### 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 ControlTechnologies 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/LocalRegulations


### ........ -9



## ....................... 4.4 

### Analysis of SourceCategory 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



### ............................ Section2.0


### . Electric Utility Steam GeneratingEquipment 27 

### Section 3.0

. 

### Industrial, Commercial, and InstitutionalBoilers. Steam



## ...................................................................... Generators. and Process Heaters 28 

### Section 4.0


### . Stationary Gas Turbines


### ............................................................. 29 

### Section 5.0


### . Stationary Internal CombustionEngines


## .................................... 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 TSD6-14-02 Created on 6118R002 9:32:00AM

### 1.0 Introduction & SourceDescription 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 combustionunits. 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 extedcombustion sources are limited to smaU and mid-sized natural gas, distillate fuel oil, and waste oil fiedprocess heaters, space heaters, and boilers. Liquefied petroleum fuels are alsoused 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 ofhazardous 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 similarto 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 electricpower, to pump gas or other fluids, or to compress air for pneumatic 

### machinery. N& CO and VOC are,themajor pollutants of concern from stationary internal fuel combustion sources. Trace quantitiesoftoxic 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 stationaryintemal 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 cumbustionturbines).

1United Metro Plant No. 4 1

fuel burning TSD 6-14-02 Created on 6118r2002 9:32:00 AM23456789 

### 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 ofthe 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), sulkoxides (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 criteriapollutant emissionmechanisms and controls isprovided below by pollutant category. Particulate Matter Emissions PM composition and emission levels from solid fuel combustion (generally associated with boilers) are a complex function ofboiler 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 affectsthe PM emissionrate 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, filterableparticulate matter emissions depend predominantly on the grade of fuel 

### fired. Combustion of lighter distillate oilsresults in significantly lower PM formationthan does combustion ofheavier residual oils. The PM 

### emitted by distillate oil-fired boilers primarily comprises carbonaceous particlesresulting 

### fromincomplete combustionof oil 

### and is not correlated to the ash or sulfk content of the oil. However, PM emissionsfiom residual oil burning are related to the oil sulkcontent. For waste oil combustion without airpollution controls, higher concentrations of ash and trace metals in the waste fuel translate to higher emissionlevelsof PM and trace metals than is the case for virgin he1oils. Particulate emissions may 

### be categorized as either filterable or condensable. Filterable emissions are generally considered to 

### be theparticles 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 micronspass through 

### the filter. Condensableparticulate matter ismaterial that 

### is emitted 

### in the vapor state which later condensesto form homogeneous andlorheterogeneous aerosol particles. Condensable PM istypically measured by analyzing the impingers, or "back half' ofthe

U.S. EPAAP-42 Fifth Edition Section 1.1, Bituminousand SubbituminousCoal Combustion- September 1998. 3 U.S. EPAAP-42 Fifth Edition Section 1.3, Fuel Oil Combustion. September, 1998.

U.S. EPAAP-42 Fifth Edition Section 1.4, Natural Gas Combustion. July, 1998. U.S. EPAAP-42 Fifth Edition Section 1.11, Waste Oil Combustion. October 1996. U.S. EPAAP-42 Fifth Edition Section 3.1, Stationary Gas Turbines. April 2000. 7 U.S. EPAAP-42 Fifth Edition Section 3.2, Natural Gas-fired Reciprocating Engines. February 1997. 

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

fuel burning TSD 6-14-02 Created on 6/18/20029:32:00AM 3sampling train. The collection, recovery, and analysis of the impingers are described in EPA Method 202 of Appendix M, Part 

### 5 1 of the Code ofFederal Regulations. Condensable PM is composed of organic and inorganic compounds and is generally consideredto 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, filterablePM 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 condensablehctions. Particulate matter in natural gas combustionis usually larger molecularweight hydrocarbonsthat arenot fully combusted. Increased PM emissions may result fiom poor aidfuel mixing or maintenanceproblems. ParticulateMatter 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, controllingthe rate of load changes, and ensuring steady, uniform fuel feed. Proper design and operation ofthe combustion air delivery systemscan also minimizePM emissions. The postcombustion control of PM emissions fiom fuel combustion sourcescan 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 largerboilers, including coal, wood waste, andresidual 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 determineESP 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 ofparticle and operational characteristics. Particle characteristics that affect the collection efficiency includeparticle size distribution, particle cohesion characteristics, and particle electricalresistivity. Operationalparametersthat affect fabric filter collectionefficiency include air-to-cloth ratio, operating pressure loss, cleaning sequence, interval between cleanings, cleaning method, and cleaning intensity. Collection efficiencies of fabric filters can be 

### as high as 99.9 percent. Wet scrubbers, including venturi and flooded disc scrubbers, tray or tower units, turbulent contact absorbers, or high-pressure spray impingement scrubbers are applicable for PM as well as SO2control on fuel oil and coal-fired combustion sources. Scrubbercollection efficiency dependson 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 sothat these devices can be

fuel burning TSD 6-14-02 Created on 6118120029:32:00 AM 4specified for lower particle loadings to reduce capital andforoperating 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 ofparticles less than 10micron (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 sulfurcompounds present in the fuel are oxidized during the combustionprocess. 

### 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 orwood 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 ofthe fuel sulhis convertedto SO2, about 1to 5 percent is Mer oxidized to sulfurtrioxide (SO3), 

### and 1to 3percent is emitted 

### as &ate particulate. SO3readily reacts with water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist. Emissions of SO2fiom naturd gas-fired sources are low because pipeline quality natural gas typically has sulklevelsof 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. SulfurDioxide Emission Controls Post combustion flue gas desulfkization 

### (FGD) techniques can remove SO2formed during combustionby using an alkalinereagent to absorb SO2 in the flue gas. Flue gases can be treated using wet, dry, or semi-dry desulfurizationprocesses of either the throwaway type (in which all waste 

### streams are discarded) or the recoverylregenerabletype (in which the SO2absorbent is regenerated and reused}. To date, wet systems are the most commonly applied. Wet systems generally use alkali slurries as the SO2absorbent medium and can be designedto remove greater 

### than 90 percent ofthe incoming SO2.Lirne/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the commercially proven wet FGD systems.The effectiveness of these devices dependsnot only on control device design but also on operatingvariables. Particulate reduction of more 

