### 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 manda tes that the Environmental Protection Agency (EPA) review and, if appropriate , revise existing new source pe rformance standards (NSPS) at least every 8 years. The focus of this work assign ment 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 chemical s manufacturing industry (40 CFR part 60 subpart VV) and the NSPS for equipment leaks in petroleum refineri es (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. Th e purpose of this memorandum is to provide an update on those activities and summar ize of the information collected.

II. Petroleum Refinery Control Devices

A literature review was conducted to identify candi date control strategies for reducing emissions from units affected by the refinery NSPS (subpart J). A primary resource for potential control strategies is the Midwest Re gional Planning Organization (RPO ) Petroleum Refinery Best Available Retrofit Technology (B ART) Engineering Analysis (MACTEC, 2005). Using this BART analysis and other information collected, the following control t echniques for refinery

NSPS units were identified.2 

### NO

x 

### 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 th e inlet air stream to the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x emissions. The normal NO x control efficiency range for FGR is 30 percent to 50 percent. When coupled with low-NO x burners (LNB) the control efficiency increases to 50-72 percent.

 Low-NO x Burners. Low-NO x burner (LNB) technology utilizes advanced burner design to

reduce NO x formation through the restriction of oxygen, flame temperature, and/or residence time. The two general types of low NO x burners are staged fuel and staged air burners. Staged fuel LNBs are particularly well suited for boile rs and process heaters burning process and natural gas which generate higher thermal NO x . The estimated NO x control efficiency for LNBs where applied to petroleum refining fuel burni ng equipment is generally around 40 percent.

 Ultra-low NO x Burners. Ultra-low NO

x burners may incorporate a variety of techniques including induced flue gas recirculation (IFGR), st eam injection, or a combination of techniques. These burners combine the benefits of flue gas recirculation and low-NO x 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 NO x control efficiency for ULNBs in high temperature applications is 50 percent. Newer designs have yielded efficiencies of betw een 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 NO x control technology in which ammonia (NH 3 ) 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 NO x decomposition. The reaction of NH 3 and NO x is favored by the presence of excess oxygen. The NH 3 oxidation to NO x increases with increasing temperature. The normal NO x control efficiency range for SCR is 70 to 90 percent. ExxonMobil Torrance Refinery website reports the installati on 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 in to the flue gas stream to convert NO to N 2 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, NO x control efficiency decreases rapidly. The normal NO x 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 gene rated 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 NO x removal from a flue gas. For example, LNB has been combined with SNCR technology to minimize the capital and operating cost for NO x removal as well as improve the control efficiency.

 Catalyst Additives. An additional NOx emission control optio n specific for the FCCU is the use of catalyst additive, such as X-NO X and DENOX (from Grace-Davison; Bruhin, et al. 2003).3 

### SO 2 

### Emission Control Options

 Advanced Flue Gas Desulfurization (AFGD). The AFGD process accomplishes SO 2 removal in a single absorber which performs three functions : prequenching the flue gas, absorption of

SO 2 , 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 SO 2 emissions. Wet scrubbing processes used to control SO 2 are generally termed flue-gas desulfurization (FGD) processes. F GD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting liquid, to remove SO 2 in the waste gas. Caustic, crushed limestone, or lime are used as scrubbing agents. The normal SO 2 control efficiency range

for SO 2 scrubbers is 80 percent to 90 percent for lo w 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 SO 2 is absorbed by the slurry, forming

CaSO 3 /CaSO 4 . The liquid-to-gas ratio is such that th e 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 SO 2 , 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 fo r 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 evid ent that cat-feed hydrotreating can significantly

reduce SO

x 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 SO

x 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 SO

x Treatment (MOST) Process. TGTU, such as SCOT and Beavon units are comm only 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 th e overall removal efficiency of the SRU. The MOST process (Stern, et al., 2000) uses combustion of tail gases (to convert the sulfur compounds SO

x ), then a high-capacity solid sorbent material to remove SO

x from the tail gas.

The sulfur-laden sorbent is then reduc tively desorbed and the concentrated SO

x /H 2 S gas is

returned to the head of the Claus unit. Unlik e 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 NO

x emissions (Stern, et al., 2000).

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

reduce SO

x emissions from flares beyond rem oving sulfur compounds (primarily H 2 S) 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 SO

x 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 potentia l 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 th e 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 pr essure 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 absorp tion and can help condense other emissions due to the cooling of the stream by the wash.

