FROM: Karen Schaffner, Kristin Sroka, a nd 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 refi neries beginning construc tion, 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 Associatio n (NPRA), and the Western States Petroleum Association (WSPA) (collectivel y referred to as “Industry Petitioners”); 2) HOVENSA, LLC; and 3) the Environmental Integrity Project, Sier ra Club, and Natural Resources Defense Council (collectively referred to as “Environmental Peti tioners”). Based on information provided by the petitioners, the EPA proposed amendments to subpa rt Ja regarding the requirements for flares and process heaters on December 22, 2008.

The definition of “fuel gas” promulgated on J une 24, 2008, in both 40 CFR part 60, subparts J and Ja, excluded “vapors that are collected a nd 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 s ubpart 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 defini tion of “fuel gas” and determining the best system of emission reduction (BSER) (formerly re ferred 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 inst alled 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 (H 2 S) or 20 ppmv sulfur dioxide (SO 2 ) over a 3-hour rolling average, refinery ow ners and operators w ould have to install an amine treatment system. This memorandum documents the procedures and methodologiesTechnical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

2 used to estimate the costs (in 2006 dollars) a nd emission reduction impacts of installing and operating a remote amine treatment system. (Not e that while owners a nd operators of a FGCD have the choice of meeting either the H 2 S limit or the SO 2 limit, the H 2 S limit is the typical option elected for compliance, so this standard is referred to as th e “short-term 162 ppmv H 2 S concentration limit” for convenience throughout the remainder of this memorandum.)

2. Analysis

A. Initial Assumptions

For this analysis, it is assumed that there is on e centralized fuel gas sy stem at the refinery. Because MVL and WWT units are often located remo tely from the process areas of the refinery, it is expected that refinery owne rs and operators have installed a thermal oxidizer or flare near the MVL or WWT units ( i.e. , not part of the centralized fu el gas system) to reduce the VOC emissions associated with these emissions point s. If vapors generated by MVL and WWT units are considered fuel gas, then any device combus ting these vapors would be required to meet the short-term 162 ppmv H 2 S concentration limit, so the vapors with H 2 S concentrations exceeding this limit would need to be treated to remove H 2 S. In that case, eith er 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 un it near the MVL or WWT units to remove the H 2 S before combustion in the thermal oxidizer or flar e. Because MVL vapors, in particular, contain oxygen levels that may not allow for venti ng 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 oxi dizer 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 SO 2 emissions from flares and thermal oxidizers combusting MVL vapors and WWT vapors are the result of the oxidation of H 2 S 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 woul d need to be treated in a remotely located amine treatment unit to meet the short-term 162 ppmv H 2 S 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 fr om MVL units and WWT systems (Sroka and Coburn, 2012). Table 1 provid es the entries for MVL and WWT units from that analysis.Technical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

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

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 rate s. CO emissions were reported specifically for the source characterization code (SCC) for 252 flares at 77 refineries (s ee Sroka and Coburn, 2012, Attachment A). Reported CO emissions were converted to flare gas fl ow 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 milli on British thermal units (lb/MMBtu) (U.S. EPA, 1995). If 1 ton/yr of CO emissions were re ported, 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 emi ssions data. For 1 ton/yr of CO, the 5,405 MMBtu/yr would equate to a flare gas flow rate of 3.75 mill ion 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 fl ows convert to approximately 160 to 480 million standard cubic feet per y ear (MMscf/yr), which is about a factor of 5 greater than the flow rate data point derived from the 2002 National Emi ssions Inventory (NEI) data (see Table 1). Assuming 4,000 hr/yr operation, the additional NEI da ta point for the flow rate from MVL units to a thermal oxidizer or flare was 120 scfm. Th erefore, three model MV L units, with flows for the small, medium, and large units of 120, 670, a nd 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 specif ic details on what WWT units were being vented. The flow rate from WWT units deri ved 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 cont rol device (for an oi l/water separator). Based on these data, three different gas flow rates from WWT units to a thermal oxidizer or flareTechnical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

