Gila River Indian Community (GRIC) TIP Development 

Generally Applicable Individual Source Requirements 

Technical Support Document 

Section F/I . E . Rule 1 -Fuel Burning Equipment 

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

2.0 GRIC Source Profile ............................................................................................................ 2 

3.0 Technical Review . Emission Units. Pollutants. and Control Technologies ....................... 3 . . 3.1 Emssions and Controls ............................................................................................ 3 

3.2 Emission UnitfPollutant Matrix ............................................................................... 7 

4.0 Regulatory Review and Proposed Rule Derivation ............................................................ L8 

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

4.2 Federal Programs and Regulations ........................................... i. ............................ -8 

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

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

4.4.1 Summary and Analysis of Identified RulesIStandards ...................................... 10 

4.4.2 Derivation of Proposed GRIC Source Category LimitsIStandards ................... 20 

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

5.1 Applicability ......................................................................................................... -24 

5.2 Definitions ............................................................................................................. -24 

5.3 Emission 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 

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

5.4.1 Source Testing Procedures ......................................................................... 31 

5.4.2 Monitoring Requirements ......................................................................... -32 

5.4.3 Recordkeeping and Reporting ................................................................... -36 

fuel burning TSD 6-14-02 Created on 6118R002 9:32:00 AM 
1.0 Introduction & Source Description 

Fuel burning equipment represents a diverse, general source category within the GRTC. Sources 

include both external combustion sources (e.g., process heaters and indirect heat steam 

generators) and intemal combustion 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 GRTC land. 

Currently, GRTC exted combustion sources are limited to smaU and mid-sized natural gas, 

distillate fuel oil, and waste oil fied process heaters, space heaters, and boilers. Liquefied 

petroleum fuels are also used in relatively small quantities. External fuel combustion sources 

emit sulfur oxides (S*), nitrogen oxides (NOx), and particulate matter (PMIPM10) 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 andlor 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. N& 

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 &om 

internal combustion sources. 

2.0 GRIC 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 intemal combustion reciprocating 

engines. Most sources are fired with either natural gas, liquefied petroleum gas (LPG) or 

distillate fuel oil. Currently, one GRTC source is known to bum on-specification waste oil in a 

hot mix asphalt plant dryer.' The potential exists for future facilities in this source category 

locating on GRTC land. Potential future sources include utility electric steam generating units 

(most likely gas fired cumbustion turbines). 

1 United Metro Plant No. 4 1 

fuel burning TSD 6-14-02 Created on 6118r2002 9:32:00 AM 
23456789 3.0 Technical Review - Emission Units, Pollutants, and Control Technologies ' ' ' ' ' ' ' 

3.1 Emissions 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 fiom fuel combustion 

are particulate matter (PM), sulk 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 fiom solid fuel (e.g., coal) fired 

boilers include the ash fiom combustion of the fuel as well as unburned carbon resulting fiom 

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 

hctions 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 sulfk content of the oil. However, PM emissions fiom residual oil 

burning are related to the oil sulk 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 he1 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 particle 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 andlor heterogeneous aerosol particles. 

Condensable PM is typically measured by analyzing the impingers, or "back half' of the 

U.S. EPA AP-42 Fifth Edition Section 1.1, Bituminous and Subbituminous Coal Combustion- September 1998. 

3 U.S. EPA AP-42 Fifth Edition Section 1.3, Fuel Oil Combustion. September, 1998. 

U.S. EPA AP-42 Fifth Edition Section 1.4, Natural Gas Combustion. July, 1998. 

U.S. EPA AP-42 Fifth Edition Section 1.1 1, Waste Oil Combustion. October 1996. 

U.S. EPA AP-42 Fifth Edition Section 3.1, Stationary Gas Turbines. April 2000. 

7 U.S. EPA AP-42 Fifth Edition Section 3.2, Natural Gas-fired Reciprocating Engines. February 1997. 

* U.S. EPA AP-42 Fifth Edition Section 3.3, Gasoline and Diesel Industrial Engines. October 1996. 9 U.S. EPA AP-42 Fifth Edition Section 3.4, Large Stationary Diesel and All Stationary Dual -6red Engines. 

October 1996. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 3 
sampling train. The collection, recovery, and analysis of the impingers are described in EPA 

Method 202 of Appendix M, Part 5 1 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 fiom natural gas combustion has been estimated to be less than 1 micrometer in size and 

has filterable and condensable hctions. Particulate matter in natural gas combustion is usually 

larger molecular weight hydrocarbons that are not fully combusted. Increased PM emissions may 

result fiom poor aidfuel mixing or maintenance problems. 

Particulate Matter Emission Controls 

The principal control techniques for PM are combustion modifications and postcombustion addon controls. Uncontrolled PM emissions fiom 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 ofthe combustion air delivery systems can also minimize PM emissions. 

The postcombustion control of PM emissions fiom 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 hm 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 SO2 control 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 

fuel burning TSD 6-14-02 Created on 611812002 9:32:00 AM 4 
specified for lower particle loadings to reduce capital andfor operating costs. The collection 

efficiency of a mechanical collector depends strongly on the effective aerodynamic particle 

diameter. Although these devices will reduce PM emissions fiom coal combustion, they are 

relatively ineffective for collection of particles less than 10 micron (PM-10). 

Sulfur Dioxide Emissions 

SOx fiom 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 Se, 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 SOX emissions 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 sulh is converted to SO2, about 1 to 5 

percent is Mer oxidized to sulfur trioxide (SO3), and 1 to 3 percent is emitted as &ate 

particulate. SO3 readily reacts with water vapor (both in the atmosphere and in flue gases) to 

form a sulfuric acid mist. 

Emissions of SO2 fiom naturd gas-fired sources are low because pipeline quality natural gas 

typically has sulk levels of 2,000 grains per milion cubic feet. However, sulk-containing 

odorants are added to natural gas for detecting leaks, leading to small amounts of SO2 emissions. 

Sulfur Dioxide Emission Controls 

Post combustion flue gas desulfkization (FGD) techniques can remove SO2 formed during 

combustion by using an alkaline reagent to absorb SO2 in 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 recoverylregenerable type (in which the SO2 absorbent is 

regenerated and reused}. To date, wet systems are the most commonly applied. Wet systems 

generally use alkali slurries as the SO2 absorbent medium and can be designed to remove greater 

than 90 percent of the incoming SO2. Lirne/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 

desulfhization equipment and possible interference with FGD process reactions. For fuel oilfired units, these systems can achieve SO2 removal efficiencies of 90 to 95 percent and 

particulate control efficiencies of 50 to 60 percent. 

Nitrogen Oxides Emissions 

Oxides of nitrogen (NO& 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 he1 ("fuel NOx "). The term NOx refers to the composite of nitric oxide 

(NO) and nitrogen dioxide (NOz). Test data have shown that for most external fossil fuel 

combustion systems, over 95 percent of the emitted N& is in the form of nitric oxide (NO}. 

Experimental measurements of thermal NOx formation have shown that NOx concentration is 

exponentially dependent on temperature, and proportional to N2 concentration in the flame, the 

fuel burning TSD 6-14-02 Created oa 6118i2002 9:32:00 AM 5 
square root of O2 concentration in the flame, and the residence time. Thus, the formation of 

thermal NOx is 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 N& production. 

Fuel nitrogen can account for up to 80 percent of total N& £?om coal combustion. Fuel nitrogen 

conversion is the more important NOx forming mechanism in residual oil boilers as well. It can 

account for 50 percent of the total N& emissions £?om residual oil firing. Thermal fixation, on 

the other hand, is the dominant NOx forming mechanism in units firing distillate oils, primarily 

because of the negligible nitrogen content in these lighter oils. The principal mechanism of Nq( 

formation in natural gas combustion is also thermal NOx. 

The predominant mechanism with internal combustion engines is thermal N&. Most thermal 

N& is formed in the high-temperature region of the flame from dissociated molecular nitrogen 

in the combustion air. Some N&, called prompt N&, is formed in the early part of the flame 

hm reaction of nitrogen intermediary species, and HC radicals in the flame. Gasoline, and most 

distillate oils have no chemically bound fuel Nz and essentially all N& formed is thermal N&. 

Nitrogen Oxides Emission Controls 

The primary Nq( control techniques can be classified into one of two fundamentally different 

methods, combustion controls and postcombustion controls. Combustion controls reduce NOx by 

suppressing N& formation during the combustion process, while postcombustion controls 

reduce NOx emission after their formation. Combustion controls are the most widely used 

method of controlling N& formation in all types of boilers and include low excess air, burners 

out of service, biased-burner firing, flue gas recirculation, overfire air, and low-NOx burners. 

Postcombustion control methods include selective noncatalytic reduction (SNCR) and selective 

catalytic reduction (SCR). To reduce fuel N& formation, 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 ht, given 

sufficient time at high temperatures, cause volatile fuel nitrogen to convert to N2 rather 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 N& control, dry controls using 

advanced combustor design to suppress N& formation andfor promote CO bumout, and postcombustion catalytic control to selectively reduce NOx andlor oxidize CO emission from the 

turbine. For IC reciprocating engines, control measures to date are primarily directed at limiting 

NOx and CO emissions since they are the primary pollutants £?om these engines. From a N& 

control 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 N& control 

techniques for diesel and dual fuel engines are focused on modifling the combustion process. 

However, SCR and SNCR are becoming available. 

fuel burning TSD 6-14-02 Created on 611812002 9:32:00 AM 
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 NOx can 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 wmpunds 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 corn@ largely of 

compounds emitted fiom 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 compnds called plynuclear aromatic hydrocarbons (PNA or PAH). 

3.2 Emission UnitPollutant Matrix 

Emission units and pollutants associated with external and internal fuel combustion sources are 

presented in Table 3-1. 

Table 3 - 1. Emission UnitPollutant Matrix 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 

Source Subcategory 

Coal combustion 

Fuel oil & combustion 

Natural gas & LPG 

combustion 

Waste oil combustion 

Wood waste combustion 

Stationary gas turbines 

Gas/diesel fired stationary 

IC engines 

Emission Unit/ Process 

Boilers: pulverized coal, cyclone, 

stoker, fluidized bed, hand-fed units 

Boilers/Furnaces; Process heaters 

Boilers/Furnaces; Process heaters 

BoilerdFurnaces; Process heaters 

Boilers; Burners 

Natural gas andlor distillate fuel fired 

combustion turbines: simple cycle, 

regenerative cycle, cogeneration cycle, 

combined cycle 

Generators, pumps, etc. 

PollutantfParameter 

PMA'MI 0, SO2, NOx, CO, 

VOC, HAP 

PMA'MIO, SO2, NOx, CO, 

Voc, HAP 

NOx, CO, VOC, SO2, PMI 0, 

trace HAP 

PM/PM10, SOz, NOx, CO, 

Voc, HAP 

PMA'MIO, SO2, N& CO, 

VOC, HAP 

NOx, CO, VOC, SO2, PM10, 

HAP 

NOx, CO, VOC. SO2, PM 10, 

HAP 
4.0 Regulatory Review and Proposed Rule Derivation 

4.1 Tribal ProgramsIRules 

A comprehensive review of U.S. tribal air quality programs was performed to define the baseline 

of existing tribal rules and source specific standards. The summary findings of this review are 

contained in a separate report. Where tribal rules and standards were identified that were 

applicable to GRIC source categories or met GRIC regulatory objectives, those provisions and 

requirements are detailed herein. 

No tribal programs or rules were identified that pertain to fuel burning equipment. 

