Date: August 19, 2005 

Subject: Summary of Data Gathering Efforts: Emission Control and Emission Reduction 

Activities. 

 

Project: Data Gathering for Review of New Source Performance Standards 

EPA Contract 68-D-01-073, Work Assignment III-15 

 RTI Project 08220.003.015 

From: Jeff Coburn 

 David Randall 

 Kristin Parrish 

To: Bob Lucas 

 EPA/ESD 

 U. S. Environmental Protection Agency 

 Research Triangle Park, N.C. 27711 

I. Introduction 

Section 111(b)(1)(B) of the Clean Air Act mandates that the Environmental Protection Agency 

(EPA) review and, if appropriate, revise existing new source performance standards (NSPS) at 

least every 8 years. The focus of this work assignment is to gather the necessary data to review 

the NSPS for petroleum refineries (40 CFR part 60 subpart J), the NSPS for equipment leaks in 

the synthetic organic chemicals manufacturing industry (40 CFR part 60 subpart VV) and the 

NSPS for equipment leaks in petroleum refineries (40 CFR part 60 subpart GGG). Since the 

kickoff meeting held on July 20, 2005, RTI has pursued various data gathering activities to assist 

in reviewing the standards for these sources. The purpose of this memorandum is to provide an 

update on those activities and summarize of the information collected. 

II. Petroleum Refinery Control Devices 

A literature review was conducted to identify candidate control strategies for reducing emissions 

from units affected by the refinery NSPS (subpart J). A primary resource for potential control 

strategies is the Midwest Regional Planning Organization (RPO) Petroleum Refinery Best 

Available Retrofit Technology (BART) Engineering Analysis (MACTEC, 2005). Using this 

BART analysis and other information collected, the following control techniques for refinery 

NSPS units were identified. 
2

NOx Emission Control Options 

 Flue Gas Recirculation. Flue gas recirculation (FGR) uses flue gas as an inert material to 

reduce flame temperatures. In a typical flue gas recirculation system, flue gas is collected from 

the heater or stack and returned to the burner via a duct and blower. The addition of flue gas with 

the combustion air reduces the oxygen content of the inlet air stream to the burner. The lower 

oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NOx 

emissions. The normal NOx control efficiency range for FGR is 30 percent to 50 percent. When 

coupled with low-NOx burners (LNB) the control efficiency increases to 50-72 percent. 

 Low-NOx Burners. Low-NOx burner (LNB) technology utilizes advanced burner design to 

reduce NOx formation through the restriction of oxygen, flame temperature, and/or residence 

time. The two general types of low NOx burners are staged fuel and staged air burners. Staged 

fuel LNBs are particularly well suited for boilers and process heaters burning process and natural 

gas which generate higher thermal NOx. The estimated NOx control efficiency for LNBs where 

applied to petroleum refining fuel burning equipment is generally around 40 percent.

 Ultra-low NOx Burners. Ultra-low NOx burners may incorporate a variety of techniques 

including induced flue gas recirculation (IFGR), steam injection, or a combination of techniques. 

These burners combine the benefits of flue gas recirculation and low-NOx burner control 

technologies. Rather than a system of fans and blowers (like FGR), the burner is designed to 

recirculate hot, oxygen depleted flue gas from the flame or firebox back into the combustion 

zone. This leads to a reduction in the average oxygen concentration in the flame without 

reducing the flame temperature below temperatures necessary for optimal combustion efficiency. 

The estimated NOx control efficiency for ULNBs in high temperature applications is 50 percent. 

Newer designs have yielded efficiencies of between 75-85 percent. When coupled with selective 

catalytic reduction, efficiencies in the range of 85-97 percent can be obtained. 

 Selective Catalytic Reduction. Selective catalytic reduction (SCR) is a post-combustion NOx

control technology in which ammonia (NH3) is injected into the post-combustion gas stream in 

the presence of a catalyst. A catalyst bed containing metals in the platinum family is used to 

lower the activation energy required for NOx decomposition. The reaction of NH3 and NOx is 

favored by the presence of excess oxygen. The NH3 oxidation to NOx increases with increasing 

temperature. The normal NOx control efficiency range for SCR is 70 to 90 percent. ExxonMobil 

Torrance Refinery website reports the installation of an SCR unit for their FCCU, which they 

claim is the first such application of its kind in the United States. 

