Gila River Indian Community (GRIC) TIP Development

Gila River Indian Community (GRIC) TIP Development

Generally Applicable Individual Source Requirements

Technical Support Document

February 23, 2001 Version

Section VI. E. Rule 1 – Fuel Burning Equipment

1.0Introduction and Source Description...... 2

2.0GRIC Source Profile...... 2

3.0Technical Review - Emission Units, Pollutants, and Control Technologies...... 3

3.1Emissions and Controls...... 3

3.2Emission Unit/Pollutant Matrix...... 7

4.0Regulatory Review and Proposed Rule Derivation...... 8

4.1Tribal Programs/Rules...... 8

4.2Federal Programs and Regulations...... 8

4.3State/Regional/Local Regulations...... 9

4.4Analysis of Source Category Emission Limitations and Standards...... 10

4.4.1Summary and Analysis of Identified Rules/Standards...... 10

4.4.2Derivation of Proposed GRIC Source Category Limits/Standards...... 20

5.0Proposed GRIC Fuel Burning Equipment Rule Provisions...... 24

5.1Applicability...... 24

5.2Definitions...... 24

5.3Emission Limitations and Standards...... 27

Section 1.0 - General Limitations and Standards ...... 27

Section 2.0 - Electric Utility Steam Generating Equipment...... 27

Section 3.0 - Industrial, Commercial, and Institutional Boilers, Steam Generators, and Process Heaters 28

Section 4.0 - Stationary Gas Turbines...... 29

Section 5.0 - Stationary Internal Combustion Engines...... 30

Section 6.0 - Used Oil Combustion...... 30

5.4Source Testing and Monitoring...... 31

5.4.1Source Testing Procedures...... 31

5.4.2Monitoring Requirements...... 32

5.4.3Recordkeeping and Reporting...... 36

1.0Introduction & Source Description

Fuel burning equipment represents a diverse, general source category within the GRIC. Sources include both external combustion sources (e.g., process heaters and indirect heat steam generators) and internalcombustion sources (e.g., stationary internal combustion [IC] engines). Categorically, external combustion sources include steam/electric generating plants, industrial boilers, and commercial and domestic combustion units. Coal, fuel oil, and natural gas are the major fossil fuels used by these sources. No utility electric generating stations or large industrial steam generating units (boilers > 100 MMBtu/hr heat input) are located at sources on GRIC land. Currently, GRIC external combustion sources are limited to small and mid-sized natural gas, distillate fuel oil, and waste oil fired process heaters, space heaters, and boilers. Liquefied petroleum fuels are also used in relatively small quantities. External fuel combustion sources emit sulfur oxides (SOX), nitrogen oxides (NOX), and particulate matter (PM/PM10) and products of incomplete combustion, including carbon monoxide (CO), volatile organic compounds (VOC). Trace amounts of hazardous or toxic air pollutants may also be emitted. These are generally related to fuel composition and/or combustion efficiency.

Internal combustion engines are often used in applications similar to those associated with external combustion sources. The major items within this category are gas turbines and general utility reciprocating engines. Most stationary internal combustion engines are used to generate electric power, to pump gas or other fluids, or to compress air for pneumatic machinery. NOX, CO and VOC are the major pollutants of concern from stationary internal fuel combustion sources. Trace quantities of toxic or hazardous organic compounds may also be emitted from internal combustion sources.

2.0GRIC Source Profile

Fuel burning equipment on GRIC land is comprised of small (< 100 MMBtu/hr heat input) industrial boilers, process and space heaters, and stationary internal combustion reciprocating engines. Most sources are fired with either natural gas, liquefied petroleum gas (LPG) or distillate fuel oil. Currently, one GRIC source is known to burn on-specification waste oil in a hot mix asphalt plant dryer.[1] The potential exists for future facilities in this source category locating on GRIC land. Potential future sources include utility electric steam generating units (most likely gas fired combustion turbines).

