MEMORANDUM 

TO: Brian Shrager, U.S. Environmental Protection Agency, OAQPS/SPPD 

FROM: Amanda Singleton and Bryan Lange, ERG 

DATE: January 2011 

SUBJECT: Gas Specification for Industrial, Commercial, Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants – Major 

Source 

1.0 INTRODUCTION 

The purpose of this memorandum is to discuss the development of a specification for 

gaseous fuels other than natural gas (NG) and refinery gas (RFG) in response to public 

comments received about other gaseous fuels with qualities similar to these fuels, and how such 

other clean gases should qualify for a work practice standard in the final regulations for 

industrial, commercial, and institutional boilers at major sources of hazardous air pollutants. 

Based are on the results of the analyses described in this memorandum, a gas 

specification has been developed that includes specific requirements for levels of mercury (Hg) 

and hydrogen sulfide (H2S) in the other gaseous fuels. In order for EPA to expand the work 

practices under section 112(h) of the Clean Air Act gaseous fuels other than NG and RFG must 

demonstrate that they will have similar measurement difficulties as those mentioned in the 

preamble to the final rule. A gas specification was developed for Hg, a regulated pollutant for 

this source category, as well as H2S, a constituent commonly used to distinguish sweet gas from 

raw gases in the NG pipeline industry. Therefore, units burning gaseous fuels other than NG or 

RFG have several options. They must either: (1) demonstrate that the fuel meets the 

specifications; (2) clean up the fuel to meet the specifications; (3) stop burning the fuel and use 

NG/RFG instead; or (4) demonstrate compliance with the emission limits for the units designed 

to burn other gases (Gas 2) subcategory. Units burning NG or RFG, as defined in the final rule 

are not required to meet the gas specifications. 
This memorandum is organized as follows: 

1.0 Introduction 

2.0 Literature Search and Communication with Stakeholders 

2.1 Mercury 

2.2 Chlorine 

2.3 Hydrogen Sulfide 

3.0 Impact on Affected Source Inventory 

4.0 Measurement Methods / Costs 

5.0 References 

Appendix A: Mercury Performance Tests for Units Firing Gaseous Fuels 

2.0 LITERATURE SEARCH AND COMMUNICATION WITH 

STAKEHOLDERS 

2.1 Mercury 

During the literature search Calgon marketing literature for impregnated carbon was identified 

which characterized a typical mercury range for North America NG as 0.005 to 40 micrograms 

per cubic meter (ug/m3).1 It should be noted that Calgon designs mercury removal system and 

their knowledge of processing plants and gas streams is focused on those that have mercury or 

are suspected of having mercury contamination. Calgon was contacted directly and asked to 

comment on the accuracy of this characterization.2

 Below is a summary of the discussed topics: 

 Calgon has found detectable levels of mercury in NG produced in Wyoming, Colorado, 

Texas, Louisiana, and in gas produced on offshore platforms located in the Gulf of 

Mexico. The amount of mercury found in composite stream entering the processing plant 

will change (sometimes daily) depending upon the volume and variety of wells being 

tapped at any given time. 

 Concentrations of 40 ug/m3

 are not common, but it should not be characterized as an 

outlier. Approximately 10 percent have pre-control mercury concentrations of 10 ug/m3
and higher, 40% have pre-control mercury concentrations of 0.5 to 10 ug/m3

, and 50% 

have extremely low or non-detectable mercury concentrations. 

 A compilation of tariff data, published by FERC in USA and NEB in Canada, shows that 

most of the 138 companies represented do not mention anything about mercury in 

pipeline quality gas and a few companies state there is “no mercury.” 3 Mercury in NG is 

a concern at the processing plant, not at the pipeline. 

 Processing plants define a safe Hg level as the level at which no equipment damage 

occurs. Mercury can foul catalysts, reducing their effectiveness, and can corrode/react 

with aluminum, a metal commonly used in the construction of the low temperature 

cryogenic equipment used to separate methane from the heavier/higher molecular weight 

hydrocarbons present in most raw NG streams. The lowest concentration that causes 

equipment damaging is 1 to 2 ug/m3. Calgon removal solutions are designed to remove 

mercury to less than 0.1 ug/m3. 