 Selective Non-Catalytic Reduction. In the selective non-catalytic reduction (SNCR) process, 

urea or ammonia-based chemicals are injected into the flue gas stream to convert NO to N2 and 

water. Without the participation of a catalyst, the reaction requires a high temperature range to 

obtain activation energy. The optimum operating temperature for SNCR is 1,600 °F to 2,100 °F. 

At temperatures above 2,000 °F, NOx control efficiency decreases rapidly. The normal NOx

control efficiency range for SNCR is 50 percent to 70 percent. SNCR systems are usually lower 

in capital cost than SCR systems for the same application. One advantage of this technology is 

the fact that no liquid or solid waste is generated with this technology. SNCR technology has 

been applied to CO boilers, process heaters and boilers in the petroleum refining sector where 

control efficiencies are consistent with the range mentioned above. 

 Combination System. Combination systems have used combustion controls followed by SCR or 

SNCR technology in order to reduce costs of NOx removal from a flue gas. For example, LNB 

has been combined with SNCR technology to minimize the capital and operating cost for NOx

removal as well as improve the control efficiency. 

 Catalyst Additives. An additional NOx emission control option specific for the FCCU is the use 

of catalyst additive, such as X-NOX and DENOX (from Grace-Davison; Bruhin, et al. 2003). 
3

SO2 Emission Control Options 

 Advanced Flue Gas Desulfurization (AFGD). The AFGD process accomplishes SO2 removal 

in a single absorber which performs three functions: prequenching the flue gas, absorption of 

SO2, and oxidation of the resulting calcium sulfite to wallboard-grade gypsum. 

 Wet Scrubbing / Flue-Gas Desulfurization. Wet scrubbing techniques are used to control both 

particulate and SO2 emissions. Wet scrubbing processes used to control SO2 are generally termed 

flue-gas desulfurization (FGD) processes. FGD utilizes gas absorption technology, the selective 

transfer of materials from a gas to a contacting liquid, to remove SO2 in the waste gas. Caustic, 

crushed limestone, or lime are used as scrubbing agents. The normal SO2 control efficiency range 

for SO2 scrubbers is 80 percent to 90 percent for low efficiency scrubbers and 90 percent to 99 

percent for high efficiency scrubbers.

 Dry Flue Gas Desulfurization (Spray Dryer Absorption). Spray dryer absorption (SDA) 

systems spray lime slurry into an absorption tower where SO2 is absorbed by the slurry, forming 

CaSO3/CaSO4. The liquid-to-gas ratio is such that the water evaporates before the droplets reach 

the bottom of the tower. The dry solids are carried out with the gas and collected with a fabric 

filter or ESP. When used to specifically control SO2, the term dry flue-gas desulfurization (dry 

FGD) may also be used. Marathon-Ashland’s Catlettsburg refinery was the only such application 

for FCCUs; however, it appears that changes in the refinery operations and use of FCCU feed 

hydrotreating has eliminated the need for this control system (KY DAQ, 2004). 

 FCCU Feed Hydrotreating. Although the refinery industry does not consider hydrotreating to 

be a viable “control technique,” it appears evident that cat-feed hydrotreating can significantly 

reduce SOx emissions from the FCCU (KY DAQ, 2004). 

 Catalyst Additives. One common method used by refineries is the use of catalyst additives, such 

as DESOX (from Grace-Davison), to reduce SOx emissions from the FCCU. According to 

Bruhin et al. (2003), DESOX has been used on over 70 FCCU applications worldwide. 

 Tail Gas Treatment Units (TGTU) and the Mobil Oil SOx Treatment (MOST) Process. 

TGTU, such as SCOT and Beavon units are commonly used to capture and recycle sulfur 

compounds from sulfur recovery unit (TRU) tail gas (i.e., a Claus unit outlet gas) back to the inlet 

of the Claus unit, thereby significantly increasing the overall removal efficiency of the SRU. The 

MOST process (Stern, et al., 2000) uses combustion of tail gases (to convert the sulfur 

compounds SOx), then a high-capacity solid sorbent material to remove SOx from the tail gas. 

The sulfur-laden sorbent is then reductively desorbed and the concentrated SOx/H2S gas is 

returned to the head of the Claus unit. Unlike the SCOT and Beavon units, the promoters of the 

MOST process suggest that the process should also be applicable to control FCCU emissions, 

where the process should also help to reduce carbon monoxide and NOx emissions (Stern, et al., 

2000).