### than 99 percent ispossible with wet scrubbers on coal 

### fired units, but fly ash is often collected by upstream ESPs or baghouses, to avoid erosion ofthe desulfhization equipment and possible interference with FGD process reactions. For fuel oilfired 

### units, these systems

### can achieve SO2removal efficienciesof 

### 90to 95 percent 

### and particulate control efficiencies of 50 to 

### 60 percent. Nitrogen Oxides Emissions Oxides ofnitrogen (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 shownthat NOx concentrationis exponentially dependenton temperature, and proportional to N2concentration in the flame, the

fuel burning TSD 6-14-02 Created oa 6118i2002 9:32:00 AM 5

### square root of O2concentration in the flame, and the residence time. Thus, the formation of thermal NOx is affected by four factors: (1) 

### peak temperature, 

### (2) fuelnitrogen 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 ofboilers: 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 80percent oftotal N& £?om coal combustion. Fuel nitrogen conversion is the more importantNOx forming mechanism in residual oil boilers as well. It can account for 50 percent ofthe total N& emissions £?om residual oil firing. Thermal fixation, on the other hand, is the dominantNOx forming mechanism in units firing distillate oils, primarily because ofthe negligible nitrogen content in these lighter oils. The principal mechanism ofNq( formationin natural gas combustion is also thermal NOx. The predominant mechanism with 

### internal combustion engines is thermal N&. Most thermal N& isformed in 

### the high-temperature region of the flame from dissociated molecular nitrogen in the combustion

### air. SomeN&, called prompt N&, is formed in 

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

### no chemically bound fuel Nz and essentially all N& formed isthermal N&. Nitrogen Oxides Emission Controls The primary Nq( control techniques can be classified into one oftwo fundamentally different methods, combustion controls and postcombustion controls. Combustion controls reduce NOx by suppressingN& formation during the combustion process, while postcombustion controls reduce NOx emission after their formation. Combustion controls are the most widely used method of controllingN& formationin all types ofboilers and include low excess 

### air, burners out of service, biased-burner firing, flue gasrecirculation, overfire 

### air, and low-NOx burners. Postcombustioncontrol methods include selectivenoncatalytic reduction (SNCR) and selective catalyticreduction (SCR). To reduce fuelN& formation, the most common combustion modificationtechnique is to suppress combustion air 

### levels below the theoretical amount required for complete combustion. The lack ofoxygen createsreducing conditionsht, given sufficienttime at 

### high temperatures, cause volatile fuel nitrogen to convertto N2rather than NO. There are three 

### generic types of emission controls in use for gas turbines, wet controls using steam or water injectiontoreduce combustion temperaturesfor N& control, dry 

### controls using 

### advanced combustor design to suppressN& 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 emissionssince they are the primary pollutants £?om these engines. From 

### a N& control viewpoint, the most important distinctionbetween 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 combustionprocess. 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 concentrationsof CO (as well as organic compounds) may increase by several orders ofmagnitude. Smaller boilers, heaters, 

### and furnacestypically emit more CO and 

### organicsthan 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 equipmentused 

### to reduce NOx can increase CO emissions ifthe modification techniques are improperly implemented or ifthe equipment isimproperly designed. As with CO emissions, the rate at which organic compounds are emitted depends on the combustion efficiency of the boiler. Therefore, combustion modificationsthat change combustionresidence time, temperature, or turbulence may increase or decrease concentrations of organic wmpundsin 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 

### areprimarily characterized by the criteriapollutant class of unburned vapor-phase hydrocarbons. These emissions include alkanes, alkenes, aldehydes, alcohols, 

### and substitutedbenzenes. The remaining organic emissions 

### are corn@ largely of compounds emitted fiom combustion sources in a condensedphase. These compounds can almost exclusivelybe 

### classed into a group known 

### as polycyclic organic matter (POM), and a subset of compndscalledplynuclear aromatic hydrocarbons(PNA or

### PAH). 3.2 

### Emission UnitPollutant Matrix Emissionunits 

### and pollutants associated with external and internalfuel 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 9:32:00AM 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'MI0, SO2,NOx, CO, VOC, HAP PMA'MIO, SO2,NOx, CO, Voc, HAP NOx, CO, VOC, SO2,PMI0, 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, HAP4.0 Regulatory Review and Proposed Rule Derivation 4.1 Tribal ProgramsIRules A comprehensive review ofU.S. tribal air quality programs was performed to define the baseline of existing tribal rules and source specific standards. The summary findings ofthis 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 applicableto the fbel combustion equipment source category as defined in this document. Those standards are: NSPS Subpart D - Standardsof Performancefor Fossil Fuel Fired Steam Generators for Which Construction is Commenced After August 17,1971 NSPS Subpart Da 

## - Standardsof Performance for Electric Utility Steam GeneratingUnits for Which Construction is Commenced After September 18,1978 NSPS Subpart Db - Standardsof Performancefor Industrial-Cornexid-Institutional Steam GeneratingUnits NSPS Subpart Dc - Standardsof Performance for Small Industrid-Cornexid-Mtutional Steam Generating Units NSPS Subpart GG - StandardsofPerformance 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 SubpartDDDDD (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> 10tpy for a single 

### HAP or > 25 tpy for total combined 

### HAP). It is not expected that the MACT standardswill apply to any current GRIC sources. The GRIC DEQ has elected to incorporateby 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 emissionsfiom electricutilities to reduce acid rain. These requirements were not reviewed for the development ofthis TSD.

fuel burning TSD 6-14-02 Created on 6/18/20029:32:00 AMRelevant 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/LocalRegulations To define State, regional, and local air quality rules applicable to the source categoriespresent 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 ofGRIC source categories. The summary State rule screening file, STATEMATRIX.xls, is included in the RTP file set developed for the GRIC 

### TIPproject. From this, specificrule 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 ofthe broad representation of StateLocal rules affectingfuel combustion equipment, only a subset of programswere reviewed. StateRegionaULocalrules were selected for considerationin 

### TIP developmentbased on stringency, technical merit (e.g., units, averaging times, etc.), presentation, and enforceability considerations.The following StateRegionaVLocalprograms were reviewed: Arizona Air Regulations
- Rule R18-2-703: Standards of Performance for ExistingFoss-il-fuel Fired Steam Generatorsand General Fuel-burning Equipment
- Rule R18-2-724: Standards ofPerformance for Fossil-fuel Fired Industrial and Commercial Equipment Maricopa County

