FROM: Karen Schaffner, Kristin Sroka, and Jeff Coburn, RTI International 

TO: Brenda Shine, EPA/OAQPS/SPPD 

FOR: Petroleum Refinery NSPS Docket No. EPA-HQ-OAR-2007-0011 

DATE: January 24, 2012 

SUBJECT: Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment Unit 

Off-gas 

1. Introduction

On June 24, 2008, the U.S. Environmental Protection Agency (EPA) issued new source 

performance standards (NSPS) for petroleum refineries beginning construction, reconstruction, 

or modification after May 14, 2007 (40 CFR part 60, subpart Ja). Following promulgation, the 

EPA received petitions for reconsideration from: 1) the American Petroleum Institute (API), the 

National Petrochemical and Refiners Association (NPRA), and the Western States Petroleum 

Association (WSPA) (collectively referred to as “Industry Petitioners”); 2) HOVENSA, LLC; 

and 3) the Environmental Integrity Project, Sierra Club, and Natural Resources Defense Council 

(collectively referred to as “Environmental Petitioners”). Based on information provided by the 

petitioners, the EPA proposed amendments to subpart Ja regarding the requirements for flares 

and process heaters on December 22, 2008. 

The definition of “fuel gas” promulgated on June 24, 2008, in both 40 CFR part 60, subparts J 

and Ja, excluded “vapors that are collected and combusted to comply with the wastewater 

provisions in §60.692, 40 CFR 61.343 through 61.348, 40 CFR 63.647, or the marine tank vessel 

loading provisions in 40 CFR 63.562 or 40 CFR 63.651.” On December 22, 2008, the EPA 

proposed to remove §60.692 from the definition in subpart Ja (the definition in subpart J was not 

proposed to be amended). The commenters on the proposed amendments to the subpart Ja 

requirements requested that the EPA either: (1) remove the reference to any federal rules or 

(2) add references to additional federal rules for completeness. 

The purpose of this memorandum is to document the data and assumptions used to aid the EPA 

in evaluating whether vapors from marine vessel loading (MVL) units and wastewater treatment 

(WWT) units should be excluded from the definition of “fuel gas” and determining the best 

system of emission reduction (BSER) (formerly referred to as best demonstrated technology, or 

BDT) for thermal oxidizers and flares combusting MVL and WWT vapors. It is assumed that if 

new, reconstructed, and modified thermal oxidizers and flares installed to control emissions from 

MVL units and WWT units are required to meet the fuel gas combustion device (FGCD) or flare 

limits of 162 parts per million by volume (ppmv) hydrogen sulfide (H2S) or 20 ppmv sulfur 

dioxide (SO2) over a 3-hour rolling average, refinery owners and operators would have to install 

an amine treatment system. This memorandum documents the procedures and methodologies 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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January 24, 2012 

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used to estimate the costs (in 2006 dollars) and emission reduction impacts of installing and 

operating a remote amine treatment system. (Note that while owners and operators of a FGCD 

have the choice of meeting either the H2S limit or the SO2 limit, the H2S limit is the typical 

option elected for compliance, so this standard is referred to as the “short-term 162 ppmv H2S 

concentration limit” for convenience throughout the remainder of this memorandum.) 

2. Analysis 

A. Initial Assumptions 

For this analysis, it is assumed that there is one centralized fuel gas system at the refinery. 

Because MVL and WWT units are often located remotely from the process areas of the refinery, 

it is expected that refinery owners and operators have installed a thermal oxidizer or flare near 

the MVL or WWT units (i.e., not part of the centralized fuel gas system) to reduce the VOC 

emissions associated with these emissions points. If vapors generated by MVL and WWT units 

are considered fuel gas, then any device combusting these vapors would be required to meet the 

short-term 162 ppmv H2S concentration limit, so the vapors with H2S concentrations exceeding 

this limit would need to be treated to remove H2S. In that case, either the vapors would be 

conveyed by pipe to the existing centralized fuel gas system or the refinery owner or operator 

would need to construct an amine treatment unit near the MVL or WWT units to remove the H2S 

before combustion in the thermal oxidizer or flare. Because MVL vapors, in particular, contain 

oxygen levels that may not allow for venting the vapors over long distances (explosive 

concerns), it was assumed that the refinery owner or operator would have to construct a 

dedicated amine treatment unit near the thermal oxidizer or flare to remove the sulfur from the 

MVL vapors and WWT vapors locally. 