 Redundant Amine Scrubbers/SRU Trains. No real control method has been identified to 

reduce SOx emissions from flares beyond removing sulfur compounds (primarily H2S) from the 

fuel gas system or reducing the sulfur load to the fuel gas system. However, process upset gases 

are exempt under the current NSPS (subpart J). Significant SOx emissions occur when there is a 

malfunction or upset in the sulfur plant, and the untreated refinery tail gases are then flared. One 

potential method to reduce the release of process upset gases that contain significant sulfur 

content is to have redundant amine scrubbing and SRU capacity to minimize the likelihood and/or 

duration of high sulfur containing process gases to the fuel gas system during upset conditions. 

PM Emission Control Options 

 Fabric Filter. A fabric filter, or baghouse, is a potential control method for particulate emissions 

from the FCCU, although the only application of a baghouse on an FCCU was in conjunction 

with the SDA at the Marathon-Ashland Catlettsburg refinery. The normal PM control efficiency 

range for a fabric filter is 98 percent to 99+ percent.
4

 Dry Electrostatic Precipitator. An electrostatic precipitator (ESP) is the most commonly 

applied control method for particulates from the FCCU catalyst regenerator. The normal PM 

control efficiency range for an ESP is between 90 and 99+ percent. One of the major advantages 

of an ESP is that it operates with essentially little pressure drop in the gas stream. They are also 

capable of handling high temperature conditions. 

 Wet Electrostatic Precipitator. A wet electrostatic precipitator (WESP) is a potential control 

method for PM. A WESP operates on the same collection principles as a dry ESP, and uses a 

water spray to remove particulate matter from the collection plates. The normal PM control 

efficiency range for a WESP is 98 to 99+ percent. The wash used in WESPs can also have some 

control effect on other pollutant gases via absorption and can help condense other emissions due 

to the cooling of the stream by the wash.

 Wet/Venturi Scrubber. Wet scrubbers, and particularly venturi scrubbers, are an additional 

control method for PM. Nearly all wet scrubbers used to control FCCU PM emissions have been 

installed at units subject to the NSPS (subpart J). Wet scrubbers have similar collection 

efficiencies as dry ESPs (90 to 99+ percent), but they are also effective in removing SOx

emissions. Wet scrubbers may also be more effective in controlling condensable PM. Wet 

scrubbers are generally more costly to operate due to high pressure drops across the control 

device, but they become economically viable if significant SOx emissions are also needed. 

CO/VOC Emission Control Options 

 Thermal Combustion Units. The primary means of reducing CO/VOC emissions from the 

FCCU is to use either complete combustion regenerators or subsequent thermal combustion units 

(commonly referred to as CO or waste heat boilers). The efficiency of CO/VOC emission control 

increases with increased excess oxygen and higher combustion temperatures, conditions that 

increase NOx formation. Therefore, the reduction in CO/VOC may need to be weighed against 

reductions in NOx emissions. 

In addition to the literature review, RTI has received copies of about 20 consent decrees for 

petroleum refineries from EC/R, and more consent decrees are expected in the coming weeks. 

The consent decrees detail requirements for a number of refineries within each company. RTI 

first matched the refineries included in each consent decree to the most current internal list of 

refineries. When reviewing the consent decrees, RTI noted the units at each refinery that are 

subject to requirements, such as installation of a new control device or additional monitoring. 

Table 1 (at the end of this memorandum) shows the facilities for which RTI has consent decrees 

to date and the units affected. Certain consent decrees were later reviewed to obtain information 

on the specific control devices and other requirements for each type of unit. 

III. Equipment Leaks 

Most of the consent decrees for petroleum refining companies specify program enhancements for 

equipment leaks. Requirements in consent decrees for 36 refineries owned by Equilon, 

Marathon-Ashland, Valero, Lion, Sunoco, and Motiva are very similar to each other. All involve 

minor enhancements to the standard work practice requirements in Federal equipment leak 

standards. We have not determined which of the 36 refineries have any refining process units 

subject to 40 CFR part 60, subpart GGG, but all (assuming all are major sources of HAP 

emissions) would be subject to 40 CFR part 63, subpart CC. Either way, the equipment leak 

requirements for these facilities are based on the requirements in 40 CFR part 60, subpart VV 

(except new refinery process units constructed since 1994 are subject to modified HON 
5

requirements, and facilities may have elected to comply with the modified HON requirements for 

other process units). The program enhancements for these 36 refineries are summarized below. 

The consent decrees for four refineries owned by Eagle, Global, Total, and Colorado have no 

equipment leak program enhancements. Consent decrees for Citgo, Coastal, Chevron, Navajo, 

ConocoPhillips, Deer Park Refining, and Murphy have not yet been reviewed. 