### Air Regulations
- Rule 3 11: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 fromNatural Gas-Fired Water Heaters
- Regulation 9, Rule 7: Nitrogen Oxides and Carbon Monoxide from Industrial, Institutional, and CommercialBoilers, 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 11: Nitrogen Oxides and Carbon Monoxide from Electric Power Generating Steam Boilers CaliforniaAir Resources Board South Coast Air Quality Management District Air Regulations

fuel burning TSD 6-14-02 Created on 6/18/2002 9:32:00AM- Rule 1 110: Emissions from Stationary Internal Combustion Engines

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

- Rule 1 121:Control ofNitrogen Oxides from Residential-Type, Natural-GasFired Water Heaters

- Rule 1134: Emissions of Oxides ofNitrogen from Stationary Gas Turbines

- Rule 1 135 Emissions of Oxides ofNitrogen from Electric Power Generating Equipment
- Rule 1146Emissions of Oxides ofNitrogen from Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters 

### - Rule 1146.1 Emissions of Oxides ofNitrogen from Small Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters
- Rule 1146.2 Emissions of Oxides ofNitrogen 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 GeneratingUnits

- 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

- Subchapter3: Control and Prohibition of Smoke from Combustionof Fuel

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

- Subchapter9: Sulfbr in Fuels

- Subchapter 10: Sulfur in Solid Fuels

- Subchapter 16: Control and Prohibition of Air Pollution by Volatile Organic Compounds (16.8, 16.9, 16.10)
- Subchapter 19: Control and Prohibition ofAir Pollution from Oxides ofNitrogen

- Subchapter20: Used Oil Combustion North CarolinaAir 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 ofthe 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 6-14-02Createdon 6/18/2002 9:32:00AM 10fuel burning equipment. Note that emission limits expressed as heat input driven equations (mainly particulate matter limitations)were not considered. Equation based limitations are difficultto 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) staterule 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. 

### SummaryofEmission Limits and Standards: Fuel Burning 

### Equipment

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

fuel burningTSD 6-14-02 Created on 6/18/2002 9:32:00 AM 12 Source (Reference) NSPS SubpartDa GeorgiaRule (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 SubpartDa

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

## 1 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 71911997) 0.15 lb/MMBtu (sources modified after 7/911997) 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 (he1oil) 0.70 lWMMBtu (coal) 0.15 Ib/MMBtu(after May 1,2003) 0.30 lb/MMBtu (after May 1,2000) 0.34 lWMMBtu (afterMay 1,1999) 0.15 -0.20 lb/MW-hr (phased emission limit schedule, afterDecember 3 1, 1999) 10,25,30ppmvd @ 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

NOxSub-category

Fuel Burning Equipment 150-250 Burning Equipment > 100MMBtu/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 OnlyCyclone: 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) 1000ppmvd @ 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/MMBtumax. 2-hr. avg. (liquid fbel) 1.2 lb/MMBtumax. 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 sulkoil) 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 (he1oil) 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-minuteperiodihr)

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 SubpartD

NSPS SubpartD GeorgiaRule (d) NSPS SubpartD Georgia Rule (g) OregonDiv. 228 Arizona Rule 703

NSPS Subpart D

Georgia Rule (d) Oregon Div. 228

NSPS SubpartDb

fuel buming TSD 6-14-02 Created on 6/184002 9:32:00AMSub-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/municipalsolid 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 OnlyCyclone: 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 (highsulfur oil) Permit renewal or modification triggers condition prohibitinguse ofhigh sulf. oil (unless demonstrated infeasibleby source) 1.0 lb/MMBtu (coal) NJAC 7:27-16.8

>= 5 MMBtu/hr and greater than 9E+9 Btu/yr fueluse: 40 ppmvd (0.05 Ib/MMBtuheat input) >= 5 MMBtulhr and less than 9E+9Btulyr 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 greaterthan 25% annual capacity factor and greater than 9E+9 Btu/yr fuel use: SCAQMD Rule I146

40 ppmvd Gaseous Fuel >= 10MMBtu/hr ( BAAQMD 30ppmvd@3%O2 Non-Gaseous Fuel >= 10MMBtu/hr 40 ppmvd @ 3% O2 Rule 9-7

fuel burningTSD 6-14-02 Created on 611812002 9:32:00AM 14fuel burning TSD 6-14-02 Created on 611812002 9:32:00 AM 15 Source (Reference) SCAQMD Rule 1146 & 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 > 10MMBtuh > 1OMMBtuh <250 MMBtu/hr Fuel Burning Equipment > 10MMBtu/hr < 100MMBtuh

Fuel Burning Equipment < 10MMBtuh 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 SubpartDc 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/billionBtu) heat output or 55 ppmv @ 3 % O2dry basis Units > 400,000 =<2 MMBtu/hr 30 ppmvd @ 3 % O2dry basis or 0.037 lb/MMBtuheat input Units > 400,000

# - 2 MMBtu/hr 400 ppmvd @, 3 % O2dry basis ~nits>2and

### <r~~~tu/hr: 30 ppm or 0.037 lb/MMBtu Units with annualheat input =< 18,000therms: Maintain stack-gas O2=<3 % 02dry basis for any 15 consecutiveminute averaging Equipment (all) Georgia Rule (d)
SCAQMD Rule 1146.2

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. 228I1 Includes all stationary gas andlor oil-fired turbines and oil-fued stationaryinternal combustion engines. Pinal County Article 23 regulation contains an exemption for emergency use IC engines <325bhp and operated <72 hrlyr. 12Note: N& limit includes thermal efficiency correctionEFF/25% of source can demonstratehigher efficiency.

fuel burning TSD 6-14-02Created on 6/18/2002 9:32:00 AM 16 Source (Reference) BAAQMD Rule 9-1 NSPS SubpartDc 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 IndustrialEquip. 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 < 100MMBtu/hr) <3.0 % S fuel (sources > 100MMBtuflu) No. 2 Fuel Oil & Lighter 0.2 -0.3 % S dependingon 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 SolidFuel 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 inputbased equation 1 .O lb/MMBtu (low sulkoil)

Stationary Gas Turbines

9 ppmvd @ 15 % O2averaged over 15 min. 15ppmvd ifno SCR 9 ppmvd @ 15 % O2averaged over 15 min. 12ppmvd ifno SCR 