B. Flow and Emission Estimates for MVL Units and WWT Units 

Baseline SO2 emissions from flares and thermal oxidizers combusting MVL vapors and WWT 

vapors are the result of the oxidation of H2S and other reduced sulfur compounds in the MVL 

and WWT vapors. The first step in this piece of the analysis was to determine the amount or 

flow rate of MVL vapors and WWT vapors that would need to be treated in a remotely located 

amine treatment unit to meet the short-term 162 ppmv H2S concentration limit. The 

memorandum Documentation of Impact Estimates for Fuel Gas Combustion Device and Flare 

Regulatory Options for Amendments to the Petroleum Refinery NSPS (“FGCD and Flare Impacts 

Memo”) included a few entries for flares used to control emissions from MVL units and WWT 

systems (Sroka and Coburn, 2012). Table 1 provides the entries for MVL and WWT units from 

that analysis. 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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Table 1. Flare Data from 2002 National Emissions Inventory Used to Estimate Flow 

Ratesa

Facility 

Number Facility Name Emission Unit Description 

Annual CO 

Emissions 

per flare 

(tpy) 

Projected 

Flow Rate 

(1000 

scf/yr) 

112 Total Petrochemicals Inc. (Prev. 

Atofina Petrochemicals, Inc.) 

Marine Dock Flare 1 7.96 29,880

113 Bp - Texas City Wastewater Treatment Plant 

Flare 

47.99 180,143

121 Delek Refining Ltd (Prev. 

Lagloria Oil & Gas Co.) 

Wastewater Flare 1.12 4,204

a

 Carbon monoxide (CO) emissions from flares that were reported in the 2002 National Emissions Inventory (NEI) 

were used to estimate flare flow rates. CO emissions were reported specifically for the source characterization 

code (SCC) for 252 flares at 77 refineries (see Sroka and Coburn, 2012, Attachment A). 

Reported CO emissions were converted to flare gas flow rates using the AP-42 emission factor and average flare 

gas heating value. The CO emission factor for flares in the EPA’s Compilation of Air Pollutant Emission Factors, 

Volume 1: Stationary Point and Area Sources (AP-42) is 0.37 pounds per million British thermal units (lb/MMBtu) 

(U.S. EPA, 1995). If 1 ton/yr of CO emissions were reported, then that facility is expected to have flared 5,405 

million British thermal units per year (MMBtu/yr) of gas (1 ton/yr × 2000 lb/ton / 0.37 lb/MMBtu). 

For this analysis, the fuel gas was assumed to have a lower heating value of 1,440 Btu/scf, and this value was 

used to estimate the flare flow rate from the CO emissions data. For 1 ton/yr of CO, the 5,405 MMBtu/yr would 

equate to a flare gas flow rate of 3.75 million standard cubic feet per year (MMscf/yr). 

Flow rates for MVL units. In a previous analysis, the flow rate from MVL units was assumed to 

be 670 standard cubic feet per minute (scfm) for barge loading operations and was assumed to be 

2,000 scfm for ship loading operations (Shine, 2010). MVL units typically operate intermittently 

and only a fraction of the commodities loaded are expected to contain appreciable levels of 

sulfur compounds. For this analysis, it was assumed that MVL units operate for approximately 

4,000 hours per year (hr/yr). Therefore, these flows convert to approximately 160 to 480 million 

standard cubic feet per year (MMscf/yr), which is about a factor of 5 greater than the flow rate 

data point derived from the 2002 National Emissions Inventory (NEI) data (see Table 1). 

Assuming 4,000 hr/yr operation, the additional NEI data point for the flow rate from MVL units 

to a thermal oxidizer or flare was 120 scfm. Therefore, three model MVL units, with flows for 

the small, medium, and large units of 120, 670, and 2,000 scfm, respectively, were used in this 

analysis. 

Flow rates for WWT units. Table 1 includes two entries for flares used to control emissions 

from WWT systems, although there are no specific details on what WWT units were being 

vented. The flow rate from WWT units derived from the 2002 NEI ranged from 8 scfm to 

343 scfm (assuming 8,670 hr/yr operation). Another source (U.S. EPA, 1985) shows a flow rate 

of 300 scfm from wastewater to an air pollution control device (for an oil/water separator). 

Based on these data, three different gas flow rates from WWT units to a thermal oxidizer or flare 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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January 24, 2012 

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were modeled; the small, medium, and large WWT units had flows of 10, 100, and 340 scfm, 

respectively. 