The reviewed consent decrees that specify program enhancements for equipment leaks all 

address the following topics: training, LDAR audits, leak definitions for valves, repairs, 

monitoring frequency, dataloggers, data QA/QC, calibrations, delay of repair, recordkeeping, and 

reporting. Most of the requirements related to these topics reiterate requirements in the federal 

standards, or they are administrative procedures designed to ensure that the standards are met 

(e.g., training and audits) or provide a better way of tracking and demonstrating that they have 

been met (e.g., more frequent and detailed records and reports). Other program enhancements 

change the actual work practice requirements and may result in better emission control than 

expected by the federal standards. All requirements apply only to components in light liquid and 

gaseous service. 

a. Leak definitions. The consent decrees specify leak definitions of 2,000 ppm for 

pumps and 500 ppm for valves (subpart VV specifies 10,000 ppm), except where permit 

requirements are already lower. Some consent decrees apply these leak definitions to all 

components all at once, others phase in the requirements over a few years. Note that these are 

only “internal” leak definitions for the purpose of the consent decrees; refineries may elect to 

continue reporting leak rates against the otherwise applicable leak definitions, or they may use 

the new lower definitions. However, the consent decrees require repair of components leaking 

above the new internal leak definitions. 

b. First attempt to repair. An attempt must be made to repair valves with leaks at levels 

below the new internal leak definitions. Some consent decrees specify 100 ppm and others 

specify 200 ppm. After repair attempts, the valves must be remonitored “immediately” in some 

consent decrees or within 5 days in others. If the refinery can demonstrate with monitoring data 

that first attempts to repair “at 100 ppm” worsens leaks (presumably they mean leaks between 

100 ppm and 500 ppm), then after 2 years they may request that EPA reconsider this 

requirement. 

c. Monitoring frequency. Some consent decrees require valves to be monitored quarterly 

(consistent with subpart VV for valves that don’t leak, but subpart VV requires monthly 

monitoring for two months after a leak is detected). Others specify either quarterly or in 

accordance with the “Sustainable Skip Period program.” (The requirements of the skip program 

have not been reviewed.) 

d. Delay of repair. If a unit supervisor determines that repairing a leaking valve is 

technically infeasible without a unit shutdown, then the valve is eligible to be placed on the delay 

of repair list. However, all of the consent decrees specify that any valves placed on the delay of 

repair list must continue to be monitored on the regular schedule. Furthermore, “extraordinary” 

efforts to repair (e.g., “drill and tap”) are required when the valve is leaking at a level of at least 

10,000 ppm (unless the refinery demonstrates that this poses a safety or major environmental 
6

concern). Some consent decrees require the extraordinary efforts for such valves that have been 

on the delay of repair list for 3 years. These consent decrees also typically require extraordinary 

efforts at repair whenever a valve is found to be leaking at greater than 50,000 ppm. Other 

consent decrees specify that two attempts at repair are required before a valve leaking at greater 

than 10,000 ppm may be placed on the delay of repair list; these consent decrees do not specify 

requirements for leaks at 50,000 ppm. 

In a related effort, RTI briefly investigated the use of infrared cameras to detect equipment leaks. 

EPA is currently working on an alternative work practice that would allow other methods of leak 

detection equivalent to Method 21. In order to understand how the technology works, RTI 

reviewed several vendor websites, news reports, and contractor documents. Specific information 

sought included the identity of the manufacturers and users of the technology, whether any States 

were developing regulations that would allow the new technology, how the performance of the 

infrared cameras compares to Method 21. The information gathered as part of this effort is 

included as Attachment 1. 

IV. Additional Data Collection Activities 

RTI has also begun looking for regulations affecting refineries and equipment leaks on the 

websites of several States’ environmental regulatory agencies. Of particular interest are any 

regulatory requirements that are more stringent than the NSPS requirements. So far, regulations 

for refineries and equipments leaks were discovered for the states of Texas, California, and 

Louisiana. These regulations have not been reviewed sufficiently to summarize at this time, but 

it appears that some requirements may be more stringent than the NSPS. 

V. References 

Bruhin, T., G. McElhiney, G. Bourdillon, and P.A. Diddams. 2003. “Catalytic Solutions for 

FCC Unit Emissions.” In the proceedings of the World Petroleum Conference 2003. 

pp. 144-147. Available at: 

http://www.world-petroleum.org/isc2004/File%20022/144_145_146_147.pdf 

Commonwealth of Kentucky, Division of Air Quality. 2004. “Permit Statement of Basis.” 