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

H 2 S concentration estimates for MVL units . The H 2 S 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 pr imarily bound in heavier sulfurcontaining hydrocarbons. The vapors from loading these fuel oils are expected to exceed the short-term 162 ppmv H 2 S concentration limit. Some facilities may also ship untreated naphtha off-site for treatment, and the untreated naphtha may be a potential source of H 2 S emissions. As a conservative estimate, the maximum H 2 S concentration in the vapors from the MVL unit is expected to be approximate ly 1 percent (10,000 ppmv) H 2 S. Based on U.S. Energy Information Administration (EIA) data on unfin ished 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 proj ected to be a potential source of H 2 S emissions. Therefore, the baseline average H 2 S concentration in the vapor stream s 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 H 2 S).

H 2 S concentration estimates for WWT units . Two separate baseline average H 2 S concentrations in the vapor streams from WWT uni ts were evaluated: a high H 2 S concentration stream indicative of vapors from sour wa ter processing units and a low H 2 S concentration stream indicative of vapors from general (non-s our water) wastewater processing units.

Water streams that contain H 2 S 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 gene rally transferred via hard piping to a sour water stripper to remove ammonia and/or sulfur compounds from th e 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 H 2 S for recovery in the sulfur recovery plant. In some cases, this off-gas may be sent to a thermal oxi dizer or flare. Th e solubility of H 2 S 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 H 2 S is approximately 0.01 atm-m 3 /mol (Sander, 1999). If the sour water contains 500 ppmw H 2 S (well below the solubility limits), an air stream in equilibrium with this sour water stream (as in the sour wa ter stripper off-gas) would have an H 2 S concentration of approximately 150,000 ppmv (15 percent H 2 S). An average sour wate r off-gas concentration of 10 percent by volume (or 100,000 ppmv H 2 S) was used to assess the impacts of controlling vapors from sour water.

For non-sour wastewater, it is assumed th e water contains on average 5 ppmw H 2 S (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 vapo rs from general (non-so ur) wastewater units.Technical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

5 Emissions estimates . The SO 2 emissions were determined by assuming the H 2 S 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 H 2 S, the thermal oxidizer or flare would emit approximately 0.11 lb SO 2 /min at baseline ( i.e. , assuming an ideal gas at 20 °C and 1 atmosphere, 1,000 ppmv ÷ 10 6 × 670 scfm × 28.317 L/ft 3 ÷ 0.08205 L-atm/mol-K ÷ 293 K × 34 lb/lb-mol ÷ 453.592 g/lb), or 13 ton SO 2 /yr. (Note that 64 lb SO 2 is released during the combustion of 34 lb H 2 S in the fuel gas, so that 1,000 ppmv H 2 S for 670 scfm is equivalent to 0.059 lb H 2 S/min, or 0.11 lb SO 2 /min.)

The controlled SO 2 emissions are based on meeting the short-term 162 ppmv H 2 S concentration limit. Continuing the MVL example above, at a fl ow rate of 670 scfm and a concentration of 162 ppmv H 2 S, the thermal oxidizer or flare would emit approximately 0.018 lb SO 2 /min when controlled ( i.e. , 162 ppmv ÷ 10 6 × 670 scfm × 28.317 L/ft 3 ÷ 0.08205 L-atm/mol-K ÷ 293 K × 34 lb H 2 S/lb-mol H 2 S ÷ 453.592 g/lb), or 2.2 ton SO 2 /yr. Therefore, the SO 2 emission reduction achieved for the sulfur limit in this example is 0.093 lb/min SO 2 and 11 ton/yr SO 2
.
The baseline SO 2 emissions and the SO 2 emissions for meeting the short-term 162 ppmv H 2 S concentration limit for a flare or thermal oxidizer installed to control em issions from MVL units and WWT units are shown in Table 2.