4.2 Federal Programs and Regulations 

Three NSP Standards were identified as applicable to the fbel combustion equipment source 

category as defined in this document. Those standards are: 

NSPS Subpart D - Standards of Performance for Fossil Fuel Fired Steam Generators for 

Which Construction is Commenced After August 17,197 1 

NSPS Subpart Da - Standards of Performance for Electric Utility Steam Generating Units for 

Which Construction is Commenced After September 18,1978 

NSPS Subpart Db - Standards of Performance for Industrial-Cornexid-Institutional Steam 

Generating Units 

NSPS Subpart Dc - Standards of Performance for Small Industrid-Cornexid-Mtutional 

Steam Generating Units 

NSPS Subpart GG - Standards of Performance for Stationary Gas Turbines 

Although no promulgated EPA HAP standards currently exist, EPA has targeted several fbel 

combustion source categories for NESHAP (MACT) standard development. These standards are 

scheduled for promulgation in 200 1 and 2002 and include: 

Subpart YYYY (Reserved) Combustion (Gas) Turbines 

Subpart DDDDD (Reserved) Industrial, Commercial and Institutional Boilers and Process 

Heaters 

Reciprocating Internal Combustion Engines (RICE) 

No GRIC sources within the fuel combustion equipment category are major sources of HAP (i.e., 

emissions > 10 tpy for a single HAP or > 25 tpy for total combined HAP). It is not expected that 

the MACT standards will apply to any current GRIC sources. 

The GRIC DEQ has elected to incorporate by reference the provisions of the Clean Air Act Title 

IV Acid Rain Program (40 CFR Parts 72-78) into the proposed TIP. This program limits SO2 and 

NOx emissions fiom electric utilities to reduce acid rain. These requirements were not reviewed 

for the development of this TSD. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Relevant federal regulatory standards affecting fuel combustion equipment are summarized in 

Section 4.4, Analysis of Source Category Emission Limitations and Standards. 

4.3 State/Regional/Local Regulations 

To define State, regional, and local air quality rules applicable to the source categories present or 

expected to potentially site on GRIC land, representative U.S. State air quality rules were 

screened using Internet resources. This screening identified each State air quality rule set with 

source specific regulations matching the matrix of GRIC source categories. The summary State 

rule screening file, STATEMATRIX.xls, is included in the RTP file set developed for the GRIC 

TIP project. From this, specific rule provisions applicable to the fuel combustion equipment 

source category, including emission limitations, standards, monitoring, recordkeeping and 

reporting were documented to form a baseline of analogous State rules. Because of the broad 

representation of StateLocal rules affecting fuel combustion equipment, only a subset of 

programs were reviewed. StateRegionaULocal rules were selected for consideration in TIP 

development based on stringency, technical merit (e.g., units, averaging times, etc.), 

presentation, and enforceability considerations. The following StateRegionaVLocal programs 

were reviewed: 

Arizona Air Regulations - Rule R18-2-703: Standards of Performance for Existing Foss-il-fuel Fired Steam 

Generators and General Fuel-burning Equipment - Rule R18-2-724: Standards of Performance for Fossil-fuel Fired Industrial and 

Commercial Equipment 

Maricopa County Air Regulations - Rule 3 1 1 : Particulate Matter hm Process Industries 

- Rule 320: Odors and Gaseous Air Contaminants 

Pinal County Air Regulations - Chapter 5; Article 21: Fossil Fuel-Fired Industrial and Commercial Equipment 

- Chapter 5; Article 22: Fossil-Fuel Fired Steam Generators 

- Chapter 5; Article 23 Stationary Rotating Machinery 

California Air Resources Board 

Bay Area Air Quality Management District Air Regulations 

- Regulation 9, Rule 1 : Sulfur Dioxide 

- Regulation 9, Rule 3: Nitrogen Oxides from Heat Transfer Operations 

- Regulation 9, Rule 6: Nitrogen Oxides Emissions from Natural Gas-Fired Water 

Heaters - Regulation 9, Rule 7: Nitrogen Oxides and Carbon Monoxide from Industrial, 

Institutional, and Commercial Boilers, Steam Generators, and Process Heaters - Regulation 9, Rule 8: Nitrogen Oxides and Carbon Monoxide from Stationary 

Internal Combustion Engines - Regulation 9, Rule 9: Nitrogen Oxides from Stationary Gas Turbines 

- Regulation 9, Rule 1 1 : Nitrogen Oxides and Carbon Monoxide from Electric 

Power Generating Steam Boilers 

California Air Resources Board 

South Coast Air Quality Management District Air Regulations 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
- Rule 1 1 10: Emissions from Stationary Internal Combustion Engines 

- Rule 1 1 1 1 : NOx Emissions from Natural-Gas-Fired, Fan-Type Central Furnaces 

- Rule 1 121 : Control of Nitrogen Oxides from Residential-Type, Natural-GasFired Water Heaters - Rule 1 134: Emissions of Oxides of Nitrogen from Stationary Gas Turbines 

- Rule 1 135 Emissions of Oxides of Nitrogen from Electric Power Generating 

Equipment - Rule 1 146 Emissions of Oxides of Nitrogen from Industrial, Institutional, and 

Commercial Boilers, Steam Generators, and Process Heaters 

- Rule 1 146.1 Emissions of Oxides of Nitrogen from Small Industrial, Institutional, 

and Commercial Boilers, Steam Generators, and Process Heaters - Rule 1146.2 Emissions of Oxides of Nitrogen from Large Water Heaters and 

Small Boilers 

Georgia Air Regulations 

- Rule (d): Fuel-burning Equipment 

- Rule (g): Sulfur Dioxide - Rule a): N& Emissions from Electric Utility Steam Generating Units 

- Rule (111): N& Emission$ from Fuel-Burning Equipment 

- Rule (mmm): N& Emissions from Stationary Gas Turbines and Stationary 

Engines used to Generate Electricity 

r Oregon Air Regulations 

- Division 228: Requirements for Fuel Burning Equipment and Fuel Sulfbr 

Content 

New Jersey Air Regulations - Subchapter 3: Control and Prohibition of Smoke from Combustion of Fuel 

- Subchapter 4: Control and Prohibition of Particles from Combustion of Fuel 

- Subchapter 9: Sulfbr in Fuels 

- Subchapter 10: Sulfur in Solid Fuels 

- Subchapter 16: Control and Prohibition of Air Pollution by Volatile Organic 

Compounds (1 6.8, 16.9, 16.10) 

- Subchapter 19: Control and Prohibition of Air Pollution from Oxides of Nitrogen 

- Subchapter 20: Used Oil Combustion 

North Carolina Air Regulation 

- Rule 2D. 0501 

Relevant emission standards and limitations from these programs are summarized in Section 4.4, 

Analysis of Source Category Emission Limitations and Standards. 

4.4 Analysis of Source Category Emission Limitations and Standards 

4.4.1 Summary and Analysis of Identified RulesIStandards 

In order to evaluate the range of existing tribal, federal, state, and local air quality standards 

relevant to the fuel burning equipment source category and make GRIC TIP recommendations, a 

subset of the available data set was condensed and organized by emission source subcategory 

and pollutant/parameter. Presented in Table 4-1 is a summary of selected existing standards for 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 10 
fuel burning equipment. Note that emission limits expressed as heat input driven equations 

(mainly particulate matter limitations) were not considered. Equation based limitations are 

difficult to correlate with available control technologies and reasonably available control system 

removal efficiencies. Generally, heat input based emission limit equations are found in old (i.e., 

pre-1990) state rule provisions. Quation based PM limitations are not consistent with NSPS, 

BACT, and other more recent regulatory formats. They are generally less stringent and largely 

irrelevant to current installations. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Table 4-1. Summary of Emission Limits and Standards: 

Fuel Burning Equipment 

10 Note: New NOx limits only reported (Adopted May 17,2000). Interim compliance limits not reported. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 12 

Source (Reference) 

NSPS Subpart Da 

Georgia Rule (d) 

NSPS Subpart Da 

Maricopa Rule 

311; 

Pinal County Ch. 5 

Article 22; 

Arizona Rule 703 

NSPS Subpart Da 

Maricopa Rule 320 

Pinal County Ch. 5 

Article 22 

Arizona Rule 703 

NSPS Subpart Da 

Maricopa Rule 320 

Pinal County Ch. 5 

Article 22 

Arizona Rule 703 

Georgia Rule (jj) 

SCAQMD Rule 

1135 

BAAQMD 

Rule 9-1 1' 

Emission Limits/Standards/Controls 

20 % (27 % for one 6-minute periodh) 

20 % (27 % for one 6-minute periodh) 

0.03 lb/MMBtu 

Heat input based equation limitation 

0.80 lb/MMBtu (gaseous or liquid fossil fuel) 

1.2 lb/MMBtu (solid fossil fuel) 

0.80 lb/MMBtu (low sulfur oil, after 1972) 

1 

1.0 lb/MMBtu (low sulfur oil, before 1972) 

0.80 1bIMMBtu (oil and coal, after 1975) 

1 .O lb/MMBtu (oil and coal, before 1975) 

0.80 1bIMMBtu (low sulfur oil, after 1972) 

1 .O lb/MMBtu (low sulfur oil, before 1972) 

2.2 lb/MMBtu (high sulfur oil) 

0.80 lb/MMBtu (coal, after 1972) 

1.0 lb/MMBtu (coal, before 1972) 

0.20 lb/MMBtu (natural gas) 

0.30 lb/MMBtu (fuel oil) 

0.50/0.60 Ib/MMBtu (bituminous and sub -bituminous 

coal, respectively) 

1.6 lb/MW-hr gross energy output (sources constructed 

after 71911 997) 

0.15 lb/MMBtu (sources modified after 7/91 1997) 

0.20 lb/MMBtu (gaseous fossil fuel, 3-hr avg.) 

0.30 lb/MMBtu (liquid fossil fuel 3-hr avg.) 

0.20 lb/MMBtu (gaseous fossil fuel 2-hr avg.) 

0.30 lb/MMBtu (liquid fossil fuel, 2-hr avg.) 

0.70 IbIMMBtu (solid fossil fuel, 2-hr avg.) 

0.20 Ib/MMBtu (natural gas) 

0.30 1bfMMBtu (he1 oil) 

0.70 lWMMBtu (coal) 

0.15 Ib/MMBtu (after May 1,2003) 

0.30 lb/MMBtu (after May 1,2000) 

0.34 lWMMBtu (after May 1,1999) 

0.15 - 0.20 lb/MW-hr (phased emission limit schedule, 

after December 3 1, 1999) 

10,25,30 ppmvd @ 3% Oz (Units > = 1.75 billion 

BTU/hr, < 1.75 > = 1.5, < 1.5, respectively, gaseous 

fuel) 

25,110,110 ppmvd @ 3 % O2 (same as above, nongaseous fuel) 

Source 

Sub-category 

Electric Utility 

Boilers 

Pollutant/ 

Parameter 

opacity 

PM 

so2 

NOx 
Sub-category 

Fuel Burning 

Equipment 

150 -250 

Burning 

Equipment 

> 100 MMBtu/hr 

pollutant/ 

Parameter 

VOC 

CO 

Opacity 

Opacity 

Emission Limits/Standards/ControIs 

Coal - Wet Bottom 

= Cyclone; 0.60 lb/MMBtu 

Face & Tangential: 1.0 1bIMMBtu 

Coal - Dry Bottom 

Cyclone: 0.55 lb/MMBtu 

Face: 0.45 lb/MMBtu 

Tangential: 0.38 lb/Mh4Btu 

Oil and lor Gas 

Cyclone: 0.43 lb/MMBtu 

Face: 0.28 lb/MMBtu 

Tangential: 0.20 lb/MMBtu 

Gas Only 

Cyclone: 0.43 lb/MMBtu = ace & Tangential: 0.20 IbJMMBtu 

50 ppmvd @ 7 % O2 

100 ppmvd @ 7 % 02 

400 ppmvd @ 3 % O2 (steady state compliance tests) 

1000 ppmvd @ 3 % O2 (normal operation) clock hour 

average 

20 % (27 % for one 6-minute periodihr) 

0.10 lb/MMJ3< 

0.80 lb/MMBtu (fbel oil & wood) 

1.2 lb/MMBtu (coal & wood) 

0.80 lb/MMBtu (fbel oil & wood) 

1.2 IblMMBtu (coal & wood) 

0.80 lb/MMBtu max. 2-hr. avg. (liquid fbel) 

1.2 lb/MMBtu max. 2-hr. avg. (solid fuel) 