Synthetic Minor Permit No. VF-02-001 (Revision 2) for Catlettsburg Refining, LLC. 

April 13. 

MACTEC. 2005. Midwest Regional Planning Organization (RPO) Petroleum Refinery Best 

Available Retrofit Technology (BART) Engineering Analysis. Prepared for The Lake 

Michigan Air Directors Consortium (LADCO). March 30. 

Stern, D.L., K.E. Nariman, J.S. Buchanan, N.A. Bhore, D.L. Johnson, and R.K. Grasselli. 2000. 

“The Mobil Oil SOx Treatment Process (MOST). Catalytic removal of SOx and H2S from 

refinery tailgas.” Catalyst Today, Vol. 55, pp. 311-316. 
7

Table 1. Information from Consent Decrees Reviewed by RTI 

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

12 Lion Oil Co. El Dorado AR X X X X 

heaemwa

15 Chevron USA Products Co. El Segundo CA X X X X 

heaem

16 Chevron USA Products Co. Richmond CA X X X X 

heaem

29.1 

ConnocoPhillips (formerly Tosco, formerly Unocal Corp.) LA - Carson CA X X X 

heaem

29.2 

ConnocoPhillips (formerly Tosco, formerly Unocal Corp.) 

LA - Wilmington CA X X X X 

heaem

30.1 

ConnocoPhillips (formerly Tosco, formerly Unocal Corp.) SF - Rodeo CA X X X hea

30.2 

ConnocoPhillips (formerly Tosco, formerly Unocal Corp.) 

SF - Santa Maria CA X X X hea

17 

Shell (formerly Equilon, formerly Texaco Refining & Marketing Inc.) Bakersfield CA X X X 

heaem

18 

Shell (formerly Equilon, formerly Shell Oil Co.) Martinez CA X X X X 

heaem

19 

Shell (formerly Equilon, formerly Texaco Refining & Marketing Inc.) Wilmington CA X X X X 

heaem

31 

Tesoro (formerly Ultramar Diamond Shamrock, formerly Tosco Corp. - Avon) 

Golden Eagle CA X X X X 

heaem

32 

Valero (formerly Ultramar Diamond Shamrock) Wilmington CA X X X X 

heaem
8

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

33 Valero ( formerly Exxon Co. USA) Benicia CA X X X X 

heaem

36 

Valero Energy (formerly Ultramar Diamond Shamrock, formerly Total Petroleum) Denver CO X X X X 

heawadocstoem

37 

Premcor (formerly Motiva Enterprises, formerly Star) 

Delaware City DE X X X X 

heaem

37.5 Citgo Petroleum Savannah GA X 

heaem

39 Chevron USA Inc. 

Barber's Point HI X X X 

heaem

41 Citgo Petrol. (formerly UNO-VEN) Lemont IL X X X X 

heaem

43 Marathon Ashland Petrol. Robinson IL X X X X 

heaem

45 

Premcor Refining Group (formerly Clark Oil and Refining Corp.) Hartford IL X hea

46 

ConnocoPhillips (formerly Tosco Refining, Equilon, Wood River, & Shell Oil) Wood River IL X X X X 

heaem

51 National Cooperative Refinery Association McPherson KS X X X X 

boigro

53 Marathon Ashland Petroleum LLC Catlettsburg KY X X X X 

waconareuni
9

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

61 Citgo Petroleum Corp. 

Lake Charles LA X X X X 

heaem

65 Marathon Ashland Petroleum LLC Garyville LA X X X X 

heaem

66 Motiva Enterprises (formerly Star) Convent LA X X X X 

heaem

67 Motiva Enterprises (formerly Shell Oil Co.) Norco LA X X X X 

heaem

69 

Valero (formerly Orion Refining Corp, formerly TransAmerican Refining Corp) Norco LA X X X X 

heaem

73 

ConocoPhillips (formerly, Tosco Refining Co., formerly BP Oil Co.) 