As a result of these findings, a mercury specification was established to the level equivalent 

to the maximum concentration of mercury identified in NG, 40 ug/m3

. This specification is 

based on the typical Hg concentrations that would be expected to have been present in the natural 

gas and refinery gas fuels that were combusted during the emission tests that showed levels 

below the level that can be accurately measured. 

This specification was also compared to mercury emission test data reported by other 

gaseous fuel boilers in the 2008 Questionnaire for Boilers, Process Heaters, Incinerators and 

Other Combustion Units (ICR No. 2286.01, OMB Control No. 2060-0616, EPA Form No. 5900-

122)5

 in order determine if the mercury data reported from NG and RFG units reported levels 

consistently below the specification. Appendix A shows 33 different mercury tests firing solely 

gaseous fuels. All of the tests firing NG or RFG, with one exception for an inconsistently 

reported detection level, are below the specification for mercury. Other gases such as hydrogen, 

biogas, and landfill gas also demonstrate several instances of mercury data below the 

specification. Units firing coke oven gas either alone or in combination with other fuels were the 

only units that reported mercury levels above the specification. 

2.2 Chlorine 
Regulatory precedent was investigated for chlorine specification in NG. Although no 

instances were identified for chlorine, two other regulations specify limits on halogens. The 

hazardous waste regulations maintain, pursuant to 40 CFR 261.3(a)(2)(v), that used oil shall 

contain less than 1,000 ppm total halogen. Further, pursuant to 40 CFR 63.111, the definition of 

a halogenated vent stream currently limits halogens to 45 kg/hr in order to reduce the formation 

of dioxin and dioxin-like compounds for the National Emission Standards for Hazardous Air 

Pollutants for Source Categories; Organic Hazardous Air Pollutants from the Synthetic Organic 

Chemical Manufacturing Industry and Seven Other Processes (HON). 

A number of locations were reviewed to identify acceptable chlorine content for NG; 

however, none were found and no specification was established. The 2008 ICR survey did not 

contain any chlorine data for NG units. 5 The Gas Research Institute reports indicate that chlorine 

is present in NG at trace levels significantly less than 1 ppmv.3 Given the limited information 

available on chlorine and halogenated contents in gaseous fuels, no specification was established 

for chlorine. No test methods were identified for measuring chlorine from NG or process gas.

2.3 Hydrogen Sulfide 

The composition of NG at the wellhead depends on the characteristics of the reservoir 

and is variable with respect to both the constituents present and the concentrations of these 

constituents. NG obtained at the wellhead can undergo treatment or processing prior to its use for 

material compatibility reasons. H2S is both highly toxic and acidic enough to precipitate 

corrosion. Gas is required to be sweetened to contain no more than a quarter grain H2S per 100 

standard cubic feet (4 parts per million).6

 Carbon dioxide, like H2S, forms acidic solutions in the 

presence of water and is also referred to as an acid gas. The most common method of acid gas 

removal, the amine process, utilizes aqueous solutions of diethanolamine (DEA), 

monoethanolamine (MEA), methyldiethanolamine (MDEA), and diglycolamine (DGA).7

 A 

variety of emerging technologies are available including Shell-Paques/Thiopaq a 

biotechnological processes whose first commercial unit began operations in 2002.8

 Processes that 

remove H2S would also be expected to remove other contaminants such as chlorine. 

3.0 IMPACT ON AFFECTED SOURCE INVENTORY 
To estimate the number of affected units that may fall above the specification and could 

potentially remain in the gas 2 subcategory, the reported stack test results were analyzed. Of the 

33 test results available for units firing solely gaseous fuels, 9 tests showed mercury levels above 

the specification. Since each of these units burn coke oven gas (COG) (or a blend of COG and 

other fuels), the data used to develop the MACT floor analysis for the gas 2 subcategory were 

based on units firing COG. Similarly, the cost and emission reduction impacts analysis assumed 

all of the 71 units greater than or equal to 10 mmBtu/hr firing COG would meet the limits for the 

gas 2 subcategory, and the appropriate control costs were estimated for each of these units. Since 

test results for hydrogen sulfide were not available in the 2008 ICR questionnaire, the impacts 

and MACT floor analysis for the gas 2 subcategory were based solely on the units consistently 

above the mercury specification. 