3.0Technical Review - Emission Units, Pollutants, and Control Technologies[2],[3],[4],[5],[6],[7],[8],[9]

3.1Emissions and Controls

Emissions from fuel combustion depend on the grade and composition of the fuel, the type and size of the boiler, process heater, or IC unit, firing conditions, load, type of control technologies, and the level of equipment maintenance. The major pollutants of concern from fuel combustion are particulate matter (PM), sulfur oxides (SOX), nitrogen oxides (NOX), unburned combustibles, including carbon monoxide (CO), and trace quantities of numerous inorganic and organic compounds, including HAPs. A brief discussion of criteria pollutant emission mechanisms and controls is provided below by pollutant category.

Particulate Matter Emissions

PM composition and emission levels from solid fuel combustion (generally associated with boilers) are a complex function of boiler firing configuration, boiler operation, pollution control equipment, and fuel properties. Uncontrolled PM emissions from solid fuel (e.g., coal) fired boilers include the ash from combustion of the fuel as well as unburned carbon resulting from incomplete combustion. Solid fuel ash may either settle out in the boiler (bottom ash) or be entrained in the flue gas (fly ash). The distribution of ash between the bottom ash and fly ash fractions directly affects the PM emission rate and depends on the boiler firing method and furnace type. Boiler load also affects the PM emissions as decreasing load tends to reduce PM emissions.

For fuel oil, filterable particulate matter emissions depend predominantly on the grade of fuel fired. Combustion of lighter distillate oils results in significantly lower PM formation than does combustion of heavier residual oils. The PM emitted by distillate oil-fired boilers primarily comprises carbonaceous particles resulting from incomplete combustion of oil and is not correlated to the ash or sulfur content of the oil. However, PM emissions from residual oil burning are related to the oil sulfur content. For waste oil combustion without air pollution controls, higher concentrations of ash and trace metals in the waste fuel translate to higher emission levels of PM and trace metals than is the case for virgin fuel oils.

Particulate emissions may be categorized as either filterable or condensable. Filterable emissions are generally considered to be the particles that are trapped by the glass fiber filter in the front half of a Reference Method 5 or Method 17 sampling train. Vapors and particles less than 0.3 microns pass through the filter. Condensable particulate matter is material that is emitted in the vapor state which later condenses to form homogeneous and/or heterogeneous aerosol particles. Condensable PM is typically measured by analyzing the impingers, or "back half" of the sampling train. The collection, recovery, and analysis of the impingers are described in EPA Method 202 of Appendix M, Part 51 of the Code of Federal Regulations. Condensable PM is composed of organic and inorganic compounds and is generally considered to be all less than 1 micrometer in aerodynamic diameter. The condensable particulate emitted from boilers fueled on coal or oil is primarily inorganic in nature.

Because natural gas is a gaseous fuel, filterable PM emissions are typically low. Particulate matter from natural gas combustion has been estimated to be less than 1 micrometer in size and has filterable and condensable fractions. Particulate matter in natural gas combustion is usually larger molecular weight hydrocarbons that are not fully combusted. Increased PM emissions may result from poor air/fuel mixing or maintenance problems.

Particulate Matter Emission Controls

The principal control techniques for PM are combustion modifications and postcombustion add-on controls. Uncontrolled PM emissions from small solid fuel-fired combustion sources can be minimized by employing good combustion practices such as operating within the recommended load ranges, controlling the rate of load changes, and ensuring steady, uniform fuel feed. Proper design and operation of the combustion air delivery systems can also minimize PM emissions. The postcombustion control of PM emissions from fuel combustion sources can be accomplished by using one or more or the following particulate control devices:Electrostatic precipitator (ESP), fabric filter (or baghouse),wet scrubber, cyclone or multiclone collector, or side stream separator. ESPs are commonly used on larger boilers, including coal, wood waste, and residual oil fired units. ESP control efficiencies can range from 70 percent to 99 + percent depending on operating parameters. The operating parameters that influence ESP performance include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and precipitator voltage and current. Other factors that determine ESP collection efficiency are collection plate area, gas flow velocity, and cleaning cycle.