### so2 N& 2.2 lb/MMBtu (high sulfur oil) Permit renewal or modification triggers condition prohibiting use ofhigh 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 15min. >= 2.9 < 10.0 MWhe1burning 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 GeorgiaRule (mmm) BAAQMD Rule 9-8
SCAQMD Rule 111 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 % O2averaged over 15 min. 15 ppmvd if no SCR Simple Cycle Turbines >= 30 MMBtu/hrheat 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/shortterm testing) >= 10.0 hfw 9 ppmvd @ 15 % O2 with SCR (25 ppmvd for gas curtailment/short term testing) 15ppmvd if no SCR (42 ppmvd for liquid fueYgas curtailment/shortterm testing) 250 ppmvd @ 15 % O2 50ppmvd @ 15 % O2 No. 1 on Ringlemann Smoke Chart or 20 %
30,42, 80, 160ppmvd @ 15 % 02, phased compliance

, schedule

Rich-Bum: 56ppmvd@15%02 Lean-Bum: 140ppmvd@15%02 Rich-Bum: 90 ppmvd @ 1 5 % O2averaged over not < 1 5 consecutive minutes Lean-Bum: 2.Oglbhp-hr(O.75pglJ); 150ppmvd@15% O2averaged 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

36ppmvd @ 15 % O2averaged over 15 minutes 250 ppmvd @ 15 % O2(as methane) averaged over 15 min.

pp 2000 ppmvd @, 15 % O2averaged over 15 minutes 500 ppmvd 0,15 % O2Source Pollutant/ Sub-category Parameter & Liquid 

### -Fueled

Central

# urna aces I Natural-Gas-Fired 

### 1 NOxNatural-GasFired, Fan-Type N@i 

# :Emission Limits/Standards/Controls

Water Heaters (Residential) SparkIgnition: I 80 ppmvd @ 15 % O2averaged over 15 minutes (1.5 I glbhp-hr) 

# ' Compression Ignition (>50,<I17 bhp):

80ppmvd @ 15 % O2averaged over 15 minutes (1.5 glbhp-hr) Compression Ignition (>I17,<400 bhp): 550 ppmvd @ 15 % O2averaged over 15 minutes (7.2 glbhp-hr) Compression Ignition (>400bhp): 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 %O2averaged over 15 minutes (2.0 gbhp-br) 40 ng/J (as NOz) ofuseful heat deliveredto heating space Phased certification requirements: 40,20,10ng/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 burningTSD 6-14-02 Created on 6/18/2002 9:32:00 AMSource Sub-category used Oil Combustion Pollutant/ Parameter General EmissionLimitsIStandardslControls Space Heaters Registrationrequired 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, orpermit required Space heaters must be listed and tested by nationally recognized lab equivalentto UL Annual combustion process adjustment required Space Heater Used Oil Limits (non-permit): Arsenic-5 ppmw Cadmium -2 ppmw Chromium - 10ppmw Lead - 100ppmw Flash point - 100 degrees F Total halogens - 1000ppmw Sulfur

### - 5000 ppmw On-spec Used Oil Combustion by Permit Protocol for conductingair quality analysis and risk assessment Equipment and control details Necessary certifications Demonstrationthat Used Oil is On-Specification Facility analysis or supplier analysis documentation for each shipmentof used oil Copies of aaalysesretained 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-SpecificationUsed Oil Permitrequired Control device requirements Source (Reference) 

# r--l

NJAC 7:27-20

fuel burning TSD 6-14-02 Created on 6118120029:32:00 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 SubpartsD, 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 limitationsexist in state and local 

### air quality regulations, 20% represents a reasonable and defendable standard, largely consistent with neighboringregulatoryjurisdictions. Compliance with this 

### limit on fuel burning equipmentis achievable through equipment upkeepJmaintenanceand good operating practice. Unless otherwise specified 

### in a category-specific de, EPA Method 

### 9 wasproposed as the default opacity determinationmethod. Fuel sulfur limitations of 1.75,0.50, and 1.0percent 

### 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 limitationsreviewed and isbelieved to be 

### consistent

### with current, reasonably available fossil fbel specifications. The definition of and provisions/exclusionsrelating 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 GeneratingEquipment A PM emissions limit of 0.03 lb-tu heat input was proposed for this source category. This limit is consistent with NSPS SubpartDa, which applies to new or modified electric utility steam generating units. No sources currently operating on GRIC land fall within 

### the electricutility source category. Any new source locating on GRIC land in the 

### futurewould be 

### subject toNSPS SubpartDa (as well as potentially NSR/PSD, Title V, CAM, Acid Rain Program, etc.). The proposed PM limit represents a reasonableminimum standard for incorporation into the 

### TIP. The proposed electric utility steam generating equipment SO2emission limit (0.80 lb/MMBtu) is consistent

### with the maximum NSPS SubpartDa requirement for gaseous and liquid fuels (i.e., not including percent reduction requirements). No separate limit for coal firing isproposed 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 6/18R0029:32:00 AMThe proposed 0.80 IblMMBtu SO2limit is consistent 

### with the Pinal County Chapter 

### 5, Article 22, Maricopa County Rule 320, and Arizona Rules 703 provisions applicable to low sulkfie1 oil and coal-fired sources installed after 1972-1975. It is also consistent 

### with the SO2standards in several other stateprograms reviewed, including Georgia and Oregon. The proposed electricutility 

### steam generating equipmentNOx emission limit of 1.6 lb/MW-hr energy output is consistent with the NSPS SubpartDa requirement for sources constructed after July 9,1997. This proposed limit is more stringentthan the Pinal County, Maricopa County, and Arizona NOx standards applicableto electric utility sources, which mirror the NSPS for sources installed or modified prior to July 9,1997. However, no electricutility steam generatingunits 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 subjectto more stringent limitationsthan the proposed standard (e.g., BACT). Theproposed limit is defensible based onNSPS, and represents a reasonableminimum baseline standard for NOx emissions form utility steam generating equipment. The limit is expressed on a gross energy outputbasis, which also encourages energy efficiency along with emissions control. A CO emission limit of400 ppmvd @ 3% O2was proposed for this source category. This limit is consistentwith BAAQMD Rule 9-1 1 and SCAQMDRule 1146. It is less stringent 