0.80 Ib/MMBtu (low sulfur oil, after 1972) 

1.0 IbIMMBtu (low sulfur oil, before 1 972) 

2.2 lb/MMBtu (high sulk oil) 

0.20 lb/MMBtu (natural gas) 

0.30 lb/MMBtu (fuel oil or gadfuel oil with wood) 

0.70 lb/MMBtu (solid fossil fuel or solid fossil fuel & 

wood) 

0.20 lb/MMBtu (natural gas) 

0.30 lb/MMBtu (he1 oil) 

0.70 lb/MMBtu (coal) 

1.4 lb/MMBtu, max. 2-hr. avg. (liquid fuel) 

1.6 lb/MMBtu, max. 2-hr. avg. (solid &el) 

20 % (27 % for one 6-minute periodihr) 

3.0510.1010.20 Ib/MMBtu (coal or coal with other 

fuels, depending on capacity factor) 

3.10 lb/MMBtu (fuel oil or oil and other fuels) 

Source (Reference) 

NJAC 7:27-19 

NJAC 7:27- 16.8 

BAAQMD 

Rule 9-1 1 

NSPS Subpart D 

NSPS Subpart D 

Georgia Rule (d) 

NSPS Subpart D 

Georgia Rule (g) 

Oregon Div. 228 

Arizona Rule 703 

NSPS Subpart D 

Georgia Rule (d) 

Oregon Div. 228 

NSPS Subpart Db 

fuel buming TSD 6-14-02 Created on 6/184002 9:32:00 AM 
Sub-category Parameter 

I"" 

Industrial and 

Commercial 

Equipment 

> 500,000 Btu/hr 

(WiWegate) 

< 250 MMBtu/hr 

Industrial, 

Institutional, and 

Commercial 

Boilers, Steam 

Generators, and 

hocess Heaters 

I 

0.1010.20 lb/MMBtu (wood/municipal solid waste, 

Emission LimitsIStandardslControIs 

depending on capacity factor) 

0.80 lb/MMBtu (gaseous or liquid fossil fuel) 

1.2 lb/MMBtu (solid fossil fuel) 

Source (Reference) 

Natural gasldistillate oil 1 

0.10 lb/MMBtu (low heat release rate) 

0.20 IblMMBtu (high heat release rate) 

Residual oil 

0.30 Ib/MMBtu (low heat release rate) 

0.40 Ib/MMBtu (high heat release rate) 

Coal: 0.50 - 0.80 lb/MMBtu (depending on coaVboiler 

type) 

All fuels: 0.20 lbA4Ml3tu if constructed aRer July 9, 

1997 

Coal - Wet Bottom 

Cyclone: 0.60 IbIMMBtu 

Face & Tangential: 1.0 Ib/MMBtu 

Coal - Dry Bottom 

Cyclone: 0.55 IblMMBtu 

Face: 0.45 lb/MMBtu 

Tangential: 0.38 lb/MMl3tu 

Oil and/or Gas 

Cyclone: 0.43 lb/MMBtu 

Face: 0.28 lb/MMBtu 

Tangential: 0.20 IbIMMBtu 

Gas Only 

Cyclone: 0.43 lb/MMBtu 

NJAC 7:27-19 

100 ppmvd @, 7 % 02 I 

1 .O Ib/MMBtu (low sulfur oil) I Arizona Rule 724 

 ace & Tangential: 0.20 IbIMMBtu 

50 ppmvd @, 7 % O2 

2.2 Ib/MMBtu (high sulfur oil) 

Permit renewal or modification triggers condition 

prohibiting use of high sulf. oil (unless demonstrated 

infeasible by source) 

1.0 lb/MMBtu (coal) 

NJAC 7:27-16.8 

>= 5 MMBtu/hr and greater than 9E+9 Btu/yr fuel use: 

40 ppmvd (0.05 Ib/MMBtu heat input) 

>= 5 MMBtulhr and less than 9E+9 Btulyr fuel use: 

Maintain stack O2 =< 3 % dry basis for any 

15-min. consecutive averaging period, or 

Tune-up at least twice per year 

>= 40 MMBtu/hr and greater than 25% annual capacity 

factor: 

30 ppmvd 

>= 40 MMBtu/hr and greater than 25% annual capacity 

factor and greater than 9E+9 Btu/yr fuel use: 

SCAQMD Rule 

I146 

40 ppmvd 

Gaseous Fuel >= 10 MMBtu/hr ( BAAQMD 

30ppmvd@3%O2 

Non-Gaseous Fuel >= 10 MMBtu/hr 

40 ppmvd @ 3% O2 

Rule 9-7 

fuel burning TSD 6-14-02 Created on 611 812002 9:32:00 AM 14 
fuel burning TSD 6-14-02 Created on 611 812002 9:32:00 AM 15 

Source (Reference) 

SCAQMD Rule 

1 146 & BAAQMD 

Rule 9-7 

NJAC 7:27-19 

Emission Limits/Standards/Controls 

400 ppmvd 

Coal - Wet Bottom 

Cyclone: 0.55 IblMMBtu 

Face & Tangential: 1.0 lb/MMBtu 

Coal - Dry Bottom 

Cyclone: 0.55 lb/MMBtu 

Face: 0.43 lb/MMBtu 

Tangential:0.38lb/MMBtu 

No. 2 Fuel Oil 

0.12 lb/MMBtu 

Other Liquid Fuels 

0.3 lb/MMBtu 

Natural Gas 

--- 0.1 lb/MMBtu 

Source 

Sub-category 

Non-utility 

Boilers and other 

indirect heat 

exchangers 

>=20 MMBtuh 

< 50 MMBtu/hr 

Pollutant1 

Parameter 

CO 

No, 

Fuel Burning 

Equipment 

> 10 MMBtuh 

> 1OMMBtuh 

< 250 MMBtu/hr 

Fuel Burning 

Equipment 

> 10 MMBtu/hr 

< 100 MMBtuh 

Fuel Burning 

Equipment 

< 10 MMBtuh 

Large Water 

Heaters & Small 

Boilers 

sma~ndustn'al, 

Institutional, and 

Commercial 

Boilers, Steam 

Generators, and 

Process Heaters 

Fuel Burning 

PM 

No, 

Opacity 

PM 

so2 

PM 

No, 

CO 

cox 

PM 

P = 0.5(10/R)~ .5 

P = allowable 1bIMMBtu 

R = heat input 

30 ppmvd @ 3 % O2 Georgia Rule (lll) 

20 % (27 % for one 6-minute periodh) NSPS Subpart Dc 

0.0510.10 lb/MMBtu (coal or coal with other fuels, 

depending on capacity fkctor) 

0.10 lbIMMI3tu (he1 oil or oil and other fuels) 

0.1010.30 lb/MMBtu (wood waste, depending on 

capacity factoi.) 

0.50 lb/MMBtu or < 0.5 % fuel sulk (fbel oil) 

1.2 lb/MMBtu (solid fossil fuel) 

0.5 lb/MMBtu (after 1972) 

0.7 lb/MMBtu (before 1972) 

Units > 75,000 =< 400,000 Btu/hr: 

40 ng/J (93 lb/billion Btu) heat output or 55 

ppmv @ 3 % O2 dry basis 

Units > 400,000 =< 2 MMBtu/hr 

30 ppmvd @ 3 % O2 dry basis or 0.037 

lb/MMBtu heat input 

Units > 400,000 - 2 MMBtu/hr 

400 ppmvd @, 3 % O2 dry basis 

~nits>2and <r~~~tu/hr: 

30 ppm or 0.037 lb/MMBtu 

Units with annual heat input =< 18,000 therms: 

Maintain stack-gas O2 =< 3 % 02 dry basis 

for any 15 consecutive minute averaging 

Equipment (all) 

Georgia Rule (d) 

SCAQMD Rule 

1 146.2 

SCAQMD Rule 

1146.1 

Opacity 

Fuel Sulfur 

Content 

0.1 grlscf (after 1970) Oregon Div. 228 

0.2 grlscf (before 1970) 

20 % for all indirect heat exchangers > 200 MMBtu/hr 

< = 0.3 % S fuel (ASTM Grade 1 fuel oil) 

< = 0.5 % S fuel (ASTM Grade 2 fuel oil) 

< = 1.75 % S (residual fuel oil) 

< = 1.0 % S fuel (coal) 

NJAC 7:27-3 

Oregon Div. 228 
I1 Includes all stationary gas andlor oil-fired turbines and oil-fued stationary internal combustion engines. Pinal 

County Article 23 regulation contains an exemption for emergency use IC engines < 325 bhp and operated < 72 

hrlyr. 

12 Note: N& limit includes thermal efficiency correction EFF/25% of source can demonstrate higher efficiency. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 16 

Source (Reference) 

BAAQMD 

Rule 9-1 

NSPS Subpart Dc 

Georgia Rule (g) 

NJAC 7:27-9 

NJAC 7:27- 10 

Pinal County Ch. 5 

Article 2 1 

Arizona Rule 7 19; 

Pinal County Ch. 5 

Article 23 

NSPS Subpart GG 

SCAQMD Rule 

1 1 3412 

Source 

Sub-category 

Fossil fuel-fired 

Commercial and 

Industrial Equip. 

Stationary 

Rotating 

~achineryl 

Pollutant/ 

Parameter 

PM 

opacity 

PM 

SO2 

Emission Limits/Standards/Controls 

< = 0.5 % S fuel (liquid oil) 

< = 300 ppmvd (solid fuel) 

< 0.5 % fuel sulfbr (fuel oil, sources 10 - 100 

MMl3* 

< 2.5 % S fuel (sources < 100 MMBtu/hr) 

< 3.0 % S fuel (sources > 100 MMBtuflu) 

No. 2 Fuel Oil & Lighter 

0.2 - 0.3 % S depending on zone, or 

0.2 1 - 0.32 Ib/MMBtu 

No. 4 Fuel Oil 

0.3 - 2.0 % S depending on zone, or 

0.32 - 2.10 lb/MMBtu 

No. 5,6 & heavier 

0.3 - 2.10 % S depending on zone, or 

0.32 - 2.10 Ib/MMBtu 

Anthracite Coal or Coke 

0.8 % S, or 

1.2 lb/MMBtu 

Other Solid Fuel 

0.2 - 1.0 % S depending on zone, or 

0.3-1.51blMMBtu 

Heat input based equation 

40 %, 10 consecutive seconds. Cold equipment - first 

10 seconds exempt. 

Heat input based equation 

1 .O lb/MMBtu (low sulk oil) 

Stationary Gas 

Turbines 

9 ppmvd @ 15 % O2 averaged over 15 min. 

15 ppmvd if no SCR 

9 ppmvd @ 15 % O2 averaged over 15 min. 

12 ppmvd if no SCR 

so2 

N& 

2.2 lb/MMBtu (high sulfur oil) 

Permit renewal or modification triggers condition 

prohibiting use of high sulfur oil (unless demonstrated 

infeasible by source) 

0.015 % by vol. @ 15 % 02, dry basis 

Allowable (% vol.) = [0.0150 (14.4 / Y)] + F 

Y = rated heat rate (kilojoules per watt hour) 

F = fuel bound nitrogen emission allowance 

>= 0.3 < 2.9 MW = 25 ppmvd @ 15 % O2 averaged over 15 min. 

>= 2.9 < 10.0 MW 
he1 burning TSD 6-14-02 Created on 6/18/2002 9:32:00Ah4 

Source (Reference) 

NJAC 7:27-19 

BAAQMD 

Rule 9-9 

NJAC 7:27-16.9 

NJAC 7:27-3 

Georgia Rule 

(mmm) 

BAAQMD 

Rule 9-8 

SCAQMD 

Rule 1 1 1 0.1 

NJAC 7:27-19.8 

SCAQMD 

Rulel110.1& 

BAAQMD 

Rule 9-8 

SCAQMD 

Rule1 110.2 

NJAC 7:27-16.10 

Source 

Sub-category 

Stationary IC 

Engines and 

Turbine Engines 

Stationary IC 

Engines (Rich & 

Lean Burn) 

Stationary 

Gaseous & 

Liquid - Fueled 

Engines 

Pollutant/ 

Parameter 

CO 

VOC 

Opacity 

NOx 

NOx 

CO 

NOx 

VOC 

CO 

Emission Limits/Standards/Controls 

>= 60.0 MW Combined Cycle 

9 ppmvd @ 15 % O2 averaged over 15 min. 