Fabric filtration has been widely applied to fuel combustion sources and consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main shell structure incorporating dust hoppers. The particulate removal efficiency of fabric filters is dependent on a variety of particle and operational characteristics. Particle characteristics that affect the collection efficiency include particle size distribution, particle cohesion characteristics, and particle electrical resistivity. Operational parameters that affect fabric filter collection efficiency include air-to-cloth ratio, operating pressure loss, cleaning sequence, interval between cleanings, cleaning method, and cleaning intensity. Collection efficiencies of fabric filters can be as high as 99.9 percent.

Wet scrubbers, including venturi and flooded disc scrubbers, tray or tower units, turbulent contact absorbers, or high-pressure spray impingement scrubbers are applicable for PM as well as SO2control on fuel oil and coal-fired combustion sources. Scrubber collection efficiency depends on particle size distribution, gas side pressure drop through the scrubber, and water (or scrubbing liquor) pressure, and can range between 95 and 99 percent for a 2-micron particle. Mechanical cyclone separators can be installed singly, in series, or grouped as in a multicyclone or multiclone collector. These devices are referred to as mechanical collectors and are often used as a precollector upstream of an ESP, fabric filter, or wet scrubber so that these devices can be specified for lower particle loadings to reduce capital and/or operating costs. The collection efficiency of a mechanical collector depends strongly on the effective aerodynamic particle diameter. Although these devices will reduce PM emissions from coal combustion, they are relatively ineffective for collection of particles less than 10 micron (PM-10).

Sulfur Dioxide Emissions

SOXfrom fuel combustion are primarily sulfur dioxide (SO2), with a much lower quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the sulfur compounds present in the fuel are oxidized during the combustion process. On average, 95 percent or more of the sulfur present in fossil fuel is emitted as gaseous SOX, whereas less will be emitted when the ash is more alkaline in nature such as with some subbituminous coals or wood waste fuels. For fuel oil combustion sources, uncontrolled SOXemissions are almost entirely dependent on the sulfur content of the fuel and are not affected by boiler size, burner design, or grade of fuel being fired. On average, more than 95 percent of the fuel sulfur is converted to SO2, about 1 to 5 percent is further oxidized to sulfur trioxide (SO3), and 1 to 3 percent is emitted as sulfate particulate. SO3readily reacts with water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist.

Emissions of SO2from natural gas-fired sources are low because pipeline quality natural gas typically has sulfur levels of 2,000 grains per million cubic feet. However, sulfur-containing odorants are added to natural gas for detecting leaks, leading to small amounts of SO2emissions.

Sulfur Dioxide Emission Controls

Post combustion flue gas desulfurization (FGD) techniques can remove SO2formed during combustion by using an alkaline reagent to absorb SO2in the flue gas. Flue gases can be treated using wet, dry, or semi-dry desulfurization processes of either the throwaway type (in which all waste streams are discarded) or the recovery/regenerable type (in which the SO2absorbent is regenerated and reused). To date, wet systems are the most commonly applied. Wet systems generally use alkali slurries as the SO2absorbent medium and can be designed to remove greater than 90 percent of the incoming SO2. Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the commercially proven wet FGD systems. The effectiveness of these devices depends not only on control device design but also on operating variables. Particulate reduction of more than 99 percent is possible with wet scrubbers on coal fired units, but fly ash is often collected by upstream ESPs or baghouses, to avoid erosion of the desulfurization equipment and possible interference with FGD process reactions. For fuel oil-fired units, these systems can achieve SO2removal efficiencies of 90 to 95 percent and particulate control efficiencies of 50 to 60 percent.

Nitrogen Oxides Emissions

Oxides of nitrogen (NOX) formed in combustion processes are due either to thermal fixation of

atmospheric nitrogen in the combustion air ("thermal NOX"), or to the conversion of chemically bound nitrogen in the fuel ("fuel NOX "). The term NOXrefers to the composite of nitric oxide (NO) and nitrogen dioxide (NO2). Test data have shown that for most external fossil fuel combustion systems, over 95 percent of the emitted NOXis in the form of nitric oxide (NO). Experimental measurements of thermal NOXformation have shown that NOXconcentration is exponentially dependent on temperature, and proportional to N2concentration in the flame, the square root of O2concentration in the flame, and the residence time. Thus, the formation of thermal NOXis affected by four factors: (1) peak temperature, (2) fuel nitrogen concentration, (3) oxygen concentration, and (4) time of exposure at peak temperature. The emission trends due to changes in these factors are generally consistent for all types of boilers: an increase in flame temperature, oxygen availability, and/or residence time at high temperatures leads to an increase in NOXproduction.

