MEMORANDUM

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

FROM: Amanda Singleton and Bryan Lange, ERG

DATE: January 2011

SUBJECT: Gas Specification for Industrial, Co mmercial, 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 natura l gas (NG) and refinery gas (RFG) in response to public comments received about other gaseous fuels with qualities similar to thes e fuels, and how such other clean gases should qualify for a work prac tice standard in the final regulations for industrial, commercial, and institu tional boilers at major sources of hazardous ai r pollutants. Based are on the results of the analys es described in this memorandum, a gas specification has been developed that includes specific requirement s for levels of mercury (Hg) and hydrogen sulfide (H 2 S) in the other gaseous fuels. In order for EPA to expand the work practices under section 112(h) of the Clean Air Act gaseous fu els other than NG and RFG must demonstrate that they will have similar measur ement difficulties as those mentioned in the preamble to the final rule. A ga s specification was developed fo r Hg, a regulated pollutant for this source category, as well as H2S, a constituen t 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 w ith the emission limits for the units designed to burn other gases (Gas 2) sub category. 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 Te sts for Units Firing Gaseous Fuels



## 2.0 LITERATURE SEARCH AND COMMUNICATION WITH STAKEHOLDERS

2.1 Mercury

During the literature search Ca lgon marketing literature for im pregnated carbon was identified which characterized a typical mercury range for North America NG as 0.005 to 40 micrograms per cubic meter (ug/m 3 ). 1 It should be noted that Calgon designs mercury removal system and their knowledge of processing plan ts 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 merc ury in NG produced in Wyoming, Colorado, Texas, Louisiana, and in gas produced on o ffshore platforms located in the Gulf of Mexico. The amount of mercury found in co mposite 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/m 3 are not common, but it should not be characterized as an outlier. Approximately 10 percent have pre- control mercury concentrations of 10 ug/m 3and higher, 40% have pre-control merc ury concentrations of 0.5 to 10 ug/m 3 , and 50% have extremely low or non-dete ctable 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 compan ies state there is “no mercury.” 3 Mercury in NG is a concern at the processing pl ant, 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 methan e 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/m 3 . Calgon removal solutions are designed to remove mercury to less than 0.1 ug/m 3

.

As a result of these findings, a mercury specifi cation was established to the level equivalent to the maximum concentration of mercury identified in NG, 40 ug/m 3 . 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 combuste d during the emission tests that showed levels below the level that can be accurately measured. This specification was also compared to me rcury emission test data reported by other gaseous fuel boilers in the 2008 Questionnaire fo r 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 re ported from NG and RFG units reported levels consistently below the specifica tion. Appendix A shows 33 different mercury tests firing solely gaseous fuels. All of the tests firing NG or RF G, with one exception for an inconsistently reported detection level, are be low the specification for mercur y. Other gases such as hydrogen, biogas, and landfill gas also demonstrate seve ral instances of mercury data below the specification. Units firing coke oven gas either al one or in combination with other fuels were the only units that reported mercur y levels above the specification.



### 2.2 ChlorineRegulatory precedent was investigated for chlorine specification in NG. Although no instances were identified for chlorine, two othe r 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. Furthe r, pursuant to 40 CFR 63.111, the definition of a halogenated vent stream current ly limits halogens to 45 kg/hr in order to reduce the formation of dioxin and dioxin-like compounds for the Na tional Emission Standards for Hazardous Air Pollutants for Source Categories; Organic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry an d Seven Other Processes (HON).

A number of locations were reviewed to identify acceptable chlorine content for NG; however, none were found and no specification wa s 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 halogena ted 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 const ituents present and the concentrations of these

constituents. NG obtained at the wellhead can unde rgo treatment or processing prior to its use for material compatibility reasons. H 2 S is both highly toxic and aci dic enough to precipitate corrosion. Gas is required to be sweetened to contain no more than a quarter grain H 2 S per 100 standard cubic feet (4 parts per million). 6 Carbon dioxide, like H 2 S, 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 a queous solutions of diethanolamine (DEA), monoethanolamine (MEA), methyldiethanol amine (MDEA), and diglycolamine (DGA). 7 A variety of emerging technologies are av ailable including Shell-Paques/Thiopaq a biotechnological processes whose first commercial unit began operations in 2002. 8 Processes that

remove H 2 S would also be expected to remove other contaminants such as chlorine.