 

4.0 MEASUREMENT METHODS / COSTS 

 Analysis for Hg and H2S can be measured by an accredited laboratory. It is likely that the 

boiler or process heater firing a gaseous fuel has a valve installed on the inlet stream. A unit 

operator can connect a Summa canister (or a Tedlar bag) to the valve and mail the sample to a 

laboratory. 

Costs for sampling are expected to be considerably lower than source testing at the stack 

exhaust (e.g., EPA Method 5). The fuel flow should be laminar and isokinetic sampling is not 

required. It can cost approximately $300 to rent a cleaned/blanked/evacuated canister. 

Once received, the sample would be analyzed by the laboratory according to the 

following ASTM methods: 1) ASTM D5954 -98(2006) Standard Test Method for Mercury 

Sampling and Measurement in Natural Gas by Atomic Absorption Spectroscopy, 2) ASTM 

D6350-98(2003) Standard Test Method for Mercury Sampling and Analysis in Natural Gas by 

Atomic Fluorescence Spectroscopy, or 3) ASTM D4084-07 Standard Test Method for Analysis 

of Hydrogen Sulfide in Gaseous Fuels. It is estimated that the cost of analysis is $200 per 

sample. EPA has included the above ASTM methods in the final rule. The following ISO 
methods, also included in the rule, should produce comparable results: ISO 6978-1(2003) and 

ISO 6978-2(2003) (Natural Gas, Determination of Mercury – Parts 1 and 2). 

EPA regulations usually require stack tests be collected in triplicate. Part of the function 

of the triplicate stack test sampling is to measure the precision of the method. There are fewer 

variables with a fuel sample, especially a gaseous fuel sample and triplicate measurements were 

not determined to be necessary in order to demonstrate compliance with the specification. For 

gaseous fuels that are somewhat variable in nature, EPA has included a monthly sampling 

frequency in the final rule to address concerns of pollutant variability over time. 

5.0 REFERENCES 

1. Calgon Carbon Corporation. Mercury Removal from Gas Streams (SA-AB1025-1004). 

2004. 

2. McNamara, Dave. Calgon Carbon Corporation. Personal Communication via email to 

Bryan Lange, ERG. November 5, 2010. 

3. Beal, Lisa. Interstate Natural Gas Association of America. Personal Communication via 

email to Bryan Lange, ERG. December 3, 2010. 

4. Singleton, A. and G. Gibson, ERG. Revised Standardization of Reported Data from the 

Questionnaire for Boilers, Process Heaters, Incinerators and Other Combustion Units, 

January 2011. 

5. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process 

Heaters, & Other Combustion Units (ICR No. 2286.01). 

6. Dow Chemical. Gas Sweetening - Product Specified. 1998. 

<http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0039/0901b803800391f

8.pdf?filepath=gastreating/pdfs/noreg/170-01395.pdf&fromPage=GetDoc> 

7. EPA Office of Air Quality Planning & Standards. Emission Inventory Improvement 

Program, Technical Report Series, Volume 2 - Point Sources: Chapter 10 - Preferred and 

Alternative Methods for Estimating Air Emissions from Oil and Gas Field Production 

and Processing Operations. September 1999. 

8. C. Cline et al. Biological Process for H2S Removal from Gas Streams: The ShellPaques/THIOPAQŽ Gas Desulfurization Process. 53rd Laurance Reid Gas Conditioning 

Conference 2003. 
Appendix A. Mercury Performance Tests for Units Firing Gaseous Fuels

FacilityID CombustorID SourceTab Reported Value (lb/mmBtu) Relationship to Fuel Spec. (2.47E-06) Control Device Fuel Gas 

WICharterSteel P31 Phase II Metals From Test Report 1.16E-09 Below No Equipment Natural gas 

ILUSSGraniteCity No. 8 Galvanizing Line Furnace Metals 3.32E-08 Below Selective Catalytic Reduction (SCR) Natural gas 

NCCampLejeuneMCB C-AS-4151-16 Metals 9.35E-08 Below No Equipment Natural gas 

ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.00E-07 Below No Equipment Natural gas/Nitrile Pitch Residue 87.804

LAShellChemicaGeismar Furnace F-S801 ERT 1.07E-07 Below No Equipment Heavy Recycle/Natural gas/Petrochemical process gas 32.756

ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.20E-07 Below No Equipment Natural gas/Nitrile Pitch Residue 88.09