15 ppmvd if no SCR 

Simple Cycle Turbines >= 30 MMBtu/hr heat input 

Oil: 0.4 Ib/MMBtu 

Gas: 0.2 Ib/MMBtu 

Combined Cycle Turbines >= 30 MMBtu/hr heat input 

Oil: 0.35 lb/MMBtu 

= Gas: 0.15 IbIMMBtu 

>=0.3 < 1OMW 

42 ppmvd @ 15 % O2 (65 ppmvd for liquid 

hel/gas curtailment/short term testing) 

>= 10.0 hfw 

9 ppmvd @ 15 % O2 with SCR (25 ppmvd 

for gas curtailment/short term testing) 

15 ppmvd if no SCR (42 ppmvd for liquid 

fueYgas curtailment/short term testing) 

250 ppmvd @ 15 % O2 

50 ppmvd @ 15 % O2 

No. 1 on Ringlemann Smoke Chart or 20 % 

30,42, 80, 160 ppmvd @ 15 % 02, phased compliance 

, schedule 

Rich-Bum: 

56ppmvd@15%02 

Lean-Bum: 

140ppmvd@15%02 

Rich-Bum: 

90 ppmvd @ 1 5 % O2 averaged over not < 1 5 

consecutive minutes 

Lean-Bum: 

2.Oglbhp-hr(O.75pglJ); 150ppmvd@15% 

O2 averaged over not < 15 consecutive 

minutes 

Rich-Burn > 500 hp, gaseous fuel 

1.5 @hp-hr 

Lean-Bum > 500 hp, gaseous fuel 

2.5 ghp-hr 

Lean-Bum > 500 hp, liquid fuel 

8.0 ghp-hr 

2000 ppmvd @ 15 % O2 

36 ppmvd @ 15 % O2 averaged over 15 minutes 

250 ppmvd @ 15 % O2 (as methane) averaged over 15 

pp 

min. 

2000 ppmvd @, 15 % O2 averaged over 15 minutes 

500 ppmvd 0,15 % O2 
Source Pollutant/ 

Sub-category Parameter 

& Liquid - Fueled 

Central urna aces I 

Natural-Gas-Fired 1 NOx 

Natural-GasFired, Fan-Type 

N@i 

: Emission Limits/Standards/Controls 

Water Heaters 

(Residential) 

Spark Ignition: 

I 80 ppmvd @ 15 % O2 averaged over 15 minutes (1.5 

I glbhp-hr) ' Compression Ignition (>50, <I17 bhp): 

80 ppmvd @ 15 % O2 averaged over 15 minutes (1.5 

glbhp-hr) 

Compression Ignition (>I 17,<400 bhp): 

550 ppmvd @ 15 % O2 averaged over 15 minutes (7.2 

glbhp-hr) 

Compression Ignition (>400 bhp): 

I 535 ppmvd @ 15 % Oz averaged over 15 minutes (7.0 

glbhp-hr) 

Spark Ignition: 

240 ppmvd @ 15 % O2 (as methane) averaged over 15 

min. (1.5 glbhp-hr) 

176 ppmvd @ 15 % O2 averaged over 15 minutes (2.0 

gbhp-br) 

40 ng/J (as NOz) of useful heat delivered to heating 

space 

Phased certification requirements: 40,20, 10 ng/J (as 

NO2) or 55,30,15 ppbvd @ 3 % O2 -- 

Source (Reference) 

SCAQMD 

Rule1 110.2 

SCAQMD Rule 

1111 & BAAQMD 

Rule 9-4 

SCAQMD Rule 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Source 

Sub-category 

used Oil 

Combustion 

Pollutant/ 

Parameter 

General 

Emission LimitsIStandardslControls 

Space Heaters 

Registration required for facilities < 500,000 

Btulhr, Permit for facilities > 500,000 

= Used oil must be on-specification 

Max. gross heat input of any space heater 

must not exceed 500,000 Btu/hr, or permit 

required 

Space heaters must be listed and tested by 

nationally recognized lab equivalent to UL 

Annual combustion process adjustment 

required 

Space Heater Used Oil Limits (non-permit): 

Arsenic-5 ppmw 

Cadmium - 2 ppmw 

Chromium - 10 ppmw 

Lead - 100 ppmw 

Flash point - 100 degrees F 

Total halogens - 1000 ppmw 

Sulfur - 5000 ppmw 

On-spec Used Oil Combustion by Permit 

Protocol for conducting air quality analysis 

and risk assessment 

Equipment and control details 

Necessary certifications 

Demonstration that Used Oil is On-Specification 

Facility analysis or supplier analysis 

documentation for each shipment of used oil 

Copies of aaalyses retained for three years 

Ash Standard 

0.15 % by weight 

Measured with ASTM D 482-91 

Burning On-Spec Oil in other Combustion Units 

(without permit) 

Gross heat input > 20 MMBtu/hr 

Unit capable of burning No. 6 fuel oil 

Demonstration of On-Specification status 

Meets ash standard of .015 % wlw 

Meets sulfur standard 

Burning of Off-Specification Used Oil 

Permit required 

Control device requirements 

Source (Reference) r--l 

NJAC 7:27-20 

fuel burning TSD 6-14-02 Created on 611 812002 9:32:00 AM 
4.4.2 Derivation of Proposed GRIC Source Category LimitsJStandards 

The derivation of Rule 1 : Fuel Burning Equipment was as follows: 

Section 1.0 - General Limitations and Standards 

A general fuel burning equipment opacity limitatiofi of 20% was proposed. This is consistent 

with NSPS Subparts D, Da, Db, and Dc as well as most stateAocql air quality regulatory 

programs, including the Arizona and Maricopa County Air Rules. 

Some state programs allow for higher opacity limits on older (pre- 1975) fuel burning equipment. 

Pinal County limits opacity by general standard to 40 % (see Chapter 2, Article 8). Arizona Rule 

7 19 allows 40% opacity for stationary rotating machinery (e.g., turbines and IC engines), as 

opposed to the generally applicable 20% standard. Although less stringent limitations exist in 

state and local air quality regulations, 20% represents a reasonable and defendable standard, 

largely consistent with neighboring regulatory jurisdictions. Compliance with this limit on fuel 

burning equipment is achievable through equipment upkeepJmaintenance and good operating 

practice. Unless otherwise specified in a category-specific de, EPA Method 9 was proposed as 

the default opacity determination method. 

Fuel sulfur limitations of 1.75,0.50, and 1.0 percent sulfix were proposed for residual fbel oil, 

distillate fuel oil, and coal, respectively. These limitations are consistent with Oregon Division 

228, which represented the most complete fuel sulfur limitations reviewed and is believed to be 

consistent with current, reasonably available fossil fbel specifications. 

The definition of and provisions/exclusions relating to start-up, shutdown, and malfunction as 

well as excess emissions reporting were not included in this TSD. These provisions should be 

addressed in a separate TIP section applicable to all GRIC source categories. 

Section 2.0 - Electric Utility Steam Generating Equipment 

A PM emissions limit of 0.03 lb-tu heat input was proposed for this source category. This 

limit is consistent with NSPS Subpart Da, which applies to new or modified electric utility steam 

generating units. No sources currently operating on GRIC land fall within the electric utility 

source category. Any new source locating on GRIC land in the future would be subject to NSPS 

Subpart Da (as well as potentially NSR/PSD, Title V, CAM, Acid Rain Program, etc.). The 

proposed PM limit represents a reasonable minimum standard for incorporation into the TIP. 

The proposed electric utility steam generating equipment SO2 emission limit (0.80 lb/MMBtu) is 

consistent with the maximum NSPS Subpart Da requirement for gaseous and liquid fuels (i.e., 

not including percent reduction requirements). No separate limit for coal firing is proposed as 

provided for in the NSPS because no sources currently located on GRIC land combust coal. Any 

potential new sources citing on GRIC land would be subject to more stringent new source 

requirements (e.g., BACT and NSPS percent reduction requirements). 

fuel burning TSD 6-14-02 Created on 6/18R002 9:32:00 AM 
The proposed 0.80 IblMMBtu SO2 limit is consistent with the Pinal County Chapter 5, Article 

22, Maricopa County Rule 320, and Arizona Rules 703 provisions applicable to low sulk fie1 

oil and coal-fired sources installed after 1972-1975. It is also consistent with the SO2 standards in 

several other state programs reviewed, including Georgia and Oregon. 

The proposed electric utility steam generating equipment NOx emission limit of 1.6 lb/MW-hr 

energy output is consistent with the NSPS Subpart Da requirement for sources constructed after 

July 9,1997. This proposed limit is more stringent than the Pinal County, Maricopa County, and 

Arizona NOx standards applicable to electric utility sources, which mirror the NSPS for sources 

installed or modified prior to July 9,1997. However, no electric utility steam generating units 

currently exist in GRTC land. Therefore, there are no existing source compliance implications 

associated with the proposed standard. Any new electric utility sources would be subject to more 

stringent limitations than the proposed standard (e.g., BACT). The proposed limit is defensible 

based on NSPS, and represents a reasonable minimum baseline standard for NOx emissions form 

utility steam generating equipment. The limit is expressed on a gross energy output basis, which 

also encourages energy efficiency along with emissions control. 

A CO emission limit of 400 ppmvd @ 3% O2 was proposed for this source category. This limit is 

consistent with BAAQMD Rule 9-1 1 and SCAQMD Rule 1 146. It is less stringent than other 

state regulations such as New Jersey 7:27-16.8, which specifies a CO limit of 100 ppmvd @ 7% 

a. Not all state regulatory programs contain CO limitations. No specific fie1 burning equipment 

CO standards are contained in the Maricopa County, Pinal County, or Arizona Rules. However, 

BACT CO limits are common. CO limitations can be usell in enforcing good combustion unit 

design and operating practices. Also, with NOx requirements becoming ever more stringent, 

tradeoffs often exist between NOx reduction and CO emissions increases. 400 ppm rep~esents a 

reasonable maximum steady state (periodic compliance test conditions) CO emission limit for 

combustion units in this source category. It should be readily achievable through good 

combustion practices. 

Section 3.0 - Inddal, Commercial, and Institutional Boilers. Steam Generators, and Process 

Heaters 

This source category was divided into two subcategories, units greater than or equal to 100 

MMBW heat input capacity and units greater than or equal to 10 MMBtuihr but less than 100 

MMBtuJhr heat input capacity. The 100 MMBtu/hr threshold is consistent with NSPS Subpart . Db, and represents a logical break point in unit capacity and emissions control cost effectiveness. 

Units less than 10 MMBtu/hr heat input capacity were deemed to be less consequential fiom an 

emissions standpoint, with comprehensive emission limitations yielding little environmental 

benefit in comparison with the regulatory burden. Therefore, only the general fuel burning 

equipment standards (e-g., opacity and fuel sulk content limitations) were proposed for units 

less than 10 MMBtu/hr. 

A PM emission limit of 0.10 lb/MMBtu was proposed for both subcategories. This limit is 

consistent with NSPS Subpart Db and Dc requirements for fuel oil and fuel oil fired in 

combination with other fuels. It is also consistent with other state rule limits (e.g., Georgia Rule 

he1 burning TSD 6-14-02 Created on 611 8/2002 9:32:00 AM 
(d)). This limit should be readily achievable firing natural gas or low sulfur fuel oil. Emission 

controls would likely be required for coal or high sulfur fuel oil-fired units. 