## 3.0 IMPACT ON AFFECTED SOURCE INVENTORYTo estimate the number of affected units that may fall above the specification and could potentially remain in the gas 2 subcategory, the re ported stack test results were analyzed. Of the 33 test results available for units firing solely ga seous fuels, 9 tests showed mercury levels above the specification. Sinc e each of these units burn coke ove n 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 C OG would meet the limits for the gas 2 subcategory, and the appropriate control cost s 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 subcategor y 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 ha s 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 consider ably lower than source testing at the stack exhaust (e.g., EPA Method 5). The fuel flow s hould be laminar and isokinetic sampling is not required. It can cost approxi mately $300 to rent a cleaned /blanked/evacuat ed canister. Once received, the sample would be anal yzed 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 Mercur y 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 es timated that the cost of analysis is $200 per sample. EPA has included the above ASTM me thods in the final rule. The following ISOmethods, also included in the rule, should pr oduce comparable results: ISO 6978-1(2003) and ISO 6978-2(2003) (Natural Gas, Determin ation 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 meas ure 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 con cerns of pollutant variability over time.



## 5.0 REFERENCES

1. Calgon Carbon Corporation. Mercury Rem oval from Gas Streams (SA-AB1025-1004). 2004.

2. McNamara, Dave. Calgon Carbon Corporati on. Personal Communication via email to Bryan Lange, ERG. November 5, 2010.

3. Beal, Lisa. Interstate Natural Gas Associat ion of America. Personal Communication via email to Bryan Lange, ERG. December 3, 2010.

4. Singleton, A. and G. Gibson, ERG. Revised St andardization 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 Combus tion 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/nor eg/170-01395.pdf&fro mPage=GetDoc>

7. EPA Office of Air Quality Planning & Sta ndards. Emission Inventory Improvement Program, Technical Report Series, Volume 2 - Point Sources: Chapter 10 - Preferred and Alternative Methods for Estimating Air Em issions from Oil and Gas Field Production and Processing Operations. September 1999.