### thanother state regulations such 

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

# a. Not all state regulatoryprograms contain CO limitations.No specific fie1burning 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 combustionunit design and operating practices. Also, with NOx requirements becoming evermore stringent, tradeoffs often exist between NOx reduction and CO emissions increases. 400 ppm rep~esents a reasonable maximum steady state (periodic compliancetest 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 sourcecategory was divided into two subcategories, units greaterthan or equal to 100 

### MMBW heat input capacity and units greaterthan or equal to 10

### MMBtuihr but less than 100 

### MMBtuJhrheat input capacity. The 100

### MMBtu/hr threshold is consistent with NSPS Subpart 

## . Db, and representsa logical break point in unit capacity and emissions control cost effectiveness. Units less than 10

### MMBtu/hrheat input capacity were deemed to be less consequential fiom an emissions standpoint, with comprehensive emission limitations yielding little environmental benefit in comparison with the regulatoryburden. Therefore, only the general fuel burning equipment standards (e-g., opacity and fuel sulkcontent 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 consistentwith NSPS Subpart Db and Dc requirements for fuel oil and fuel oil fired in combination with other fuels. It is also consistent with other staterule limits (e.g., GeorgiaRule

he1 burning TSD 6-14-02 Created on 6118/2002 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-specificN& emission limit of 0.20 lb/MMBtuheat input was proposed for units greater than 

### 100

### MMBtu/hr. This limit is consistentwith 

### NSPS SubpartDb 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-specificN& emissionsto 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 staterules. The proposed 0.20 lb/MMBtuN& limit is less stringent 

### thancurrent BACT, yet reflective of current combustionand control technology. It represents a reasonable minimum baseline for NOx emissions control for this source category. No specificNOx limits are proposed for units between 10 and 100

### MMBtu/hr. [SUGGESTADDING 40 PPM N& @ 

### 3% 02Limit for this category] An 

### SO2emission limit of 0.80 lb/MMBtu was proposed for sources greater than 100MMBtu/hr. Again, this limit is consistent with NSPS SubpartDb 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 controlsto comply with the proposed SO2limit. A CO emission limit of 400 ppmvd @ 

### 3% O2was proposed for this source category. This limit is consistent with BAAQMD Rule 9-7 and SCAQMD Rule 1146. It is less stringent 

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

### 7% 02. 

### Not all stateregulatoryprograms contain CO limitations. No specific fuelburning 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 requirementsbecoming ever more stringent, tradeoffsoften exist between

### NOx reduction and CO emissionsincreases. 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 achievablethrough good combustionpractices. Section4.0 

### - Stationary Gas Turbines NSPS Subpart

### GG,which appliesto 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 SO2emissionsfiom "Rotating Machinery," including gas turbines, to 1.0 and 2.2 lb/MMBtu for low sulfurand high sulfur fuel oil, respectively. Since most stationary turbinestypically fire natural gas, except duringperiods of gas curtailment or other under backup fuel scenarios, SO2 emissions are normally not a concern. A limit on the sulk content ofhe1oil fired in 

### gasturbines offers a practical and straightforwardmethod of limiting SO2emissions fkom this source category. A limit of 0.5% sulfur for fuel oil 

### fired in gas

fuelburning TSD 6-14-02 Created on 6/18/20029:32:00 AM

### turbines isproposed. This is consistent with the distillate fuel oil sulfur content limit proposed under the general limitations section ofthis standard (see Section 1.0). Stationary gas turbine NOx standardswere 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 BACTLAERrequirementsbelow 10ppm NOx. Therefore, the primary purpose ofthis standard is to set presumptive BACT for non-NSR/PSD major installations. NSPS SubpartGG 

### regulates gas turbines with a heat input at peak load greater 

### than 10.7 gigajoules per hour (10 

### 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 9ppm (for natural gas) and can be 

### aslow 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 15ppmvd 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 SCAQMDRule 1134 (see Table 4-1). The proposed limits are believed to represent a reasonable presumptiveBACT level for non-major source gas turbines. 

### A CO limit of 250 ppmvd 

### @ 15 % 

### O2during steady-state compliance test conditions was proposed for this source category. This limit is consistent with BAAQMD Rule 9-1 1 and less stringent 

### thanthe 100ppmvd 

### @ 7 % 

### O2limit contained in New Jersey Rule 7:27-16.8. No specific fuel burning equipment CO standardsare contained 

### in the Maricopa County, 

### Pinal County, or Arizona Rules. Again, this proposed limit is believed to constitute a reasonable level ofpresumptive BACT for non-major gas turbines. Section 5.0 

## - Stationary Internal CombustionEngines 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 suppressionif operated less 

### than 500 hours per year. This is consistentwith 

### Pinal County Chapter 5, Article 

### 23. No specific standards applicabletoIC engines or rotating machinery are contained 

### in the Maricopa County Rules. No rotating machinery exemption levels 

### are contained in Arizona Rule 719. 

### 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 1 110.1 

### 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-hrwas proposed. Again, this limit is consistentwith 

### New Jersey Rule 7:27-19.8.

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

### A CO emission limit of 2000 ppm @ 

### 15 % 

### O2was proposed for all stationary IC engines subject to the standard. This limit is consistent with 

### SCAQMDRule 1 11

### 0.2. It is less stringent

### than the 500 ppmvd limit contained 

### in New Jersey Rule 7:27- 16.10. 

### 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 standardsfor used oil fuing. 5.0 

### Proposed 

### GRICFuel 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 combustionreciprocating engines, and internal combustion engines used for emergencypower generation. Compliance with the provisions ofthis rule shall not relieve any person subjectto the requirements ofthis rule fiom complyingwith 

### any other federally enforceableNew Source Pedormance StandardsorNational Emission Standardsfor Hazardous Air 

### Pollutants. In 

### such case, the more stringent standard shall apply 5.2 DEFINITIONS Ash means the residue remaining afterthe 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 

### isused 

### to mversensible 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 combustionequipment. 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

### thisregulation. Combinedcyclesystem 

### 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. Combustionunit 

### means a unit into which fuel is charged and heated to the point at which oxidation occursand energy is generated.

fuel burning TSD 6-14-02 Created on 6/1U20029:32:00 AMDistillate oil 

### means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the specifications for fuel oil numbers 

### 1and 2, as definedby 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 ofproducing steam, including fossil-fuel-fired steam generators associated 

### with combined cycle gas turbines. Engine 

### means any spark- or compression-ignitedinternal combustionengine, not including engines used for self-propulsion. Fuel 