Belle Chasse LA X X X X 

heaem

74 Valero (formerly Basis Petroleum, Inc.) 

Krotz Springs LA X X X 

heaem

75 Marathon Ashland Petrol. LLC Detroit MI X X X 

heaem

77 Marathon Ashland Petrol. LLC 

St. Paul Park MN X X X 

con(Wboiben

78 Chevron USA Inc. Pascagoula MS X X X X 

heaem

79 Ergon Refining Inc. Vicksburg MS X 

heaemsyssepfac
10

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

85 Montana Refining Co. Great Falls MT X X X uni

87.6 Citgo Asphalt Refining Co. Paulsboro NJ X X 

heaem

88 

Sunoco (formerly Coastal Eagle Point Oil Co.) Westville NJ X X X X 

refiheaem

89 

ConocoPhillips (formerly Tosco Refining Co., formerly Bayway) Linden NJ X X X X 

heaem

90 Valero Energy Corp. (formerly Mobil Oil) Paulsboro NJ X X X X 

heawauni

93 Navajo Refining Co. Artesia NM X X X X 

heatha

96 Marathon Ashland Petrol. LLC Canton OH X X X X 

indstosepboiben

98 Sunoco, Inc. Toledo OH X X X X 

heaem

102 Sunoco, Inc. Tulsa OK X X 

heaem

103 

Valero (formerly Ultramar/Diamond Shamrock, formerly Total Petroleum Inc.) Ardmore OK X X X X 

heaalksysben

105 Sunoco, Inc. 

Marcus Hook PA X X X X 

heaem
11

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

106 Sunoco (combined Sun & Chevron) 

Phil. (Girard Pt & Pt Breeze) PA X X X X 

heaem

107 

ConocoPhillips (formerlyTosco Refining Co., formerly BP) 

Trainer (Marcus Hook) PA X X X X 

heaem

115 Citgo 

Corpus Christi TX X X X X 

heaem

123 Marathon Ashland Petrol. LCC Texas City TX X X X X 

heaem

124 Motiva Enterprises (formerly Star) Port Arthur TX X X X X 

heaem

125 

ConocoPhillips (formerly Phillips Petroleum Co.) Borger TX X X X X 

heaem

126 

ConocoPhillips (formerly Phillips Petroleum Co.) Sweeny TX X X X X 

heaem

128 

Shell -Deer Park Refining Limited Partnership Deer Park TX X X X 

heaem

130 

Valero (formerly Ultramar/Diamond Shamrock Corp.) 

Three Rivers TX X X X X 

heaem

131 

Valero (formerly Ultramar/Diamond Shamrock Corp.) Sunray TX X X X X 

heaaciben

132 Valero Refining Co. 

Corpus Christi TX X X X X 

heahyduni
12

Facility 

No. FacName City State 

Units Subject to Consen

Flares FCCU SRU 

Eq. 

Leaks Oth

133 Valero (formerly Basis Petroleum, Inc.) Houston TX X X X X 

heaem

134 Valero (formerly Basis Petroleum, Inc.) Texas City TX X X X X 

heaem

136 Chevron USA 

Salt Lake City UT X X X X uni

142 

Shell Oil (formerly Equilon Enterprises, formerly Texaco Refining & Marketing Inc.) Anacortes WA X X X X 

heaem

145 

ConocoPhillips (formerly Tosco Refining Co.) Ferndale WA X X X X 

heaem

147 

Ergon-West Virginia inc. (formerly Quaker State Oil Refining Corp.) Newell WV X X 

heaem

148 Murphy Oil USA Inc. Superior WI X X X proN/A Global Companies LLC Waltham MA 

CoProble

N/A Navajo Refining Lovington NM X X 

heatha
13

Attachment 1 

Information Gathered on IR Cameras used for Leak Detection – August 18, 2005 

Categories of interest: 

1. Manufacturer(s) of imaging equipment 

2. Any info on who, if anyone, is using the technology 

3. Any info on performance relative to Method 21 

4. Any regulatory agencies incorporating use of this equipment in their regulations 

5. Any other issues/questions 

Press release: “FLIR Systems Introduces New Infrared Camera for Detection of Volatile 

Organic Compounds.” June 8, 2005. 

1. Manufacturer: FLIR Systems, Inc., “global leader in infrared cameras” – GasFindIR infrared 

camera 

4. Regulatory agencies: Article quotes David Markwordt as saying that USEPA is in the 

process of writing regulations to take advantage of the technology. 

Pacific Advanced Technology website: product brochure and information about Sherlock 

1. Manufacturer: Pacific Advanced Technology with support from US DOE, state of 

California, and the Gas Technology Institute (under contract to the DOD). Camera uses 

Image Multi-Spectral Sensing (IMSS) 

2. Who is using the system: British Petroleum and Shell Oil helped to test the system for 

environmental monitoring and fugitive gas leak detection applications 

3. Performance relative to Method 21: Testing shows that IMSS can measure target spectral 

signatures consisting of multiple species simultaneously and can handle the effects of 

atmospheric absorption and scattering. It is ideal for monitoring emissions of toxic metals 

and organic compounds from high-temperature complex matrix sources. (No mention of 

performance at lower temperatures) Only ambient light is needed. In Phase I tests, IMSS 

successfully imaged leaks as small as 0.01 ft3

/min. 