CAConocoPhilipsLosAng D146 B-202 U90 PM and Metals (11) 1.21E-07 Below No Equipment Refinery gas 

INNucorSteel Cold Mill Annealing ERT 1.29E-07 Below No Equipment Natural gas 

INArcelorMittalBurnsHarbor Hot Dip Coating Line Annealing Furnace ERT 1.51E-07 Below Selective Catalytic Reduction (SCR) Natural gas 

INTateLyleSagamore 21B501 ERT 1.58E-07 Below No Equipment Biogas/Natural gas 66.668

ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.60E-07 Below No Equipment Natural gas/Nitrile Pitch Residue 85.714

CAExxonMobil-Torrance 25F-2A PMandMetals(25F-1+2)050190 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

CAExxonMobil-Torrance 25F-1A PMandMetals(25F-1+2)050190 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

CAExxonMobil-Torrance 25F-2B PMandMetals(25F-1+2)050190 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

CAExxonMobil-Torrance 25F-2B PMandMetals(25F-1B&2B)050190(2) 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

CAExxonMobil-Torrance 25F-1B PMandMetals(25F-1B&2B)050190(2) 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

CAExxonMobil-Torrance 25F-1B PMandMetals(25F-1+2)050190 2.30E-07 Below Selective Catalytic Reduction (SCR) Hydrogen 

INRollsRoyceIndianapolis 70-65 PM and Metals 2.51E-07 Below No Equipment Landfill Gas 

SCMichelinSandySprings B:02:01 ERT 3.55E-07 Below No Equipment Natural gas 

SCBMWManufacturingCo HB03 Metals 3.59E-07 Below No Equipment Landfill Gas 

KSCoffeyvilleRefinery EU-39-FH0027 ERT 3.63E-07 Below No Equipment Refinery gas 

WYSinclairWyoming Pt 74 #2 H2 Plant Heater ERT 6.15E-07 Below Selective Catalytic Reduction (SCR) Natural gas 

WYSinclairWyoming Pt 41 #9 HPB ERT 7.02E-07 Below No Equipment Refinery gas 

UTWestinghouse 202 ERT 7.50E-07 Below No Equipment Natural gas 

CAExxonMobil-Torrance 24F-1 PMandMetals(24F-1)011008 1.14E-06 Below Selective Catalytic Reduction (SCR) Natural gas/Process Gas/Refinery Gas

INOutokumpuStainlessPlate Heppenstall Annealing Furnace Phase II Metals From Test Report 1.17E-06 Below No Equipment Natural gas 

MNStPaulParkRef EU 026 EU 026 Metals 1.87E-06 Below No Equipment Refinery gas 

INArcelorMittalBurnsHarbor No. 11 Boiler Additional Hg from comments - test 1 4.85E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas INArcelorMittalBurnsHarbor No. 8 Boiler Additional Hg from comments - test 1 5.11E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas INArcelorMittalBurnsHarbor No. 12 Boiler Additional Hg from comments - test 1 5.20E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas INArcelorMittalBurnsHarbor No. 12 Boiler Additional Hg from comments - test 2 5.22E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 

INArcelorMittalBurnsHarbor No. 8 Boiler Additional Hg from comments - test 2 5.74E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas INAlcoaWarrick Pre-Heat Furnace #36 ERT 5.88E-06 Above No Equipment Natural gas INArcelorMittalBurnsHarbor No. 11 Boiler Additional Hg from comments - test 2 6.20E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas WVMountainStateCarbonFollansbee S1 Phase II Metals From Test Report 6.20E-06 Above No HAP APCD Control Coke Oven Gas INArcelorMittalBurnsHarbor No. 9 Boiler Additional Hg from comments - test 2 7.94E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas INArcelorMittalBurnsHarbor No. 9 Boiler Additional Hg from comments - test 1 8.08E-06 Above No Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas a - Mercury was non-detect, but the detection level is higher than spec. Data from ERT does not match test report, data from test report file 166925 B MACT Test Report.pdf p. 42 updated here in spreadsheet and will be updated in database. This is the only NG datapoint reporting abovThe fuel specification is described below:

40 (μg/m3) from Calgon Corporation

2.47E-06 lb/mmBtu using HHV of Natural Gas of 1,012.75 Btu/ft3, as per Table B-2 of Standardization Memo.