### means combustiblematerial 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 liquefiablepetroleum product burned for lighting or for the generation ofheat or power and derived directly or indirectly from crude oil. Full capacity 

### means operation ofthe fuel burning unit at 90 percent or more ofthe 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 ofthe fuel. This does not include the sensibleheat of incoming combustion air. Heat Output 

### means the enthalpy ofthe working fluid output ofthe unit. Lean-BmEngine 

### 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 statebasis, as determined by the physical design and 

### characteristics ofthe unit. Wtu 

### means million British Thermal Units Naturalgas 

### means (1) a naturally occurring mixture 

### ofhydrocarbon and nonhydrocarbon gases found 

### in geologic formationsbeneath the earth's surface, ofwhich the principal constituent is methane; or (2) liquid petroleum gas, as defined by the American Society for Testing and Materials in ASTM Dl835-82, "Standard Specificationfor Liquid Petroleum Gases" Number 

### 1 fuel oil 

### means fuel oil ofthe grade that is classified 

### as Number 1, according to ASTM Standard Specification for Classificationof Fuel Oilsby ASTM D396-84. Number Zfiel oil 

### means fuel oil ofthe grade that is classified as 

### Number 2, according to ASTM Standard Specification for Classification of Fuel Oils by ASTM D396-84. Number 6fieloil 

### means fuel oil ofthe grade that is classified as 

### Number 6, 

### according to ASTM Standard Specification for ClassificationofFuel Oils by ASTM D396-84. NOxEmissions 

### means the sum of nitrogen oxide and nitrogen dioxide in 

### the flue gas, collectively expressed as nitrogen dioxide. On-speciJcation usedoil 

### 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 specificationsme 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 itselfor in or on a piece of equipment, is designed to be and capable of being carried or moved from one location to another. Indicationsofportability include, but are not limited to, wheels, skids, carryinghandles, dolly, trailer, platform or mounting. The owner or operator must demonstratethe necessity of the engine being periodically moved from one location to another because of the nature ofthe 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 adorgaseous 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. 

### Ifthe combustionunit has 

### been alteredormodified 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 ofaGas Turbine Unit

### means the continuousMW 

### (megawatt) rating or mechanical equivalentby a mandacturer for gasturbine 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 quareinch absolute. Standard CubicFoot 

### means the amount of gas that would occupy one cubic foot, ifthe gas were he ofuncombined water at standard conditions. When applied to combustion flue gases from fuel or 

### refuseburning, standard cubic foot also implies adjustment of gas volume to that which would result at 

### a concentrationof 12%

### carbon dioxide or 50% 

### excess

### air. Stationary Gas Turbine 

### means any gas turbine unit that is gas andor liquid fueled with or withoutpower 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 unitspowering one shaft shall be treated asone gas turbine unit. Stationary Internal CombustionEngine 

### (engine) means any spark compressionignited reciprocating internal combustion enginethat is attached to a 

### foundation at a location or is portable and operated at the location for more than one year, not including enginesused for selfpropulsion. Steamgenerating unit 

### means a device that combusts any 

### fuel or byproduct/waste to produce steam or to heat water or any otherheat transfer medium. This term includes any municipal-type solid waste incinerator with a heatrecovery steam generatingunit or any steam 

### generating unit that combustsfuel and ispart of a 

### cogeneration system or a combined cycle system. This term does not include process heaters.

fuel burning TSD 6-14-02 Created on 6/18120029:32:00AMUsed 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 impuritiesthrough storage or handling. Visiblesmoke means smoke that obscures light to a degree readily discernibleby visual observation. 

### 5.3 EMISSION LIMITATIONS 

### AND STANDARDS Section 1.0

# - General Limitations and Standards Applicability The provisions ofRule 1, Section 1.0 apply to all fuel burning equipment 

### as definedin 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 ofRule 1 shall not apply to combustion sources in residential dwellings where such sources 

### are used for heating or other domesticpurposes. VisibleEmissions Visible emissionsfrom 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 observationsin accordancewith 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 isthe only reason for failure of an emission unit to meet the applicable opacity limitation, that requirement shall not apply. Sulf;rDioxide SulfurContent of Fuels: Residual Fuel Oil Shall not exceed 1.75 percent sulfur by weight Distillate Fuel Oil Shall not exceed 0.5 percent sulfurby weight Coal Shall not exceed 1.0percent sulfurby weight Section 2.0 

## - Electric Utilitv Steam GeneratingEquipment Applicability The provisions of Rule 1, Section 2.0 apply to all electric utility steam generatingunits.

fuel burning TSD6-14-02 Created on 6/18/2002 9:32:00 AMParticulate Matter 

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

t, SulJirrDioxide SO2emissions 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 CarbonMonoxide 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 ofRule 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 SulJivDioxide 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 CarbonMonoxide CO emissions shall not exceed 400 ppmvd corrected to 3 percent oxygen

fuel burningTSD 6-14-02 Created on 6118R002932:00 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 

### shallbe tuned at least once per year 

### in accordancewith 

### the manufacturer's specified tune-up procedure or alternatetuning 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 SO2emissions shall not exceed 0.015 percent by volume, dry basis, corrected to 15 percent oxygen 

### Nitrogen Oxides Units 

### > = 

### 0.3, 

### < 10MW rated cavacity 

### N& emissions shall not exceed 42 ppmvd corrected to 15percent oxygen when firing gaseous he1 

### N& emissions shall not exceed 65ppmvd corrected to 15percent oxygen when firing fuel oil Units > = 

### 10MW 

### rated capacity 

### N@ emissions shall not exceed 15ppmvd correctedto 15percent oxygen when firing 

### gaseous fuel N@ 

### emissions shall not exceed 42 

### ppmvd corrected to 15percent oxygenwhen firing 

### fuel oil

fbel burningTSD 6-14-02 Created on 6/18/20029:32:00 AM

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

### 5.0 

## - Stationarv Internal Combustion Engines 

### Applicability The provisions ofRule 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 emergencypower generationor 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 

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

### 6.0 

## - Used Oil Combustion 

### Applicability The provisions ofRule 1, Section 6.0 applyto all sources which combust used oil as defined in this regulation. Sources include, but are not limited to space heaters, boilers, dryers, and kilns. 