H2S concentration estimates for MVL units. The H2S concentration in the vapor streams from 

MVL units will be highly dependent on the type of fuel being loaded. Most refined products do 

not have significant sulfur content. Some distillate and heavy fuel oils, like off-road diesel fuel, 

can contain 1 to 2 percent sulfur by weight, but the sulfur is primarily bound in heavier sulfurcontaining hydrocarbons. The vapors from loading these fuel oils are expected to exceed the 

short-term 162 ppmv H2S concentration limit. Some facilities may also ship untreated naphtha 

off-site for treatment, and the untreated naphtha may be a potential source of H2S emissions. As 

a conservative estimate, the maximum H2S concentration in the vapors from the MVL unit is 

expected to be approximately 1 percent (10,000 ppmv) H2S. Based on U.S. Energy Information 

Administration (EIA) data on unfinished oils input to refineries (presumably shipped from a 

different refinery) and non-low sulfur diesel fuel output (EIA, 2011), approximately 10 percent 

of the liquid products loaded are projected to be a potential source of H2S emissions. Therefore, 

the baseline average H2S concentration in the vapor streams from MVL units (considering all 

products loaded) was estimated to be 1,000 ppmv (i.e., 10,000 ppmv × 10% = 1,000 ppmv or 0.1 

percent H2S). 

H2S concentration estimates for WWT units. Two separate baseline average H2S concentrations 

in the vapor streams from WWT units were evaluated: a high H2S concentration stream 

indicative of vapors from sour water processing units and a low H2S concentration stream 

indicative of vapors from general (non-sour water) wastewater processing units. 

Water streams that contain H2S at concentrations greater than 10 ppm by weight (ppmw) are 

considered sour water streams (see definition of “sour water stream” in 40 CFR part 61, subpart 

FF). Sour water streams are generally transferred via hard piping to a sour water stripper to 

remove ammonia and/or sulfur compounds from the water. The off-gases from the sour water 

stripper are generally either sent directly to the sulfur recovery plant or processed in an amine 

treatment unit to concentrate the H2S for recovery in the sulfur recovery plant. In some cases, 

this off-gas may be sent to a thermal oxidizer or flare. The solubility of H2S in water is 

approximately 3,300 mg/L (3,500 ppmw) at 25°C (Dean, 1992; Lide, 1992-1993). The Henry’s 

Law constant for H2S is approximately 0.01 atm-m3/mol (Sander, 1999). If the sour water 

contains 500 ppmw H2S (well below the solubility limits), an air stream in equilibrium with this 

sour water stream (as in the sour water stripper off-gas) would have an H2S concentration of 

approximately 150,000 ppmv (15 percent H2S). An average sour water off-gas concentration of 

10 percent by volume (or 100,000 ppmv H2S) was used to assess the impacts of controlling 

vapors from sour water. 

For non-sour wastewater, it is assumed the water contains on average 5 ppmw H2S (the midpoint 

between 0 and 10 ppmw threshold for sour water). A vapor stream in equilibrium with this 

wastewater is projected to have an average concentration of approximately 1,500 ppmv. This 

vapor concentration was used to evaluate vapors from general (non-sour) wastewater units. 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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Emissions estimates. The SO2 emissions were determined by assuming the H2S in the gas stream 

is fully oxidized in the flare or thermal oxidizer. As an example, for a MVL unit with a flow rate 

of 670 scfm and a concentration of 1,000 ppmv H2S, the thermal oxidizer or flare would emit 

approximately 0.11 lb SO2/min at baseline (i.e., assuming an ideal gas at 20 °C and 1 

atmosphere, 1,000 ppmv ÷ 106 × 670 scfm × 28.317 L/ft3 ÷ 0.08205 L-atm/mol-K ÷ 293 K × 

34 lb/lb-mol ÷ 453.592 g/lb), or 13 ton SO2/yr. (Note that 64 lb SO2 is released during the 

combustion of 34 lb H2S in the fuel gas, so that 1,000 ppmv H2S for 670 scfm is equivalent to 

0.059 lb H2S/min, or 0.11 lb SO2/min.) 

The controlled SO2 emissions are based on meeting the short-term 162 ppmv H2S concentration 

limit. Continuing the MVL example above, at a flow rate of 670 scfm and a concentration of 

162 ppmv H2S, the thermal oxidizer or flare would emit approximately 0.018 lb SO2/min when 

controlled (i.e., 162 ppmv ÷ 106 × 670 scfm × 28.317 L/ft3 ÷ 0.08205 L-atm/mol-K ÷ 293 K × 34 

lb H2S/lb-mol H2S ÷ 453.592 g/lb), or 2.2 ton SO2/yr. Therefore, the SO2 emission reduction 

achieved for the sulfur limit in this example is 0.093 lb/min SO2 and 11 ton/yr SO2. 

The baseline SO2 emissions and the SO2 emissions for meeting the short-term 162 ppmv H2S 

concentration limit for a flare or thermal oxidizer installed to control emissions from MVL units 

and WWT units are shown in Table 2. 