Table 2. Emissions for Model Plants Meeting the Short-Term 162 ppmv H 2 S Concentration Limit

Conditions Emissions from Model Fuel Gas System (ton SO 2 /yr)
1 2 3

MVL units a

Baseline 2.4 13 40 162 ppmv H 2 S 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 H 2 S 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 H 2 S 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 scf m, 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 Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

6 C. Costs for MVL Units and WWT Units

Estimated costs for fuel gas systems that w ould add amine treatment capacity were based on vendor cost literature. The vendor cost informa tion allowed estimation of capital costs based on the circulation rate of solution n eeded to control the acid gas (H 2 S) in the inlet stream. For comparison, we also reviewed costs provided by p ublic commenters that included capital costs, annual operating costs, and total an nual costs for eight relevant pr ojects; further details on these projects are considered confid ential business information (Sroka and Coburn, 2012). For a new flare or thermal oxidizer, the estimated capital an d total annual costs to meet the FGCD limits were assumed to be $7.3 million and $0.97 milli on, respectively (in 2006$). These costs are expected to apply to a typical refi nery fuel gas system, which is expected to have a flow rate of approximately 35,000 scfm. Capital costs were al so available from vendor cost data, and the vendor cost data provided a cost curve (in 1986$) based on liquid ci rculation in the absorber of the amine treatment unit (Arkema, 2000). The vendor provided an equation for estimating the liquid recirculation rate, in ga llons per minute (gpm), for an MDEA scrubber based on the fuel gas flow rate, H 2 S concentration, and MDEA solution con centration. 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 th e vendor literature, the capital costs for this system would be a pproximately $770,000 (in 1986$). 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 refl ect the additional facili ty 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 subpa rt Ja). The capital costs for amine treatment systems installed for a new flare or thermal oxi dizer 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 am ine treatment system to an existing flare or thermal oxidizer that becomes an affected sour ce 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 ad ministrative, property tax, and insurance were estimated at 4 percent of TCI. The annualized capital costs we re estimated based on a capital recovery factor of 0.0944 (assuming an interest ra te of 7 percent and an equipment life of 20 years). Total annual costs (TAC ) are the sum of the annual oper ating costs and the annualized capital costs.

Table 3 summarizes the values for capital and annua l costs. The cost effectiveness estimates are provided in Table 4 for MVL units and WWT units.Technical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

7 Table 3. Summary of the Average Costs to Add Amine Capacity to Meet the Short-Term 162 ppmv H 2 S 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 1,300,000Technical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

8 Table 4. Cost Effectiveness for Model Plants Meeting the Short-Term 162 ppmv H 2 S Concentration Limit

Conditions Cost Effectiveness for Model Operations ($/ton SO 2 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 lo w for several reasons. First, the baseline emissions are estimated based on typical, but conservatively high, H 2 S 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 trans port the recovered sour gas to the sulf ur recovery plant. However, as the MVL and WWT units are commonly remote and separated from the primary refinery process units, the refinery owner or opera tor either would have to constr uct longer runs of piping to convey the gas to an existing sulfur recovery plant or construct a sm all sulfur recovery plant near the MVL or WWT units. Costs were not estimated fo r either of those scenarios as part of this analysis. Therefore, requiri ng flares and thermal oxidizers combusting MVL or WWT vapors to meet the short-term 162 ppmv H 2 S 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.c om/literature/pdf/328.pdf

Dean, J.A. (ed.) 1992. Lange’s Handbook of Chemistry , 14th Edition, McGr aw-Hill Inc., New York, NY.Technical Memorandum – Fuel Gas Treatment of Ma rine Vessel Loading and Wastewater Treatment Unit Off-gas January 24, 2012

9 EIA (U.S. Energy Informati on 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 Constant s 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 Ju ly 15. Docket Item No. EPA-HQ-OAR-2010-0600- 0047.

Sroka, K. and J. Coburn, RT I 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.