A non fuel-specific N& emission limit of 0.20 lb/MMBtu heat input was proposed for units 

greater than 100 MMBtu/hr. This limit is consistent with NSPS Subpart Db requirements for 

sources constructed after July 9, 1997. It is somewhat more stringent than the NSPS for units 

installed prior to 1997, which limits fuel-specific N& emissions to 0.24 0.30, and 0.70 

lb/MMBtu for gas, oil, and coal, respectively. These older source NSPS limitations are also 

mirrored in several state rules. 

The proposed 0.20 lb/MMBtu N& limit is less stringent than current BACT, yet reflective of 

current combustion and control technology. It represents a reasonable minimum baseline for 

NOx emissions control for this source category. No specific NOx limits are proposed for units 

between 10 and 100 MMBtu/hr. [SUGGEST ADDING 40 PPM N& @ 3% 02 Limit for this 

category] 

An SO2 emission limit of 0.80 lb/MMBtu was proposed for sources greater than 100 MMBtu/hr. 

Again, this limit is consistent with NSPS Subpart Db for fuel oil firing and fuel oil firing with 

other fuels. The proposed limit is also consistent with the Pinal County Rule applicable to fossil 

fuel-fired steam generators (Chapter 5, Article 22) and both Maricopa County Rule 320 and 

Arizona Rule 703 provisions for low sulfur oil hg after 1972. Sources firing natural gas and/or 

distillate (No. 2) fuel oil would not require controls to comply with the proposed SO2 limit. 

A CO emission limit of 400 ppmvd @ 3% O2 was proposed for this source category. This limit is 

consistent with BAAQMD Rule 9-7 and SCAQMD Rule 1 146. It is less stringent than other state 

regulations, such as New Jersey 7:27-16.8 which specifies a CO limit of 100 ppmvd @ 7% 02. 

Not all state regulatory programs contain CO limitations. No specific fuel burning equipment CO 

standards are contained in the Maricopa County, Pinal County, or Arizona Rules. However, CO 

BACT limits are common. CO limitations are a usefbl surrogate for enforcing good combustion 

unit design and operating practices. Also, with NOx requirements becoming ever more stringent, 

tradeoffs often exist between NOx reduction and CO emissions increases. 400 ppm represents a 

reasonable maximum steady state (periodic compliance test conditions) CO emission limit for 

combustion units in this source category. It should be readily achievable through good 

combustion practices. 

Section 4.0 - Stationary Gas Turbines 

NSPS Subpart GG, which applies to new or modified gas turbines, contains an SO2 emission 

limit of 0.015 % by volume @ 15 % 02 as well as a fuel oil sulfur limitation of 0.8 %. The Pinal 

County and Arizona Rules limit SO2 emissions fiom "Rotating Machinery," including gas 

turbines, to 1.0 and 2.2 lb/MMBtu for low sulfur and high sulfur fuel oil, respectively. Since 

most stationary turbines typically fire natural gas, except during periods of gas curtailment or 

other under backup fuel scenarios, SO2 emissions are normally not a concern. A limit on the 

sulk content of he1 oil fired in gas turbines offers a practical and straightforward method of 

limiting SO2 emissions fkom this source category. A limit of 0.5% sulfur for fuel oil fired in gas 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
turbines is proposed. This is consistent with the distillate fuel oil sulfur content limit proposed 

under the general limitations section of this standard (see Section 1.0). 

Stationary gas turbine NOx standards were proposed that are roughly equivalent to presumptive 

BACT for smaller turbines without add-on controls (e.g., SCR). Large turbines potentially citing 

on GRIC land in the future (e.g., cogeneration units) would be subject to NSR/PSD requirements 

and BACTLAER requirements below 10 ppm NOx. Therefore, the primary purpose of this 

standard is to set presumptive BACT for non-NSR/PSD major installations. 

NSPS Subpart GG regulates gas turbines with a heat input at peak load greater than 10.7 

gigajoules per hour (1 0 MMBtdw). This standard is outdated, and currently in the process of 

being revised by EPA. The equation based NOx limit contained in the standard corresponds to 

roughly 75 ppm. For comparison, current BACT levels are less than 9 ppm (for natural gas) and 

can be as low as 2.5 - 3 ppm. The Maricopa County, Pinal County and Arizona Rules do not 

contain N& standards for gas turbines. 

The proposed N& limits for gas turbines are 42 ppmvd and 65 ppmvd @ 15 % 02 for gas and 

oil firing, respectively, for units less than 10 MW; and 15 ppmvd and 42 ppmvd @ 15 % 02 for 

gas and oil firing, respectively, for units greater than or equal to 10 MW. These limits are 

consistent with BAAQMD Rule 9-9 for units not equipped with SCR. They are less stringent 

than SCAQMD Rule 1134 (see Table 4-1). The proposed limits are believed to represent a 

reasonable presumptive BACT level for non-major source gas turbines. 

A CO limit of 250 ppmvd @ 15 % O2 during steady-state compliance test conditions was 

proposed for this source category. This limit is consistent with BAAQMD Rule 9-1 1 and less 

stringent than the 100 ppmvd @ 7 % O2 limit contained in New Jersey Rule 7:27-16.8. No 

specific fuel burning equipment CO standards are contained in the Maricopa County, Pinal 

County, or Arizona Rules. Again, this proposed limit is believed to constitute a reasonable level 

of presumptive BACT for non-major gas turbines. 

Section 5.0 - Stationary Internal Combustion Engines 

The proposed emission limits for stationary internal combustion engines apply to all stationary 

IC engines > = 500 bhp. An exemption fkom the standard was proposed for equipment used for 

emergency power generation or fire suppression if operated less than 500 hours per year. This is 

consistent with Pinal County Chapter 5, Article 23. No specific standards applicable to IC 

engines or rotating machinery are contained in the Maricopa County Rules. No rotating 

machinery exemption levels are contained in Arizona Rule 71 9. 

N& limitations of 1.5 ghp-hr and 2.5 g/hp-hr were proposed for rich and lean burn gaseous 

fuel-fired engines, respectively. These engines are generally associated with natural gas 

transmission stations, which currently do not exist on GRIC land. The standards are consistent 

with New Jersey Rule 7:27-19.8 and less stringent than SCAQMD Rule 1 1 10.1 and BAAQMD 

Rule 9-8. For liquid fuel (e-g., gasoline and diesel fuel-fired) lean bum IC engines, a NqL limit 

8.0 g/hp-hr was proposed. Again, this limit is consistent with New Jersey Rule 7:27-19.8. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
A CO emission limit of 2000 ppm @ 15 % O2 was proposed for all stationary IC engines subject 

to the standard. This limit is consistent with SCAQMD Rule 1 1 1 0.2. It is less stringent than the 

500 ppmvd limit contained in New Jersey Rule 7:27- 1 6.1 0. 

Section 6.0 - Used Oil Combustion 

The proposed standards for used oil firing are based on New Jersey Rule 7:27-20. This recently 

adopted rule contained the most comprehensive and complete standards for used oil fuing. 

5.0 Proposed GRIC Fuel Burning Equipment Rule Provisions (Section M. E; Rule 1: 

Fuel Burning Equipment) 

5.1 APPLICABILTY 

The provisions of Rule 1 apply to any fuel burning equipment, including, but not limited to 

utility steam generating units, industrial, commercial and institutional boilers, process heaters, 

and space heaters, combustion turbines, stationary internal combustion reciprocating engines, 

and internal combustion engines used for emergency power generation. Compliance with the 

provisions of this rule shall not relieve any person subject to the requirements of this rule fiom 

complying with any other federally enforceable New Source Pedormance Standards or National 

Emission Standards for Hazardous Air Pollutants. In such case, the more stringent standard shall 

apply 

5.2 DEFINITIONS 

Ash means the residue remaining after the burning of a material as tested according to ASTM 

Standard Test Method for Ash fiom Petroleum Products by ASTM D482-91, incorporated herein 

by reference. 

ASTM means the American Society for Testing and Materials. 

Boiler or Steam Generator means any combustion equipment fired with liquid andlor gaseous 

andlor solid fossil fuel, used to produce steam or to heat water, and that is not used exclusively to 

produce electricity for sale. Boiler or Steam Generator does not include any waste heat recovery 

boiler that is used to mver sensible heat fiom the exhaust of a combustion turbine or any 

unfired waste heat recovery boiler that is used to recover sensible heat fiom the exhaust of any 

combustion equipment. 

BTUmeans British Thermal Unit. 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the 

American Society of Testing and Materials in ASTM D388-77, Standard Specification for 

Classification of Coals by Rank, coal refuse, and petroleum coke. Coal-derived synthetic fuels, 

including but not limited to solvent re-fined coal, gasified coal, coal-oil mixtures, and coal-water 

mixtures, are also included in this definition for the purposes of this regulation. 

Combined cycle system means a system in which a separate source, such as a gas turbine, internal 

combustion engine, kiln, etc., provides exhaust gas to a heat recovery steam generating unit. 

Combustion unit means a unit into which fuel is charged and heated to the point at which 

oxidation occurs and energy is generated. 

fuel burning TSD 6-14-02 Created on 6/1U2002 9:32:00 AM 
Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with 

the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing 

and Materials in ASTM D396-78, Standard Specifications for Fuel Oils. 

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from 

another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow 

the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat 

recovery steam generating unit. 

Electric utility steam generating unit means any furnace, boiler, or other device used for r 

combusting fuel for the purpose of producing steam, including fossil-fuel-fired steam generators 

associated with combined cycle gas turbines. 

Engine means any spark- or compression-ignited internal combustion engine, not including 

engines used for self-propulsion. 

Fuel means combustible material burned in boilers, furnaces, or other machinery to generate heat 

or other forms of energy. This term includes commercial fuel and non-commercial fuel. 

Fuel oil means a liquid or liquefiable petroleum product burned for lighting or for the generation 

of heat or power and derived directly or indirectly from crude oil. 

Full capacity means operation of the fuel burning unit at 90 percent or more of the maximum 

steady-state design heat input capacity. 

Heat Input means the chemical heat released due to fuel combustion in a unit, using the higher 

heating value of the fuel. This does not include the sensible heat of incoming combustion air. 

Heat Output means the enthalpy of the working fluid output of the unit. 

Lean-Bm Engine means a spark-ignited, Otto-cycle or two-stroke engine that is operated with 

gaseous fuel and with an exhaust stream oxygen concentration of 4 percent by volume, or 

greater. 

Maximum heat input capacity means the ability of a fuel combustion unit to combust a stated 

maximum amount of fuel on a steady state basis, as determined by the physical design and 

characteristics of the unit. 

Wtu means million British Thermal Units 

Natural gas means (1) a naturally occurring mixture of hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath the earth's surface, of which the principal constituent is 

methane; or (2) liquid petroleum gas, as defined by the American Society for Testing and 

Materials in ASTM Dl 835-82, "Standard Specification for Liquid Petroleum Gases" 

Number 1 fuel oil means fuel oil of the grade that is classified as Number 1, according to ASTM 

Standard Specification for Classification of Fuel Oils by ASTM D396-84. 

Number Zfiel oil means fuel oil of the grade that is classified as Number 2, according to ASTM 

Standard Specification for Classification of Fuel Oils by ASTM D396-84. 

Number 6fiel oil means fuel oil of the grade that is classified as Number 6, according to ASTM 

Standard Specification for Classification of Fuel Oils by ASTM D396-84. 

NOx Emissions means the sum of nitrogen oxide and nitrogen dioxide in the flue gas, 

collectively expressed as nitrogen dioxide. 

On-speciJcation used oil means used oil which meets the specifications established in the solid 

waste des at 40 CFR Part 279, Standards for the Management of Used Oil, and any 

amendments thereto. These specifications me currently as follows: 

ConstituentIPro~ertv Allowable Level 

Arsenic 5 ppmw maximum 

Cadmium 2 ppmw maximum 

fuel burning TSD 6-14-02 Created on 6f1812002 9:32:00 AM 
ConstituentProperty Allowable Level 

Chromium 10 ppmw maximum 

Lead 100 ppmw maximum 

Flash point 100 degrees Fahrenheit minimum 

Total halogens 1000 ppmw maximum 

Portable Engine means an engine that, by itself or in or on a piece of equipment, is designed to 

be and capable of being carried or moved from one location to another. Indications of portability 

include, but are not limited to, wheels, skids, carrying handles, dolly, trailer, platform or 

mounting. The owner or operator must demonstrate the necessity of the engine being periodically 

moved from one location to another because of the nature of the operation. 

ppmw means parts per million by weight. 

ppmvd means parts per million by volume, dry basis. 