Fuel nitrogen can account for up to 80 percent of total NOXfrom coal combustion. Fuel nitrogen conversion is the more important NOXforming mechanism in residual oil boilers as well. It can account for 50 percent of the total NOXemissions from residual oil firing. Thermal fixation, on the other hand, is the dominant NOXforming mechanism in units firing distillate oils, primarily because of the negligible nitrogen content in these lighter oils. The principal mechanism of NOXformation in natural gas combustion is also thermal NOX.

The predominant mechanism with internal combustion engines is thermal NOX. Most thermal NOXis formed in the high-temperature region of the flame from dissociated molecular nitrogen in the combustion air. Some NOX, called prompt NOX, is formed in the early part of the flame from reaction of nitrogen intermediary species, and HC radicals in the flame. Gasoline, and most distillate oils have no chemically bound fuel N2and essentially all NOXformed is thermal NOX.

Nitrogen Oxides Emission Controls

The primary NOX control techniques can be classified into one of two fundamentally different methods, combustion controls and postcombustion controls. Combustion controls reduce NOXby suppressing NOXformation during the combustion process, while postcombustion controls reduce NOXemission after their formation. Combustion controls are the most widely used method of controlling NOXformation in all types of boilers and include low excess air, burners out of service, biased-burner firing, flue gas recirculation, overfire air, and low-NOXburners. Postcombustion control methods include selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR). To reduce fuel NOXformation, the most common combustion modification technique is to suppress combustion air levels below the theoretical amount required for complete combustion. The lack of oxygen creates reducing conditions that, given sufficient time at high temperatures, cause volatile fuel nitrogen to convert to N2rather than NO.

There are three generic types of emission controls in use for gas turbines, wet controls using steam or water injection to reduce combustion temperatures for NOXcontrol, dry controls using advanced combustor design to suppress NOXformation and/or promote CO burnout, and post-combustion catalytic control to selectively reduce NOXand/or oxidize CO emission from the turbine. For IC reciprocating engines, control measures to date are primarily directed at limiting NOXand CO emissions since they are the primary pollutants from these engines. From a NOXcontrol viewpoint, the most important distinction between different engine models and types of reciprocating engines is whether they are rich-burn or lean-burn. The most common NOX control techniques for diesel and dual fuel engines are focused on modifying the combustion process. However, SCR and SNCR are becoming available.

Carbon Monoxide Emissions and Organic Compounds Emissions

The rate of CO emissions from combustion sources depends on the fuel oxidation efficiency of the source. By controlling the combustion process carefully, CO emissions can be minimized. Thus, if a unit is operated improperly or is not well maintained, the resulting concentrations of CO (as well as organic compounds) may increase by several orders of magnitude. Smaller boilers, heaters, and furnaces typically emit more CO and organics than larger combustors. This is because smaller units usually have less high-temperature residence time and, therefore, less time to achieve complete combustion than larger combustors. Combustion modification techniques and equipment used to reduce NOXcan increase CO emissions if the modification techniques are improperly implemented or if the equipment is improperly designed.

As with CO emissions, the rate at which organic compounds are emitted depends on the combustion efficiency of the boiler. Therefore, combustion modifications that change combustion residence time, temperature, or turbulence may increase or decrease concentrations of organic compounds in the flue gas. Organic emissions include volatile, semivolatile, and condensable organic compounds either present in the fuel or formed as a product of incomplete combustion (PIC). Organic emissions are primarily characterized by the criteria pollutant class of unburned vapor-phase hydrocarbons. These emissions include alkanes, alkenes, aldehydes, alcohols, and substituted benzenes. The remaining organic emissions are composed largely of compounds emitted from combustion sources in a condensed phase. These compounds can almost exclusively be classed into a group known as polycyclic organic matter (POM), and a subset of compounds called polynuclear aromatic hydrocarbons (PNA or PAH).