5. Any other issues/ questions: The product brochure contains fairly detailed specs for the 

product. 

Erin Young, Petro-Canada. Optical Emissions Detection Technology – Technical Abstract. 

Prepared for Petroleum Technology Alliance Canada. September 2004. 

1. Manufacturer: (a) Raytheon (Palm IR 250) and (b) Leak Systems, Inc. (US)/Maverick 

Inspection LTD (Canada) (HAWK) 

3. Performance relative to Method 21: (a) Operating temperature range is -20° to 49°C (-4° to 

120°F). Cost is about $20,000. (b) Maverick LSI HAWK technology is proprietary and 
14

requires operation by a consultant for accurate assessment. Camera is worth about $150,000, 

and the consultant fee is about $4,000/day. 

5. Any other issues/ questions: Abstract says that most cameras use passive infrared instead of 

active infrared because it uses ambient radiation, consumes less power, and is much easier to 

use in a number of ways. 

Thermal-eye website (http://www.thermal-eye.com) and info from the U.S. Navy Pollution 

Prevention Equipment Program website 

1. Manufacturer: L-3 Communications Infrared Products (formerly Raytheon; acquired Nov. 

2004) – Thermal-Eye is the name of the line of cameras 

2. Who is using the system: U.S. Navy Pollution Prevention Equipment Program tested the 

PalmIR Pro on its ability to locate harbor oil spills. According to PPEP, it reduces chemical 

testing required to locate spills, reduces the amount of petroleum products in harbors by 

quickly identifying the source of discharge and determining accountability, and provide night 

detection of oil spills. Cost is around $20,000. 

5. Any other issues/questions: L-3 has a number of different IR cameras for commercial use, 

but they do not advertise leak detection as one of the applications. Specified applications 

include home security, public safety, search and rescue, fire fighting, law enforcement, 

monitoring of endangered species in the wild, and others.

FLIR Systems product brochure for GasFindIR 

1. Manufacturer: FLIR Systems, Inc. 

3. Performance relative to Method 21: (a) Operating temperature range is -15° to 50°C (5° to 

122°F). 

5. Any other issues/ questions: Detailed specs for product included at the end 

WAFB.com, Baton Rouge, articles from June 22, July 13, and July 15, and Louisiana DEQ 

website 

1. Manufacturer: Leak Survey Inc. (Hawk), also considered Pacific Advanced Technology 

(Sherlock) 

2. Who is using the system: Louisiana DEQ conducted surveys over Baton Rouge using the 

Hawk and a helicopter in June 2005. The study was funded by EPA Region 6. (An LSI 

employee accompanied DEQ staff during the surveys.) 

3. Performance relative to Method 21: Examined 2,000-3,000 railcars, more than 500 storage 

tanks, and less than 100 barges. System found “a dozen leaks in just 90 minutes.” (After 

second survey, total leaks were at least 24 – 12 barges and 12 leaking tanks.) 

4. Regulatory agencies: It is unclear whether LA DEQ plans to allow facilities to use infrared 

cameras as an alternative method for detecting leaks. 
15

5. Any other issues/ questions: Cost to purchase is about $100,000. June 22 article says that 

DEQ plans to purchase a Hawk “within the next few weeks,” which seems to contradicts the 

report from Petro-Canada indicating that the Hawk is used more on a “rental” basis. 

TCEQ Regulatory Watch – July 2005 

2. Who is using the system: The contractor for this project is Lamar University, who is using 

Leak Surveys, Inc. (LSI), as its subcontractor. LSI is performing most of the observations. 

4. Regulatory agencies: Texas Commission on Environmental Quality is conducting helicopter 

flights around industrial areas and using LSI HAWK cameras to note VOC plumes as part of 

its Texas Air Quality Field Study (TexAQS II). Letters will be sent to those companies 

observed to have VOC plumes requesting information on the source, identity, and rate of 

those emissions. The State of Texas is planning to use the information gathered as part of 

TexAQS II in the development of its SIP. 

Development of Emissions Factors and/or Correlation Equations for Gas Leak Detection, and the 

Development of an EPA Protocol for the Use of a Gas-imaging Device as an Alternative or 

Supplement to Current Leak Detection and Evaluation Methods. Environ International 

Corporation, October 29, 2004. 