Process Heater means any combustion equipment fired with liquid ador gaseous andlor solid 

fossil fuel and which transfers heat from combustion gases to water or process streams. 

Rated Brake Horsepower means the rating specified for the engine by the manufacturer. 

Rated Heat Input Capacify means the heat input capacity specified on the nameplate of the 

combustion unit. If the combustion unit has been altered or modified such that its maximum heat 

input is different than the heat input capacity specified on the nameplate, the new maximum heat 

input shall be considered as the rated heat input capacity. 

Rating ofa Gas Turbine Unit means the continuous MW (megawatt) rating or mechanical 

equivalent by a mandacturer for gas turbine unit(s) without power augmentation. 

Residual oil means any oil meeting the specifications of ASTM Grade 4,s or 6 fuel oils. 

Rich-Burn Engine means a spark-ignited, Otto-cycle or two-stroke engine that is operated with 

gaseous fuel and with an exhaust stream oxygen concentration of less than 4 percent by volume. 

Space heater means a fossil fuel or used oil fired space heater that is selfcontaked, 

automatically controlled, indirectly fired heating appliance for warming of a non-residential area 

or for other energy recovery. 

Standard Conditions means a temperature of 68 degrees Fahrenheit and a pressure of 14.7 

pounds per quare inch absolute. 

Standard Cubic Foot means the amount of gas that would occupy one cubic foot, if the gas were 

he of uncombined water at standard conditions. When applied to combustion flue gases from 

fuel or refuse burning, standard cubic foot also implies adjustment of gas volume to that which 

would result at a concentration of 12% carbon dioxide or 50% excess air. 

Stationary Gas Turbine means any gas turbine unit that is gas andor liquid fueled with or 

without power augmentation. This gas turbine unit is either attached to a foundation at a facility 

or is portable equipment operated at a specific facility for more than 90 days in any 12-month 

period. Two or more gas turbine units powering one shaft shall be treated as one gas turbine unit. 

Stationary Internal Combustion Engine (engine) means any spark compression ignited 

reciprocating internal combustion engine that is attached to a foundation at a location or is 

portable and operated at the location for more than one year, not including engines used for selfpropulsion. 

Steam generating unit means a device that combusts any fuel or byproduct/waste to produce 

steam or to heat water or any other heat transfer medium. This term includes any municipal-type 

solid waste incinerator with a heat recovery steam generating unit or any steam generating unit 

that combusts fuel and is part of a cogeneration system or a combined cycle system. 

This term does not include process heaters. 

fuel burning TSD 6- 14-02 Created on 6/ 1812002 9:32:00 AM 
Used oil means any oil that has been refined from crude oil, or any synthetic oil, that has been 

used and as a result of such use, is contaminated by physical or chemical impurities, or unused 

oil that is contaminated by physical or chemical impurities through storage or handling. 

Visible smoke means smoke that obscures light to a degree readily discernible by visual 

observation. 

5.3 EMISSION LIMITATIONS AND STANDARDS 

Section 1.0 - General Limitations and Standards 

Applicability 

The provisions of Rule 1, Section 1.0 apply to all fuel burning equipment as defined in this 

regulation. Where more stringent category-specific requirements apply as defined in Rule 1, 

Sections 2.0 - 6.0, those requirements shall apply. 

The provisions of Rule 1 shall not apply to combustion sources in residential dwellings where 

such sources are used for heating or other domestic purposes. 

Visible Emissions 

Visible emissions from any fuel burning equipment shall not exceed 20 % opacity. 

Unless otherwise required in Sections 2.0 - 6.0, compliance with opacity standards shall 

be determined by conducting observations in accordance with Reference Method 9 in 

Appendix A, 40 CFR Part 60, as amended, requiring a six minute average as determined 

by 24 consecutive readings at intervals of 15 seconds each 

Where the presence of uncombined water is the only reason for failure of an emission 

unit to meet the applicable opacity limitation, that requirement shall not apply. 

Sulf;r Dioxide 

Sulfur Content of Fuels: 

Residual Fuel Oil 

Shall not exceed 1.75 percent sulfur by weight 

Distillate Fuel Oil 

Shall not exceed 0.5 percent sulfur by weight 

Coal 

Shall not exceed 1.0 percent sulfur by weight 

Section 2.0 - Electric Utilitv Steam Generating Equipment 

Applicability 

The provisions of Rule 1, Section 2.0 apply to all electric utility steam generating units. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Particulate Matter 

PM emissions shall not exceed 0.03 IbIMMBtu (1 3 ng/J) heat input 

t, 

SulJirr Dioxide 

SO2 emissions shall not exceed 0.80 lb/MMBtu (340 ng/J) heat input on a 30-day rolling 

average 

Nitrogen Oxides 

NOx emissions (expressed as NOz) shall not exceed 1.6 1bIMW-hr (200 ng/J) gross 

energy output on a 30-day rolling average 

Carbon Monoxide 

CO emissions shall not exceed 400 ppmvd corrected to 3 percent oxygen 

Section 3.0 - Industrial, Commercial, and Institutional Boilers, Steam Generators, and 

Process Heaters 

The provisions of Rule 1, Section 3.0 apply to all industrial, commercial, and institutional 

boilers, steam generators, and process heaters > = 10 MI'vlBtu/hr rated heat input capacity. 

Units > = 100 MMBtu/hr rated heat input capacity 

Particulate Matter 

PM emissions shall not exceed 0.10 1bIMMBtu (43 ng/J) heat input 

SulJiv Dioxide 

SO2 emissions shall not exceed 0.80 lb/MMBtu (340 ng/J) heat input 

Nitrogen Oxides 

NOx emissions (expressed as NO2) shall not exceed 0.20 lb/MMBtu (86 ng/J) heat input 

Carbon Monoxide 

CO emissions shall not exceed 400 ppmvd corrected to 3 percent oxygen 

fuel burning TSD 6-14-02 Created on 6118R002 932:00 AM 
Units > = 10 MMBtu/hr. < 100 MMBtu/hr rated heat input capacity 

Particulate Matter 

PM emissions shall not exceed 0.10 lb/MMBtu (43 ng/J) heat input 

Sulfur Dioxide 

Sources shall comply with he1 sulfur content limitations contained in Rule 1, Section 1.0 

(General Limitations and Standards) 

All Industrial, Commercial. and Institutional Boilers. Steam Generators. and Process Heaters 

All units shall be tuned at least once per year in accordance with the manufacturer's 

specified tune-up procedure or alternate tuning procedure approved by the Department. 

Approved tuning procedures are available from the Department. 

Section 4.0 - Stationarv Gas Turbines 

Applicability 

The provisions of Rule 1, Section 4.0 apply to all stationary gas turbines greater than 0.3 MW 

rated capacity. 

SuIfur Dioxide 

SO2 emissions shall not exceed 0.015 percent by volume, dry basis, corrected to 15 

percent oxygen 

Nitrogen Oxides 

Units > = 0.3, < 10 MW rated cavacity 

N& emissions shall not exceed 42 ppmvd corrected to 15 percent oxygen when firing 

gaseous he1 

N& emissions shall not exceed 65 ppmvd corrected to 15 percent oxygen when firing 

fuel oil 

Units > = 10 MW rated capacity 

N@ emissions shall not exceed 15 ppmvd corrected to 15 percent oxygen when firing 

gaseous fuel 

N@ emissions shall not exceed 42 ppmvd corrected to 15 percent oxygen when firing 

fuel oil 

fbel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Carbon Monoxide 

CO emissions shall not exceed 250 ppmvd corrected to 15 percent oxygen 

Section 5.0 - Stationarv Internal Combustion Engines 

Applica bili ty 

The provisions of Rule 1, Section 5.0 apply to all stationary and portable internal combustion 

engines > 500 brake horsepower (bhp) output rating. Stationary internal combustion engines 

used for emergency power generation or fire-suppression water pumps shall be exempt fiom 

these requirements provided they are operated not more than 500 hours in any calendar year. 

Nitrogen Oxides 

Rich-Burn Engines Operated with Gaseous Fuel 

NOx emissions shall not exceed 1.5 gthp-hr 

Lean-Burn Engines Operated with Gaseous Fuel 

NOx emissions shall not exceed 2.5 g/hp-hr 

Gasoline or Diesel Fueled Engines 

NOx emissions shall not exceed 8.0 glhp-hr 

Carbon Monoxide 

CO emissions shall not exceed 2000 ppmvd corrected to 15 percent oxygen 

Section 6.0 - Used Oil Combustion 

Applica bility 

The provisions of Rule 1, Section 6.0 apply to all sources which combust used oil as defined in 

this regulation. Sources include, but are not limited to space heaters, boilers, dryers, and kilns. 

Used Oil Specification Requirements 

All used oil combusted must be certified as on-specification 

Used oil ash content shall not exceed 0.15 percent by weight 

Used oil shall not exceed the following limits: 

o Arsenic: 5 ppmw maximum 

o Cadmium: 2 ppmw maximum 

o Chromium: I0 ppmw maximum 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
o Lead: 100 ppmw maximum 

o Flash point: 100 degrees F minimum 

o Total halogens: 1000 ppmw maximum 

o Sulfur: 5000 ppmw maximum 

~e~istratibn/~ermiffin~ Requirements 

Facilities combusting on-specification used oil in equipment with a total rated heat input 

capacity < 500,000 Btu/hr that are otherwise not required to obtain an air quality permit 

to construct andor operate pursuant to Rule are required to register with the 

Department (NOTE: link to registration provisions in minor source permitting rule) 

Any space heater combusting used oil must be listed and tested by a nationally 

recognized lab in accordance with standards equivalent to the Underwriters Laboratory, 

Incorporated 296A Standard for Safety, UL296A "Waste Oil Burning Air Heating 

Appliances." 

Facilities combusting used oil in equipment with a total rated heat input capacity > 

500,000 Btu/hr are required to obtain an air quality permit to construct and/or operate 

pursuant to Rule . 

5.4 SOURCE TESTING AND MONITORING 

5.4.1 Source Testing Procedures 

Source testing and fuel analyses, as required by this rule or specified by the Department in a 

construction and/or operating permit, shall be performed in accordance with Rule and the 

following EPA and ASTM reference methods and procedures, as amended, incorporated herein 

by reference: 

Fuel Analysis - Coal 

Sampling and preparation procedures shall be in accordance with approved ASTM 

methods and procedures 

Analysis of gross caloric value (Btu content), moisture content, and percent sulb shall 

be performed using approved ASTM Methods. A listing of approved ASTM methods is 

available fiom the Department. 

Alternatively, a facility may obtain and keep on file a copy of the fuel supplier certified 

fuel analysis for each shipment of fuel. The certification shall incIude name of the 

supplier, analysis results, including sulfur content, moisture content, ash content, and 

heat content and the sampling and analysis methods used in performing the analyses. 

Fuel Analysis - Oil 

Sampling shall be at the pipeline inlet to the fuel burning unit or designated fuel oil 

storage tank. 

Analysis of heat of combustion (Btu content), and percent sub shall be performed 

using approved ASTM Methods. A listing of approved ASTM methods is available fiom 

the Department. 

Alternatively, a facility may obtain and keep on file a copy of the fuel supplier certified 

fuel analysis for each shipment of fuel. The certification shall include name of the 

fuel burning TSD 6-14-02 Created on 6118r2002 9:32:00 AM . 31 
supplier, statement that the oil complies with the specifications listed under 

"Definitions" for the particular grade of fbel, analysis results, including sulh content, 

ash content (for waste oil) and heat content and the sampling and analysis methods used 

in performing the analyses. 