Table 2. Emissions for Model Plants Meeting the Short-Term 162 ppmv H2S 

Concentration Limit 

Conditions 

Emissions from Model Fuel Gas System 

 (ton SO2/yr) 

1 2 3 

MVL unitsa

Baseline 2.4 13 40 

162 ppmv H2S 0.39 2.2 6.5 

Reduction from baseline 2.0 11 33 

WWT units - Non-sour water b

Baseline 0.66 6.6 22 

162 ppmv H2S 0.071 0.71 2.4 

Reduction from baseline 0.58 5.8 20 

WWT units - Sour water b

Baseline 44 440 1,500 

162 ppmv H2S 0.071 0.71 2.4 

Reduction from baseline 44 440 1,500 

a

 The flow rates for MVL units for models 1, 2, and 3 are assumed to be 120 scfm, 670 scfm, and 2,000 scfm, 

respectively. 

b

 The flow rates for WWT units for models 1, 2, and 3 are assumed to be 10 scfm, 100 scfm, and 340 scfm, 

respectively. 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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C. Costs for MVL Units and WWT Units 

Estimated costs for fuel gas systems that would add amine treatment capacity were based on 

vendor cost literature. The vendor cost information allowed estimation of capital costs based on 

the circulation rate of solution needed to control the acid gas (H2S) in the inlet stream. For 

comparison, we also reviewed costs provided by public commenters that included capital costs, 

annual operating costs, and total annual costs for eight relevant projects; further details on these 

projects are considered confidential business information (Sroka and Coburn, 2012). For a new 

flare or thermal oxidizer, the estimated capital and total annual costs to meet the FGCD limits 

were assumed to be $7.3 million and $0.97 million, respectively (in 2006$). These costs are 

expected to apply to a typical refinery fuel gas system, which is expected to have a flow rate of 

approximately 35,000 scfm. Capital costs were also available from vendor cost data, and the 

vendor cost data provided a cost curve (in 1986$) based on liquid circulation in the absorber of 

the amine treatment unit (Arkema, 2000). The vendor provided an equation for estimating the 

liquid recirculation rate, in gallons per minute (gpm), for an MDEA scrubber based on the fuel 

gas flow rate, H2S concentration, and MDEA solution concentration. Using this equation with 

the typical values suggested by the vendor, a typical refinery amine treatment system would have 

an amine recirculation rate of 100 gpm. Based on the cost curve in the vendor literature, the 

capital costs for this system would be approximately $770,000 (in 1986$). The costs provided 

by the public commenters are approximately 10 times higher than the vendor cost data, but are in 

2006$ compared to 1986$ and are expected to reflect the additional facility related costs of 

installing the amine scrubbing system. Therefore, the vendor cost data were scaled up by a 

factor of 10 to estimate amine treatment system capital costs in 2006 dollars (to be consistent 

with other cost estimates developed for NSPS subpart Ja). The capital costs for amine treatment 

systems installed for a new flare or thermal oxidizer system were estimated to range from 

$1.8 million to $4.5 million for MVL models, and for WWT units, they ranged from $1.7 million 

to $6.0 million. The capital costs for installing an amine treatment system to an existing flare or 

thermal oxidizer that becomes an affected source due to a modification or reconstruction were 

assumed to be 50 percent higher (i.e., a retrofit factor of 1.5 was used). 

Annual operating costs were estimated based on the steam usage ($7.25 per 1000 lb of steam) 

needed for the absorber liquid, and costs for administrative, property tax, and insurance were 

estimated at 4 percent of TCI. The annualized capital costs were estimated based on a capital 

recovery factor of 0.0944 (assuming an interest rate of 7 percent and an equipment life of 20 

years). Total annual costs (TAC) are the sum of the annual operating costs and the annualized 

capital costs. 

Table 3 summarizes the values for capital and annual costs. The cost effectiveness estimates are 

provided in Table 4 for MVL units and WWT units. 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

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Table 3. Summary of the Average Costs to Add Amine Capacity to Meet the Short-Term 