1. Manufacturer: Studied cameras made by Pacific Advanced Technology (IMSS passive IR – 

Sherlock), Laser Imaging Systems (long-wave BAGI active IR – GasVue® – only one of the 

four that is fully developed and commercially available), Sandia National Laboratory (midwave BAGI active IR), and Leak Survey Inc. (passive IR – Hawk – currently available for 

leak surveys service work.) 

2. Who is using the system: BP’s laboratory in Naperville, IL, was used for the tests. Electric 

power facilities use the LIS GasVue® to detect SF6. 

3. Performance relative to Method 21: (two phases; lab testing and field study): 

 - EPA developed Monte Carlo simulation software, and a Monte Carlo analysis was run for 

mass flow rate equivalent to 500, 1,000, and 10,000 ppmv leak definitions. The analysis 

determined that a leak definition of 60 grams per hour (g/hr) would result in equivalent 

environmental protection to Method 21. Therefore, EPA has accepted a 60 g/hr threshold 

for gas imaging. 

 - Cameras tested in a laboratory in August 2003 and March 2004. Goals were (1) to 

demonstrate the effectiveness of the cameras in detecting 14 candidate chemical groups 

(all organics – ethylene, 1,3-butadiene, 1-butene, and propylene had highest priority in 

the laboratory tests), (2) to determine the detection limits, and (3) collect data to 

determine the effectiveness of the cameras in the varying conditions that might be found 

at chemical plants and refineries. 

 - Minimum detection limits tested in laboratory setting, but not directly comparable 

because some cameras have zoom features. In addition, the limit for each camera varies 

with the background, distance from the camera to the leak, and the chemical composition 

of the leak. The BAGI method requires a background; i.e., it will not detect a leak above 

the operator’s head if there is nothing between the leak and the sky. In the laboratory, 
16

PIR cameras (Hawk and Sherlock) detected a leak as long as there was a temperature 

difference of at least 1°F between the gas and the background. Other test factors and 

differences between the cameras prevent direct comparison as well as any conclusions as 

to the “best” camera. 

 - The field study found that of the 66 detected leaks at two test sites, 14 were detected by 

both Method 21 and at least one IR camera, 17 were detected by at least one IR camera 

and not detected by Method 21, and 35 were detected by Method 21 only. The cameras 

cannot quantify the leaks; mass emissions were determined by Method 21 and/or bagging 

the leaking components. Only the 49 leaks detected by Method 21 were quantified. The 

measured leaks detected by the camera were the larger leaks. Of the 35 leaks that were 

undetected by all cameras, 30 were between 0 and 1 g/hr. The measured leaks that were 

detected by at least one cameras had total emissions of 533.9 g/hr. (Total measured 

emissions from 49 leaks were 595.4 g/hr, so the cameras detected about 90% of the 

emissions.) 

 - The areas tested included a 1-butene area with double-pipe heat exchangers, a 1-butene 

pump, an ethylene compressor shed (11 leaks detected), alpha olefin separation units, 

propylene splitters, an ethylene compressor deck (0 leaks detected), propylene pumps, 

and a butadiene separation area. The specific components (e.g., valves) found to be 

leaking were not detailed. Report does say that some leaks were identified from sources 

that are not currently required to be screened using Method 21. 

 - Of the 49 quantified leaks in the field study, 14 were seen by the PIR camera, 9 by the 

mid-wave BAGI (did not survey the butadiene separation area), 7 by the long-wave 

BAGI (did not survey the butadiene separation area), and 8 by IMSS (did not survey the 

1-butadiene pump). Above the 60 g/hr threshold, there were 3 leaks. IMSS, long-wave 

BAGI, and PIR saw all three; mid-wave BAGI missed one. 

4. Regulatory agencies: Results of the laboratory and field tests were used to develop a draft 

alternative work practice protocol for gas-imaging monitoring for the State of Texas (TCEQ). 

OAQPS was also working on a draft of an alternative work practice at the time of this study. 

This study team provided comments on EPA’s drafts using the knowledge gained from this 

study. The team kept in touch with OAQPS while writing their protocol to ensure that the 

alternative work practices were consistent with one another. The authors recommend that 

any regulations adopted by regulatory agencies provide the flexibility to handle new 

technical and operational issues that may arise. This study was funded by the Texas 

Commission on Environmental Quality as a result of an aerial study of the emissions in the 

industrial areas of Houston and Galveston. (TCEQ does not appear to have acted on this 

alternative protocol yet; as of January 2005, their regulations still require emissions factors, 

correlation equations, or Method 21.)