Compliance test methods and procedures for all fuel burning equipment shall be in accordance 

with those in 40 CFR Part 60 Appendix A unless otherwise approved in writing by the 

Department. 

EPA Method 1 shall be used to select a suitable site and the appropriate number of test 

points for PM testing and velocity and volume flow rate measurement. 

EPA Method 2 shall be used concurrently with any method in which velocity and 

volume flow rate measurements are required. 

EPA Method 9 (6-minute average of 24 observations) shall be used to determine the 

opacity of stack emissions. 

EPA Method 5 or Method 17 (providing that stack gas temperatures do not exceed 320 

degrees F) and Methods 201 or 202 shall be used to determine PM emissions. Total PM 

emission shall include both filterable and condensable particulate matter. 

EPA Method 6 shall be used to determine compliance with SO2 limitations. Compliance 

shall be determined by averaging six 20-minute samples taken over such a period of time 

that no more than 20 minutes elapses between any two consecutive samples. 

EPA Method 7 shall be used to determine compliance with NOx limitations. 

EPA Method 3 shall be used to determine the concentration of 02, COZ CO, or N in the 

gas being sampled as necessary to determine the molecular weight of the gas being 

sampled. 

EPA Method 20 shall be used to determine NOx, SO2, and 02 concentrations from 

stationary gas turbines and internal combustion engines 

EPA Method 10 shall be used to determine the CO concentration from stationary internal 

combustion engines. 

The procedures in Method 19 shall be used to compute emission rates in relevant units of 

the standard as required. 

Upon prior approval from the Department, test methods or procedures different from 

those in this Rule may be used if they will provide equivalent or more reliable results. 

Alternate test methods must be approved by the Department in writing. 

5.4.2 Monitoring Resuirements 

Electric Utility Steam Generating Equipment and Industrial, Commercial, and 

Institutional Boilers, Steam Generators, and Process Beaters > = 100 MMBWr Rated 

Heat Input Capacity 

The following monitoring requirements apply to all electric utility steam generating equipment 

and all industrial, commercial, and institutional boilers, steam generators, and process heaters 

> = 100 MMBtu/hr rated heat input capacity. 

Except as provided below, facilities subject to Rule 1, Section 2.0 and Rule 1, Section 3.0 

(> = 100 MMBtu/hr rated heat input capacity) shall install, calibrate, maintain, and 

he1 burning TSD 6-14-02 Created on 611 8D002 9:32:00 AM 
operate continuous monitoring systems (CEMs), and record the output of the systems, for 

measuring the following pollutants and parameters: 

o Opacity 

o Sulfur Dioxide 

o Nitrogen Oxides 

o Oxygen or Carbon Dioxide 

Where gaseous fuel is the only fuel combusted, CEMs are not required for opacity and 

SO2. 

Where No. 1 or No. 2 grade distillate fuel oil with a sulfur content < = 0.5 percent by 

weight andlor gaseous fuel are the only fuels combusted, a CEM is not required for SO2. 

If opacity interference due to water droplets exists in the stack (for example, fiom the use 

of an FGD system), the opacity is monitored upstream of the interference (at the inlet to 

the FGD system). If opacity interference is experienced at all locations (both at the inlet 

and outlet of the sulk dioxide control system), alternate parameters indicative of the 

particulate matter control system's performance are monitored (subject to the approval of 

the department). 

The CEMs required under this rule shall be operated and data recorded during all periods 

of operation of the facility including periods of starhzp, shutdown, malhction or 

emergency conditions, except for continuous monitoring system breakdowns, repairs, 

calibration checks, and zero and span adjustments. 

Minimum Specifications for CEMs 

Facilities required to install and operate continuous monitoring systems shall operate 

such monitoring equipment in accordance with the following performance specifications 

(PS) set forth in Appendix B of 40 CFR Part 60 as amended, incorporated herein by 

reference. 

o Opacity-PS 1 

o NOx-PS2 

0 SO2-PS2 

o O2andC02-PS3 

Calibration gases: Span and zero gases shall be traceable to National Bureau of 

Standards reference gases whenever these reference gases are available. Every 6 months 

from date of manufacture, span and zero gases shall be reanalyzed by conducting 

triplicate analyses using the reference methods in Appendix A of 40 CFR 60 (Chapter 1) 

as amended: For sulfur dioxide, use Reference Method 6; for nitrogen oxides, use 

Reference method 7; and for carbon dioxide or oxygen, use Reference Method 3. The 

gases may be analyzed at less fkquent intervals if longer shelf lives are guaranteed by 

the manufacturer. 

Cycling time: Time includes the total time required to sample, analyze, and record an 

emission measurement. 

o Continuous emission monitoring systems for measuring opacity shall complete a 

minimum of 1 cycle of sampling and analyzing for each successive 6-minute 

period. 

o Continuous emission monitoring systems for measuring oxides of nitrogen, 

carbon dioxide, oxygen, or sulfur dioxide shall complete a minimum of 1 cycle of 

fuel burning TSD 6-14-02 Created on 6/18/2W2 9:32:00 AM 33 
operation (sampling, analyzing, and date recording) for each successive 15- 

minute period. 

Monitor location: All continuous emission monitoring systems or monitoring devices 

shall be installed such that representative measurements of emissions of process 

parameter (i.e., oxygen, or carbon dioxide) from the affected facility are obtained. 

Additional guidance for location of continuous emission monitoring systems to obtain 

representative samples is contained in the applicable performance specifications of 

Appendix B of 40 CFR 60. 

Zero and drift: Facilities required to install and operate continuous emission monitoring 

systems in accordance with this Rule shall record the zero and span drift in accordance 

with the method prescribed by the manufacturer's recommended zero and spa check at 

least once daily, using specified calibration gases, unless the manufacturer has 

recommended adjustments at shorter intervals, in which case such recommendations 

shall be followed. Facilities shall adjust the zero span whenever the 24-hour zero drift or 

24-hour calibration drift limits of the applicable performance specifications in Appendix 

B of Part 60, Chapter 1, Title 40 CFR are exceeded. 

Span: Instrument span should be approximately 200% of the expected instrument data 

display output corresponding to the emission standard for the source. 

Minimum Data Requirements 

Facilities required to install continuous emission monitoring systems shall submit to the 

Department a written report of excess emissions for each calendar quarter and the nature 

and cause of the excess emissions, if known. The averaging period used for data 

reporting shall correspond to the averaging period specified in the emission standard for 

the pollutant source category in question. The required report shall include, as a 

minimum, the data stipulated in this subsection. 

o For opacity measurements, the smary shall consist of the magnitude in actual 

percent opacity of all 6-minute opacity averages greater than any applicable 

standards for each hour of operation of the facility. Average values may be 

obtained by integration over the averaging period or by arithmetically averaging a 

minimum of 4 equally spaced, instantaneous opacity measurements per minute. 

Any time periods exempted shall be deleted before determining any averages in 

excess of opacity standards. 

o For gaseous measurements the summary shall consist of emission averages in the 

units of the applicable standard for each averaging period during which the 

applicable standard was exceeded. 

o The date and time identiwg each period during which the continuous emission 

monitoring system was inoperative, except for zero aud span checks and the 

nature of system repair or adjustment shall be reported. The Department may 

require proof of continuous emission monitoring system performance whenever 

system repairs or adjustments have been made. 

o When no excess emissions have occurred and the continuous emission monitoring 

system(s) have not been inoperative, repaired, or adjusted, such information shall 

be included in the report. 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Owners or operators of affected facilities shall maintain a file of all information reported 

in the quarterly summaries, and all other data collected either by the continuous emission 

monitoring system or as necessary to convert monitoring data to the units of the 

applicable standard for a minimum of 2 years hm the date of collection of such data or 

submission of such summaries. 

Data Reduction 

Owners or operators of affwted facilities shall use the procedures outlined in EPA 

Reference Method 19, as amended, for converting monitoring data to units of the 

standard where necessary. 

Industrial, Commercial, and Institutional Boilers, Steam Generators, and Process Heaters 

> = 10 MMBtu/hr, < 100 MMBtu/hr Rated Heat Input Capacity 

The following monitoring requirements apply to all industrial, commercial, and institutional 

boilers, steam generators, and process heaters > = 10 MMBtuh and < 100 MMBtu/hr rated heat 

input capacity. 

As required by the Department, facilities shall conduct periodic source tests to 

demonstrate compliance with specified PM, NOx, SO2, and CO limitations. Test results 

shall be submitted to the Department within 30 days of completion of testing. 

Pollutant/parameter emissions shall be expressed in the applicable units of the standard. 

Stationary Gas Turbines 

Cogeneration and combined cycle gas turbine units 3 MW and larger (continuous rating by the 

manufacturer without power augmentation) 

Facilities shall install, calibrate, maintain, and operate continuous monitoring systems 

(CEMs), and record the output of the systems, for measuring the following pollutants 

and parameters: 

o NOx 

0 02 

Monitoring equipment shall be operated in accordance with the following performance 

specifications (PS) set forth in Appendix B of 40 CFR Part 60 as amended, incorporated 

herein by reference. 

o NOx-PS2 

o 02-PS3 

CEMs shall have data gathering and retrieval capability that meet the reporting 

requirements of 40 CFR part 60.7(c), 60.7(d), and 60.13. This system shall include 

equipment that measures and records the following: 

o Flow rate of liquids or gases and the ratio of water or steam to fuel added to the 

combustion chamber or to the exhaust for the reduction of N& emissions, as 

applicable. 

o Elapsed time of operation. 

fuel burning TSD 6-14-02 Created on 611 812002 9:32:00 AM 
Facilities shall provide periodic source test data to demonstrate the gas turbine unit's 

exhaust gas N& concentration, and the demonstrated percent efficiency, or the 

manufacturer's rated efficiency, and the carbon monoxide concentration as specified in 

this rule. N& and carbon monoxide concentrations shall be in ppm by volume, 

corrected to 15 percent oxygen on a dry basis. 

The source test frequency shall be at least once every 12 months. 

Stationary Internal Combustion Engines 

As required by the Department, facilities shall conduct periodic source tests to 

demonstrate compliance with specified NOx and CO limitations. Test results shall be 

submitted to the Department within 30 days of completion of testing. 

Pollutant emissions shall be expressed in the applicable units of the standard. 

5.4.3 Rule 1 - Recordkeeping and Reporting 

Facilities subject to this rule shall comply with the following recordkeeping and reporting 

requirements. 

All records shall be maintained for a period of five years and be made available to the 

Department upon request. 

Facilities shall maintain an operating log that includes, at a minimum on a monthly basis, 

the total hours of operation; type and quantity of fuel used, and cumulative hours of 

operation and fbel specific heat input to date for the calendar year for each fuel-burning 

unit. 

Facilities shall maintain a record of all maintenance and tuning procedures performed on 

each fbel-burning unit. 

Facilities shall maintain a record of all fuel specification data required for compliance 

with this rule 

Facilities using an emission control system as a means of complying with this rule shall 

maintain daily records of system operation and maintenance to demonstrate continuous 

operation and compliance of the emission control device during periods of emission 

producing activities. 

The results of periodic source tests required by this rule shall be submitted to the 

Department within 30 days after testing is completed. 

Facilities required to install CEMs shall submit to the Department a written report of 

excess emissions for each calendar quarter and the nature and cause of the excess 

emissions, if known. The averaging period used for data reporting shall correspond to the 

averaging period specified in the emission standard for the pollutant source category in 

question. The required report shall include, as a minimum, the data stipulated in this rule. 

For continuous opacity measurements, the summary shall consist of the magnitude in 

actual percent opacity of all six-minute opacity averages greater than any applicable 

standards in these rules for each hour of operation of the source. 

For gaseous pollutant measurements the summary shall consist of emission averages in 

the units of the applicable standard for each averaging period during which the applicable 

standard was exceeded. 

fuel burning TSD 6-14-02 Created on 611 8/2002 9:32:00 AM 
The date and time identifying each period during which the continuous emission 

monitoring system was inoperative, except for zero and span checks and the nature of 

system repair or adjustment shall be reported. The Department may require proof of 

continuous emission monitoring system performance whenever system repairs or 

adjustments have been made. 