162 ppmv H2S Concentration Limit 

Type of Combustion Device Model 1 Model 2 Model 3 

MVL 

New 

Capital cost ($) 1,800,000 2,500,000 4,500,000 

Total annual cost ($/yr) 250,000 350,000 660,000 

Modified/ Reconstructed 

Capital cost ($) 2,700,000 3,800,000 6,800,000 

Total annual cost ($/yr) 330,000 470,000 870,000 

WW - Non-sour water 

New 

Capital cost ($) 1,700,000 1,700,000 1,700,000 

Total annual cost ($/yr) 230,000 230,000 230,000 

Modified/ Reconstructed 

Capital cost ($) 2,600,000 2,600,000 2,600,000 

Total annual cost ($/yr) 310,000 310,000 310,000 

WW – Sour water 

New 

Capital cost ($) 1,800,000 3,100,000 6,000,000 

Total annual cost ($/yr) 250,000 480,000 570,000 

Modified/ Reconstructed 

Capital cost ($) 2,700,000 4,600,000 9,000,000 

Total annual cost ($/yr) 330,000 630,000 1,300,000 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

Unit Off-gas 

January 24, 2012 

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Table 4. Cost Effectiveness for Model Plants Meeting the Short-Term 162 ppmv H2S 

Concentration Limit 

Conditions 

Cost Effectiveness for Model Operations 

 ($/ton SO2 reduced) 

Model 1 Model 2 Model 3 

MVL units 

New 120,000 32,000 20,000 

Modified/Reconstructed 160,000 42,000 26,000 

WWT - Non-sour water 

New 390,000 39,000 12,000 

Modified/Reconstructed 530,000 53,000 16,000 

WWT - Sour water 

New 5,700 1,100 690 

Modified/Reconstructed 7,600 1,400 880 

Note that the cost effectiveness values shown in Table 4 may be biased low for several reasons. 

First, the baseline emissions are estimated based on typical, but conservatively high, H2S 

concentrations in the vapors. In addition, 4,000 hr/yr operation is a conservatively high estimate 

for the MVL units at a refinery. These factors combined provide a “best-case scenario” estimate 

of the emissions reduction. Second, the estimated costs are likely underestimated for application 

to MVL and WWT units. This analysis uses the cost of the amine treatment unit applied to a 

typical fuel gas system, which would generally have a developed network or a fairly short 

distance over which to transport the recovered sour gas to the sulfur recovery plant. However, as 

the MVL and WWT units are commonly remote and separated from the primary refinery process 

units, the refinery owner or operator either would have to construct longer runs of piping to 

convey the gas to an existing sulfur recovery plant or construct a small sulfur recovery plant near 

the MVL or WWT units. Costs were not estimated for either of those scenarios as part of this 

analysis. Therefore, requiring flares and thermal oxidizers combusting MVL or WWT vapors to 

meet the short-term 162 ppmv H2S concentration limit may be somewhat less cost effective than 

shown in Table 4. 

3. References

Arkema. 2000. MDEA: Proven Technology for Gas Treating Systems. Available at: 

http://www.arkema-inc.com/literature/pdf/328.pdf 

Dean, J.A. (ed.) 1992. Lange’s Handbook of Chemistry, 14th Edition, McGraw-Hill Inc., New 

York, NY. 
Technical Memorandum – Fuel Gas Treatment of Marine Vessel Loading and Wastewater Treatment 

Unit Off-gas 

January 24, 2012 

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EIA (U.S. Energy Information Administration). 2011. Petroleum Supply Annual 2010, Volume 

1. Prepared by the Energy Information Administration, Washington, DC. July 28. 

Available at: http://www.eia.gov/petroleum/supply/annual/volume1/. 

Lide, D.R. (ed.) 1992-1993. CRC Handbook of Chemistry and Physics, 73rd edition, CRC Press 

Inc., Boca Raton, FL. 

Sander, R. 1999. Compilation of Henry’s Law Constants for Inorganic and Organic Species of 

Potential Importance in Environmental Chemistry. Version 3. Max-Plank Institute of 

Chemistry, Mainz, Germany. April 8. Available at: http://www.rolfsander.net/henry/henry.pdf. 

Shine, B. 2010. Email correspondence between B. Shine, EPA/OAQPS/SPPD, and J.R. Hewitt, 

Petrogas. Emails dated July 8 and July 15. Docket Item No. EPA-HQ-OAR-2010-0600-

0047. 

Sroka, K. and J. Coburn, RTI International. 2012. Documentation of Impact Estimates for Fuel 

Gas Combustion Device and Flare Regulatory Options for Amendments to the Petroleum 

Refinery NSPS. January 25. Docket ID No. EPA-HQ-OAR-2010-0682. 

U.S. EPA (Environmental Protection Agency). 1985. VOC Emissions from Petroleum Refinery 

Wastewater Systems – Background Information for Proposed Standards. EPA Publication 

No. EPA-450/3-85-001a. February. 

U.S. EPA (Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission 

Factors. Volume 1: Stationary Point and Area Sources. AP-42, Fifth Edition. Office of Air 

Quality Planning and Standards, Research Triangle Park, NC.