### UsedOil 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 followinglimits: o Arsenic: 5 ppmw maximum o Cadmium: 2 ppmw maximum o Chromium: I0 ppmw maximum

fuel burning TSD 6-14-02Created on 6/18/2002 9:32:00AMo Lead: 100ppmw maximum o Flash point: 100 degrees F 

### minimum o Total halogens: 1000ppmw maximum o Sulfur: 5000ppmw maximum ~e~istratibn/~ermiffin~ Requirements Facilities combustingon-specification used oil in equipment with a total rated heat input capacity 

### <500,000 

### Btu/hr that are otherwisenot 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 combustingused 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 combustingused 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 specifiedby the Department in a constructionand/or operatingpermit, shall be performed in accordance with Rule and the followingEPA and ASTM reference methods and procedures, as amended, incorporated herein by reference: Fuel Analysis 

### - Coal Sampling and preparation procedures shall be in accordance with approvedASTM methods and procedures Analysis of gross caloric value (Btu content), moisture content, and percent sulbshall 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 ofthe fuel supplier certified fuel analysis for each shipment of fuel. The certification shall incIude name ofthe 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 ofthe fuel supplier certified fuel analysis for each shipment of fuel. The certification shall include name of the

fuel burningTSD 6-14-02 Created on 6118r20029:32:00 AM . 31supplier, statement that the oil complies with the specifications listed under "Definitions" for the particular grade of fbel, analysis results, including sulhcontent, 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 appropriatenumber oftest points for PM testing and velocity and volume flowrate 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 condensableparticulatematter. EPA Method 6 shall be used to determine compliancewith SO2 limitations. Compliance shall be determined by averaging six 20-minute samplestaken over such a 

### period of time that no more than 20 minutes elapsesbetween 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,COZCO, or N in the gas being sampled asnecessary to 

### determine the molecular weight ofthe gas being sampled. EPA Method 20 shall be used to determine

### NOx, SO2,and 02 concentrationsfrom stationary gas turbines and internal combustion engines EPA Method 10 shall be used to determinethe 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 fromthe Department, test methodsor procedures different from those in this Rule may be used ifthey will provide equivalent or more reliable results. Alternate test methods must be approved by the Department in writing. 5.4.2 MonitoringResuirements Electric Utility Steam Generating Equipment and Industrial, Commercial, and Institutional Boilers, Steam Generators, and Process Beaters > = 

### 100 

### MMBWrRated Heat Input Capacity The following monitoring requirements applyto all electricutility steam generating equipment and all industrial, commercial, and institutionalboilers, steam generators, and process heaters 

### > = 100MMBtu/hr rated heat input capacity. Except as provided below, facilities subjectto Rule 1, Section 2.0 and Rule 1, Section 3.0 (> = 100MMBtu/hrrated heat input capacity) shall install, calibrate, maintain, and

he1 burning TSD 6-14-02 Created on 6118D002 9:32:00 AM

### operate continuous monitoring systems (CEMs), and record the output of the systems, for measuringthe 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 distillatefuel 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 ofthe interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both 

### at the inlet and outlet ofthe sulkdioxide control system), alternate parameters indicative ofthe particulatematter 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 ofthe facility including periods of starhzp, 

### shutdown, malhction or emergency conditions, except for continuous monitoring systembreakdowns, 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 followingperformance specifications (PS) set forth in Appendix B of 40 CFR Part 60 as 

### amended, incorporatedherein by reference. o 

### Opacity-PS 1 o 

### NOx-PS2 0 

### SO2-PS2 o 

### O2andC02-PS3 Calibrationgases: Span and zero gases shall be traceable to National Bureau of Standardsreference 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) asamended: 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 shelflives 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 emissionmonitoring 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 33operation (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 ofprocess 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: Facilitiesrequired 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 suchrecommendations shall be followed. Facilities shall adjust the zero span wheneverthe 24-hour zero drift or 24-hour calibration 

### drift limits ofthe applicable performance specifications in Appendix 

### B of 

### Part 60, Chapter 1, Title 40 CFR 

### are exceeded. Span: Instrument span shouldbe approximately200% of the expected instrument data display output correspondingto the emission standard for the source. Minimum Data Requirements Facilitiesrequired to install continuous emission monitoring systems shall submit to the Department a written report of excess emissionsfor each calendar quarter and the nature and cause ofthe excess emissions, if known. The averaging period used for data reporting shall correspondto the averagingperiod 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 smaryshall consist ofthe magnitude in actual percent opacity of all 6-minute opacity averages greater than any applicable standards for each hour of operation ofthe facility. Average values may be obtained by integration over the averagingperiod or by arithmetically averaging a minimum of4 equally spaced, instantaneous opacity measurements per minute. Any time periods exempted shall be deleted before determining any averages in excess ofopacity standards. o For gaseous measurementsthe summary shall consist of emission averagesin the units ofthe applicable standard for each averagingperiod duringwhich 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, suchinformation shall be included in the report.

fuel burning TSD 6-14-02Created on 6/18/2002 9:32:00AMOwners or operatorsof affected facilities shall maintain a file of all informationreported in the quarterly summaries, and all other data collected either by the continuous emission monitoring system or as necessary to convertmonitoring data to the 

### units ofthe applicable standard for a minimum of 2 years 

### hm the date of collection of such data or submissionof such summaries. Data Reduction Owners or operatorsof affwted facilities shall use the procedures outlined in 

### EPA Reference Method 19, as amended, for converting monitoring datato 

### units ofthe 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 monitoringrequirements 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 demonstratecompliance 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 ofthe 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 ofthe systems, for measuring the following pollutants and parameters: o 

### NOx 0 02 Monitoring equipment shall be operated in accordance 

### with the followingperformance 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 capabilitythat 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 exhaustfor the reduction of

### N& emissions, 

### as applicable. o Elapsed time of operation.

fuel burning TSD 6-14-02 Created on 611 8120029:32:00 AMFacilities 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 15percent oxygen on a 

### dry basis. The source test frequency shall be at least once every 12months. Stationary Internal Combustion Engines As required by the Department, facilities shall conduct periodic source tests to demonstrate compliancewith specifiedNOx and CO limitations. Test results shall be submitted to the Department within 30 days of completion oftesting. Pollutant emissions shall

### be expressed in the applicable units ofthe standard. 5.4.3 Rule 1 

### -Recordkeeping and Reporting Facilities subjectto 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 availableto 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 operationand 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 datarequired for compliance with this rule Facilitiesusing an emission control system as a means of complying with this rule shall 