8. C. Cline et al. Biological Process for H2 S 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 FuelsFacilityID CombustorID SourceTabReported Value(lb/mmBtu)Relationshipto Fuel Spec.(2.47E-06)Control Device Fuel Gas 1% Gas 2% Other % NoteWICharterSteel P31 Phase II Metals From Test Report 1.16E-09BelowNo Equipment Natural gas 100 0 0ILUSSGraniteCity No. 8 Galvanizing Line Furnace Metals 3.32E-08BelowSelective Catalytic Reduction (SCR) Natural gas 100 0 0NCCampLejeuneMCB C-AS-4151-16 Metals 9.35E-08BelowNo Equipment Natural gas 100 0 0ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.00E-07BelowNo Equipment Natural gas/Nitrile Pitch Residue 87.80487805 0 12.195122LAShellChemicaGeismar Furnace F-S801 ERT 1.07E-07BelowNo Equipment Heavy Recycle/Natural gas/Petrochemical process gas 32.75665692 55.47534853 11.7679946ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.20E-07BelowNo Equipment Natural gas/Nitrile Pitch Residue 88.0952381 0 11.9047619CAConocoPhilipsLosAng D146 B-202 U90 PM and Metals (11) 1.21E-07BelowNo Equipment Refinery gas 100 0 0INNucorSteel Cold Mill Annealing ERT 1.29E-07BelowNo Equipment Natural gas 100 0 0INArcelorMittalBurnsHarbor Hot Dip Coating Line Annealing Furnace ERT 1.51E-07BelowSelective Catalytic Reduction (SCR) Natural gas 100 0 0INTateLyleSagamore 21B501 ERT 1.58E-07BelowNo Equipment Biogas/Natural gas 66.66859555 33.33140445 0ILAkzoNobelMorris B-1 Nebraska Boiler Metals 1.60E-07BelowNo Equipment Natural gas/Nitrile Pitch Residue 85.71428571 0 14.2857143CAExxonMobil-Torrance 25F-2A PMandMetals(25F-1+2)050190 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0CAExxonMobil-Torrance 25F-1A PMandMetals(25F-1+2)050190 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0CAExxonMobil-Torrance 25F-2B PMandMetals(25F-1+2)050190 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0CAExxonMobil-Torrance 25F-2B PMandMetals(25F-1B&2B)050190(2) 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0CAExxonMobil-Torrance 25F-1B PMandMetals(25F-1B&2B)050190(2) 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0CAExxonMobil-Torrance 25F-1B PMandMetals(25F-1+2)050190 2.30E-07BelowSelective Catalytic Reduction (SCR) Hydrogen 100 0 0INRollsRoyceIndianapolis 70-65 PM and Metals 2.51E-07BelowNo Equipment Landfill Gas 0 100 0SCMichelinSandySprings B:02:01 ERT 3.55E-07BelowNo Equipment Natural gas 100 0 0SCBMWManufacturingCo HB03 Metals 3.59E-07BelowNo Equipment Landfill Gas 0 100 0KSCoffeyvilleRefinery EU-39-FH0027 ERT 3.63E-07BelowNo Equipment Refinery gas 100 0 0WYSinclairWyoming Pt 74 #2 H2 Plant Heater ERT 6.15E-07BelowSelective Catalytic Reduction (SCR) Natural gas 100 0 0WYSinclairWyoming Pt 41 #9 HPB ERT 7.02E-07BelowNo Equipment Refinery gas 100 0 0UTWestinghouse 202 ERT 7.50E-07BelowNo Equipment Natural gas 100 0 0CAExxonMobil-Torrance 24F-1 PMandMetals(24F-1)011008 1.14E-06BelowSelective Catalytic Reduction (SCR) Natural gas/Process Gas/Refinery GasINOutokumpuStainlessPlate Heppenstall Annealing Furnace Phase II Metals From Test Report 1.17E-06BelowNo Equipment Natural gas 100 0 0MNStPaulParkRef EU 026 EU 026 Metals 1.87E-06BelowNo Equipment Refinery gas 100 0 0INArcelorMittalBurnsHarbor No. 11 Boiler Additional Hg from comments - test 1 4.85E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0INArcelorMittalBurnsHarbor No. 8 Boiler Additional Hg from comments - test 1 5.11E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0INArcelorMittalBurnsHarbor No. 12 Boiler Additional Hg from comments - test 1 5.20E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 6 94 0INArcelorMittalBurnsHarbor No. 12 Boiler Additional Hg from comments - test 2 5.22E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 6 94 0INArcelorMittalBurnsHarbor No. 8 Boiler Additional Hg from comments - test 2 5.74E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0INAlcoaWarrick Pre-Heat Furnace #36 ERT 5.88E-06AboveNo Equipment Natural gas 100 0 0 (a)INArcelorMittalBurnsHarbor No. 11 Boiler Additional Hg from comments - test 2 6.20E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0WVMountainStateCarbonFollansbee S1 Phase II Metals From Test Report 6.20E-06AboveNo HAP APCD Control Coke Oven Gas 0 100 0INArcelorMittalBurnsHarbor No. 9 Boiler Additional Hg from comments - test 2 7.94E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0INArcelorMittalBurnsHarbor No. 9 Boiler Additional Hg from comments - test 1 8.08E-06AboveNo Equipment Blast Furnace Gas/Coke Oven Gas/Natural gas 12 88 0a - 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 above spec.The fuel specification is described below:40(μg/m3)from Calgon Corporation2.47E-06 lb/mmBtu using HHV of Natural Gas of 1,012.75 Btu/ft3, as per Table B-2 of Standardization Memo.