When no excess emissions have occurred and the continuous emission monitoring 

system(s) have not been inoperative, repaired, or adjusted, such information shall be 

included in the report. 

Facilities shall maintain a file of all information reported in the quarterly summaries, and 

all other data collected either by CEMs or as necessary to convert monitoring data to the 

units of the applicable standard for five years from the date of collection of such data or 

submission of such summaries. 

fuel burning TSD 6-14-02 Created on 611 W2002 9:32:00 AM 
ATTACHMENT 1 

A. Equipment Tuning procedure1 for Forced-Draft Boilers, Steam Generators, and Process 

Heaters 

Nothing in this EQuipment Tuning Procedure shall be construed to require any act or omission 

that would result in unsafe conditions or would be in violation of any regulation or requirement 

established by Factory Mutual, Industrial Risk Insurers, National Fire Prevention Association, 

the California Department of Industrial Relations (Occupational Safety and Health Division), the 

Federal Occupational Safety and Health Administration, or other relevant regulations and 

requirements. 

Should a different tuning procedure be used, a copy of this procedure should be kept with the 

unit records for five years and made available to the Department on request. 

1. Operate the unit at the firing rate most typical of normal operation. If the unit experiences 

significant load variations during normal operation, operate it at its average firing rate. 

2. At this firing rate, record stack gas tem erature, oxygen concentration, and CO concentration 

(for gaseous fuels) or smoke-spot numbe 3 (for liquid fuels), and observe flame conditions after 

unit operation stabilizes at the firing rate selected. If the excess oxygen in the stack gas is at the 

lower end of the range of typical minimurn values3, and if CO emissions are low and there is not 

smoke, the unit is probably operating at near optimum efficiency - at this particular firing rate. 

However, complete the remaining portion of this procedure to determine whether still lower 

oxygen levels are practical. 

3. Increase combustion air flow to the hace until stack gas oxygen levels increase by one to 

two percent over the level measured in Step 2. As in Step 2, record the stack gas temperature, 

CO concentration (for gaseous fuels) or smoke-spot number (for liquid fuels), and observe flame 

conditions for these higher oxygen levels after boiler operation stabilizes. 

4. Decrease combustion air flow until the stack gas oxygen concentration is at the level measured 

in Step 2. From this level gradually reduce the combustion air flow, in small increments. After 

each increment, record the stack gas temperature, oxygen concentration, CO concentration (for 

gaseous fuels) and smoke-spot number (for liquid fuels). Also observe the flame and record any 

changes in its condition. 

5. Continue to reduce combustion air flow stepwise, until one of these limits is reached: 

a. Unacceptable flame conditions - such as flame impingement on furnace walls or burner 

parts, excessive flame carryover, or flame instability. 

b. Stack gas CO concentrations greater than 400 ppm. 

fuel burning TSD 6-14-02 Created on 6/1812002 9:32:00 AM 
c. Smoking at the stack. 

d. Equipment-related limitations - such as low windbox/furnace pressure differential, 

built in air-flow limits, etc. 

6. Develop an 02/C0 curve (for gaseous fuels) or 02/smoke curve (for liquid fuels) similar to 

those shown in Figures 1 and 2 using the excess oxygen and CO or smoke-spot number data 

obtained at each combustion air flow setting. 

7. From the curves prepared in Step 6, find the stack gas oxygen levels where the CO emissions 

or smoke-spot number equal the following values: 

The above conditions are referred to as the CO or smoke thresholds, or as the minimum excess 

oxygen level. 

Gaseous 

#1 and #2 oils 

#4 oil 

#5 oil 

Other oils 

Compare this minimum value of excess oxygen to the expected value provided by the 

combustion unit manufacturer. If the minimum level found is substantially higher than the value 

provided by the combustion unit manufacturer, burner adjustments can probably be made to 

improve fuel and air mixing, thereby allowing operation with less air. 

8. Add 0.5 to 2.0 percent of the minimum excess oxygen level found in Step 7 and reset burner 

controls to operate automatically at this higher stack gas oxygen level. This margin above the 

minimum oxygen level accounts for fuel variations, variations in atmospheric conditions, load 

changes, and nonrepeatability or play in automatic controls. 

Measurement 

CO Emissions 

smoke-spot number 

smoke-spot number 

smoke-spot number 

smoke-spot number 

9. If the load of the combustion unit varies significantly during normal operation, repeat Steps 1- 

8 for firing rates that represent the upper and lower limits of the range of the load. Because 

control adjustments at one firing rate may affect conditions at other firing rates, it may not be 

possible to establish the optimum excess oxygen level at all fig rates. If this is the case, choose 

the burner control settings that give best performance over the range of firing rates. If one firing 

rate predominates, settings should optimize conditions at that rate. 

Value 

400 ppm 

number 1 

number 2 

number 3 

number 4 

10. Verify that the new settings can accommodate the sudden load changes that may occur in 

daily operation without adverse effects. Do this by increasing and decreasing load rapidly while 

he1 burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
observing the flame and stack. If any of the conditions in Step 5 result, reset the combustion 

controls to provide a slightly higher level of excess oxygen at the affected firing rates. Next, 

verify these new settings in a similar fashion. Then make sure that the final control settings are 

recorded at steady-state operating conditions for future reference. 

1 1. When the above checks and adjustments have been made, record data and attach combustion 

analysis data to boiler, steam generator, or heater records indicating name and signature of 

person, title, and date the tuneup was performed. 

B. Equipment Tuning Procedure for Natural Draft-Fired Boilers, Steam Generators, and 

Process Heaters. 

Nothing in this Equipment Tuning Procedure shall be construed to require any act or omission 

that would result in unsafe conditions or would be in violation of any regulation or requirement 

established by Factory Mutual, Industrial Risk Insurers, National Fire Prevention Association, 

the Federal Occupational Safety and Health Administration, or other relevant codes, regulations, 

and equipment manufacturers specifications and operating manuals. 

Should a different tuning procedure be used, a copy of this procedure should be kept with the 

unit records for five years and made available to the Department on request. 

1. PRELIMINARY ANALYSIS 

a. CHECK THE OPERATING PRESSURE OR TEMPERATURE. 

Operate the boiler, steam generator, or heater at the lowest acceptable pressure or temperature 

that will satisfy the load demand. This will minimize heat and radiation losses. Determine the 

pressure or temperature that will be used as a basis for comparative combustion analysis before 

and after tuneup. 

b. CHECK OPERATING HOURS. 

Plan the workload so that the boiler, steam generator, or process heater operates only the 

minimum hours and days necessary to perform the work required. Fewer operating hours will 

reduce fuel use and emissions. For units requiring a tuneup to comply with the rule, a totalizing 

non-resettable fuel meter will be required for each fuel used and for each boiler, steam generator, 

and heater to prove fuel consumption is less than the heat input limit in therms per year specified 

in the rule. 

c. CHECK AIR SUPPLY. 

Sufficient fresh air supply is essential to ensure optimum combustion and the area of air supply 

openings must be in compliance with applicable codes and regulations. Air openings must be 

kept wide open when the burner is firing and clear from restriction to flow. 

d. CHECK VENT. 

fuel buming TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Proper venting is essential to assure efficient combustion. Insufficient draft or overdraft 

promotes hazards and inefficient burning. Check to be sure that vent is in good condition, sized 

properly and with no obstructions. 

e. COMBUSTION ANALYSIS. 

Perform an "as is" combustion analysis (COY 02, etc.) with a warmed up unit at high and low 

fae, if possible. In addition to data obtained from combustion analysis, also record the following: 

i. Inlet fuel pressure at burner (at high & low fire) 

ii. Draft above draft hood or barometric damper 

1) Draft hood: high, medium, and low 

2) Barometric Damper: high, medium, and low 

iii. Steam pressure, water temperature, or process fluid pressure or temperature entering 

and leaving the boiler, steam generator, or process heater. 

iv. Unit rate if meter is available. 

With above conditions recorded, make the following checks and corrective actions as necessary: 

2. CHECKS & CORRECTIONS 

a. CHECK BURNER CONDITION. 

Dirty burners or burner orifices will cause boiler, steam generator, or process heater output rate 

and thermal efficiency to decrease. Clean burners and burner orifices thoroughly. Also, ensure 

that he1 filters and moisture traps are in place, clean, and operating properly, to prevent plugging 

of gas orifices. Confirm proper location and orientation of burner diffuser spuds, gas canes, etc. 

Look for any burned-off or missing burner parts, and replace as needed. 

b. CHECK FOR CLEAN BOILER, STEAM GENERATOR, OR PROCESS HEATER TCTBES 

& HEAT TRANSFER SURFACES. 

External and internal build-up of sediment and scale on the heating surfaces creates an insulating 

effect that quickly reduces unit efficiency. Excessive fuel cost will result if the unit is not kept 

clean. Clean tube surfaces, remove scale and soot, assure proper process fluid flow and flue gas 

flow. 

c. CHECK WATER TREATMENT & BLOWDOWN PROGRAM. 

he1 burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Soft water and the proper water or process fluid treatment must be uniformly used to minimize 

scale and corrosion. Timely flushing and periodic blowdown must be employed to eliminate 

sediment and scale build-up on a boiler, steam generator or process heater. 

d. CHECK FOR STEAM, HOT WATER OR PROCESS FLUID LEAKS. 

Repair all leaks immediately since even small high-pressure leaks quickly lead to considerable 

fuel, water and steam losses. Be sure there are no leaks through the blow-off, drains, safety 

valve, by-pass lines or at the feed pump, if used. 

3. SAFETY CHECKS 

a. Test primary and secondary low water level controls. 

b. Check operating and limit pressure and temperature controls. 

c. Check pilot safety shut off operation. 

d. Check safety valve pressure and capacity to meet boiler, steam generator or process heater 

requirements. 

e. Check limit safety control and spill switch. 

4. ADJUSTMENTS 

While taking combustion readings with a warmed up boiler, steam generator, or process heater at 

high fie perform checks and adjustments as follows: 

a. Adjust unit to fire at rate; record fuel manifold pressure. 

b. Adjust draft andfor fuel pressure to obtain acceptable, clean combustion at both high, medium 

and low fire. Carbon Monoxide (CO) value should always be below 400 parts per million (PPM) 

at 3% 02. If CO is high make necessary adjustments. 

Check to ensure boiler, steam generator, or process heater light offs are smooth and safe. A 

reduced fuel pressure test at both high and low fire should be conducted in accordance with the 

manufacturers instructions and maintenance manuals. 

c. Check and adjust operation of modulation controller. Ensure proper, efficient and clean 

combustion through range of £iring rates. 

When above adjustments and corrections have been made, record all data. 

5. FINAL TEST 

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AM 
Perform a final combustion analysis with a warmed up boiler, steam generator, or process heater 

at high, medium and low fire, whenever possible. In addition to data fiom combustion analysis, 

also check and record: 

a. Fuel pressure at burner (High, Medium, and Low). 

b. Draft above draft hood or barometric damper (High, Medium and Low). 

c. Steam pressure or water temperature entering and leaving boiler, steam generator, or 

process heater. 

d. Unit rate if meter is available. 

When the above checks and adjustments have been made, record data and attach combustion 

analysis data to boiler, steam generator, or process heater records indicating name and signature 

of person, title, company name, company address and date the tuneup was performed. 

 his hlning procedure is based on a tune-up procedure developed by KVB, Inc. for the United 

States EPA. 

'The smoke-spot number can be determined with ASTM Test Method D-2156 or with the 

Bacharach method. ASTM Test Method D-2156 is included in a tuneup kit that can be purchased 

fiom the Bacharach Company. 

'~~~ical minimum oxygen levels for boilers at high firing rates are: 

1. For natural gas: 0.5% - 3% 

2. For liquid fuels: 2% - 4% 

fuel burning TSD 6-14-02 Created on 611 8/2002 9:32:00 AM