### maintain daily records of system operation and maintenance to demonstrate continuous operationand compliance ofthe emission control device during periods of emission producing activities. The results ofperiodic source tests required by this rule shall be submitted to the Department within 

### 30 days after testing is completed. Facilitiesrequired 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, ifknown. 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, asa minimum, the data stipulatedin this rule. For continuous opacity measurements, the summary shall consist ofthe magnitude in actual percent opacity of all six-minute opacity averages greater 

### thanany applicable standardsin these rules for each hour of operation of the source. For gaseouspollutant measurements the summary shall consist ofemission averagesin the units of the applicable standard for each averagingperiod during which the applicable standard was exceeded.

fuel burning TSD 6-14-02 Created on 6118/2002 9:32:00AM

### The date and time identifyingeach period during which the continuousemission monitoring system was inoperative, except for zero and span checks and the nature of systemrepair or adjustment shall be reported. The Department may require proof of continuousemission monitoring systemperformance whenever system repairs or adjustmentshave been made. 

### When no excess emissionshave occurred and the continuous emissionmonitoring 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 eitherby CEMs or asnecessary to convert monitoring 

### data tothe units of the applicable standard for five years from the date of collectionof such 

### data or submission of such summaries.

fuel burningTSD 6-14-02Created on 611W2002 9:32:00AMATTACHMENT 

### 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, IndustrialRisk Insurers, National Fire Prevention Association, the California Department of Industrial Relations (Occupational Safety and Health Division), the Federal Occupational Safety and Health Administration, or otherrelevant regulations and requirements. Should a different tuning procedure be used, a copy ofthis procedure should be 

### kept with 

### the unit records for five years and made available to the Departmenton 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 firingrate 

### selected. Ifthe excess oxygen in 

### the stack gas is at the lower end ofthe range oftypical minimurn

### values3, and if CO emissions are low and 

### there isnot smoke, the unit isprobably operating at near optimum efficiency 

## - at this particular firing rate. However, completethe remaining portion ofthis procedure to determine whether still lower oxygen levels are practical. 

### 3. Increase combustion

### air flow to the hace until stack gas oxygen levels increaseby 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 graduallyreduce the combustionair flow, in 

### small increments. After each increment, record the stack gas temperature, oxygen concentration, CO concentration(for gaseousfuels) 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 ofthese limits isreached:

a. Unacceptable flame conditions 

### - such as flame impingementon furnace 

### walls or burner parts, excessive flame carryover, or flame instability. b. Stack gas CO concentrationsgreater than 400 

### ppm.

fuel burning TSD 6-14-02 Created on 6/1812002 9:32:00AMc. 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/smokecurve (for liquid fuels) similar to those shown in Figures 1 and 2 using the excessoxygen and CO or smoke-spot number data obtained at each combustion 

### air flow setting. 

### 7. From the curvesprepared in Step 6, find the stack gas oxygen levels where the CO emissions or smoke-spot number equal the followingvalues:

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

Comparethis minimum value of excess oxygen to the expected value provided by the combustionunit manufacturer. Ifthe 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 

### airmixing, thereby allowing operation with less 

### air. 8. Add 0.5 to 2.0percent ofthe minimum excessoxygen level found in Step 7 and reset burner controlsto 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-spotnumber smoke-spot number smoke-spot number smoke-spotnumber

9. If the load of the combustionunit varies significantly during normal operation, repeat Steps 1- 8 for firing rates that represent the upper and lower limits of the range ofthe load. Because control adjustments at one firing rate may affect conditions at other firing rates, it may not be possible to establishthe optimum excess oxygen level at all fig rates. Ifthis is the case, choose the burner control settingsthat give best performance over the range of firing rates. If one firing rate predominates, settings should optimize conditionsat that rate. Value 400 ppm number 1 number 2 number 

### 3 number 4

10. Verify that the new settings can accommodatethe sudden load changes that may occur in daily operationwithout adverse effects. Do this by increasing and decreasing load rapidly while

he1 burning TSD 6-14-02 Created on 6/18/20029:32:00 AMobservingthe 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 

### finalcontrol settings are recorded at steady-state operating conditions for futurereference. 11. When the above checks and adjustmentshave been made, record data and attach combustion analysis data to boiler, steam generator, or heater records indicatingname and signature of person, title, and date the tuneup was performed. B. Equipment Tuning Procedurefor 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 establishedby Factory Mutual, Industrial Risk Insurers, National Fire PreventionAssociation, the Federal Occupational Safety and Health Administration, or otherrelevant codes, regulations, and equipment manufacturers specificationsand operating manuals. Should a different tuning procedure be used, a copy ofthis procedure should be kept with the unit records for five years and made availableto 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 necessaryto 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 optimumcombustion and the area of 

### air supply openings must be 

### in compliance with applicable codes and regulations. Air openingsmust 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 6/18/20029:32:00 AM

### Proper venting is essentialto assure efficientcombustion. Insufficient draft or overdraft promotes hazards and inefficientburning. Check to be 

### surethat 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, ifpossible. 

### In additionto data obtained from combustion analysis, also record the following: i. 

### Inlet fuel pressure at burner (at high & 

### low fire) ii. Draft above drafthood or barometric damper 1)

### Draft hood: high, medium, and low 2) BarometricDamper: high, medium, and low iii. Steampressure, 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 conditionsrecorded, make the followingchecks 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 orificesthoroughly. Also, ensure that he1filters and moisture traps 

### are in place, clean, and operating properly, 

### to prevent plugging of gas orifices. Confirm proper location and orientation ofburner 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. Cleantube surfaces,remove scale and soot, assure proper process fluid flow and flue gas flow.

c. CHECK WATER TREATMENT & 

### BLOWDOWN PROGRAM.

he1burning TSD 6-14-02 Created on 6/18/2002 9:32:00 AMSoft 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, ifused. 

### 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 fieperform checks and adjustments as follows: a. Adjust unit to fire at rate; record fuel manifold pressure. b. Adjust 

### draft andforfuel 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 processheater 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 maintenancemanuals.

c. Check and adjust operation ofmodulation 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 additionto data fiom combustionanalysis, 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 leavingboiler, 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 indicatingname and signature ofperson, 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 StatesEPA. '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 6118/2002 9:32:00 AM