling plus oil flow meter
4. SO2 and flow CEMs.
Gas-fired and oil-fired base-loaded units must use NOx CEMs.
Gas-fired peaking units and oil-fired peaking units may either estimate NOx emissions by using site-specific emission correlations and periodic stack testing to verify continued representativeness of the correlations, or use NOx CEMS
All gas-fired units using natural gas for at least 90 percent of their annual heat input and units burning diesel fuel oil are exempt from opacity monitoring
For CO2 all units can use either (1) a mass balance estimation, or (2) CO2 CEMs, or (3) O2 CEMs in order to estimate CO2 emissions
CEM systems include:
An SO2 pollutant concentration monitor
A NOx pollutant concentration monitor
A volumetric flow monitor
An opacity monitor
A diluent gas (O2 or CO2) monitor
A computer-based data acquisition and handling system (DAHS) for recording and performing calculations with the data
CEM systems must be in continuous operation and be able to sample, analyze, and record data at least every 15 minutes and reduce flow data to 1-hour averages.
The CEM rule includes requirements for notification, recordkeeping, and reporting for the Acid Rain Program, such as:
Submission of monitoring plans
Written notifications of monitor certification tests
Report of certification test results in a "certification application“
Recording and maintaining of hourly emissions data, flow data, and other information
Quarterly reports of emissions, flow, unit operation, and monitoring performance data.
The owner or operator also must report the data in a standard electronic format available through the Acid Rain Hotline
Unless otherwise specified by your regulators or permit conditions, it is recommended to keep these records for a minimum of 3 years unless the boiler destroys hazardous waste, then the records must be kept through closure of the boiler
TIPS FOR USING CONTRACTORS
ELEMENTS OF A SUCCESSFUL
INDUSTRIAL BOILER PROGRAM
THE IMPORTANCE OF A
“I would ask all of us to remember that protecting our environment is about protecting where we live and how we live. Let us join together to protect our health, our economy, and our communities -- so all of us and our children and our grandchildren can enjoy a healthy and a prosperous life.”
Carol Browner Former EPA Administrator