 Wet/Venturi Scrubber. Wet scrubbers, and particularly vent uri scrubbers, are an additional control method for PM. Nearly all wet scrubbers u sed 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 SO

x emissions. Wet scrubbers may also be more e ffective in controlling condensable PM. Wet scrubbers are generally more costly to operat e due to high pressure drops across the control device, but they become economically viable if significant SO

x 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 rege nerators 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 NO

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

reductions in NO

x 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 numb er of refineries within each company. RTI

first matched the refineries included in each cons ent 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 th e 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 refi ning companies specify program enhancements for equipment leaks. Requirements in consent decrees for 36 refineries owned by Equilon, Marathon-Ashland, Valero, Lion, Sunoco, and Motiva ar e very similar to each other. All involve minor enhancements to the standard work pr actice 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 constr ucted since 1994 are subject to modified HON5 

### requirements, and facilities may have elected to comply with the modified HON requirements for other process units). The program enhancements fo r 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 pr ogram enhancements for equipment leaks all address the following topics: tr aining, LDAR audits, leak definitions for valves, repairs, monitoring frequency, dataloggers, data QA/QC, ca librations, delay of repair, recordkeeping, and reporting. Most of the requirement s related to these topics reitera te requirements in the federal standards, or they are administ rative procedures designed to ensu re that the standards are met (e.g., training and audits) or prov ide a better way of tracking and demonstrating that they have been met (e.g., more frequent and detailed reco rds 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 requireme nts 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 requir ements 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 ag ainst the otherwise applicable l eak definitions, or they may use the new lower definitions. However, the consen t 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. So me 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 l eaks (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 detect ed). Others specify e ither quarterly or in accordance with the “Sustainable Skip Period progr am.” (The requirements of the skip program have not been reviewed.)

d. Delay of repair. If a unit supervisor de termines that repairing a leaking valve is technically infeasible without a un it shutdown, then the valv e 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 th e regular schedule. Furt hermore, “extraordinary” efforts to repair (e.g., “drill and tap”) are required when the valve is leaking at a le vel of at least 10,000 ppm (unless the refinery dem onstrates that this poses a sa fety or major environmental6 

### concern). Some consent decrees require the extrao rdinary efforts for such valves that have been on the delay of repair list for 3 years. These c onsent decrees also typica lly 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 at tempts at repair are required be fore a valve leaking at greater than 10,000 ppm may be placed on the delay of repa ir 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 Met hod 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 info rmation gathered as part of this effort is

included as Attachment 1.

IV. Additional Data Collection Activities

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

websites of several States’ envir onmental regulatory agencies. Of particular interest are any regulatory requirements that are mo re stringent than the NSPS require ments. So far, regulations for refineries and equipments leaks were discov ered for the states of Texas, California, and Louisiana. These regulations ha ve not been reviewed sufficientl y 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 Qua lity. 2004. “Permit Statement of Basis.” Synthetic Minor Permit No. VF-02-001 (Revis ion 2) for Catlettsburg Refining, LLC. April 13.

MACTEC. 2005. Midwest Regional Planning Or ganization (RPO) Petroleum Refinery Best Available Retrofit Technology (B ART) Engineering Analysis. Prepared for The Lake Michigan Air Directors Cons ortium (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 SO

x 

### Treatment Process (MOST). Catalytic removal of SO

x 

### and H 2 

### S from refinery tailgas.” Catalyst Today , Vol. 55, pp. 311-316.7Table 1. Information from Consent Decrees Reviewed by RTIFacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other12 Lion Oil Co. El Dorado AR X X X Xheaters and boilers, unitsemitting benzene,wastewater treatment15 Chevron USA Products Co. El Segundo CA X X X Xheaters and boilers, unitsemitting benzene16 Chevron USA Products Co. Richmond CA X X X Xheaters and boilers, unitsemitting benzene29.1ConnocoPhillips (formerly Tosco, formerlyUnocal Corp.) LA - Carson CA X X Xheaters and boilers, unitsemitting benzene29.2ConnocoPhillips (formerly Tosco, formerlyUnocal Corp.)LA -Wilmington CA X X X Xheaters and boilers, unitsemitting benzene30.1ConnocoPhillips (formerly Tosco, formerlyUnocal Corp.) SF - Rodeo CA X X X heaters and boilers30.2ConnocoPhillips (formerly Tosco, formerlyUnocal Corp.)SF - SantaMaria CA X X X heaters and boilers17Shell (formerly Equilon, formerly TexacoRefining & Marketing Inc.) Bakersfield CA X X Xheaters and boilers, unitsemitting benzene18Shell (formerly Equilon, formerly Shell OilCo.) Martinez CA X X X Xheaters and boilers, unitsemitting benzene19Shell (formerly Equilon, formerly TexacoRefining & Marketing Inc.) Wilmington CA X X X Xheaters and boilers, unitsemitting benzene31Tesoro (formerly Ultramar DiamondShamrock, formerly Tosco Corp. - Avon)GoldenEagle CA X X X Xheaters and boilers, unitsemitting benzene32Valero (formerly Ultramar DiamondShamrock) Wilmington CA X X X Xheaters and boilers, unitsemitting benzene8FacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other33 Valero ( formerly ExxonCo. USA) Benicia CA X X X Xheaters and boilers, unitsemitting benzene36Valero Energy (formerly Ultramar DiamondShamrock, formerly Total Petroleum) Denver CO X X X Xheaters and boilers, oilwater separator, loadingdock racks, petroleumstorage tanks, unitsemitting benzene37Premcor (formerly Motiva Enterprises,formerly Star)DelawareCity DE X X X Xheaters and boilers, unitsemitting benzene37.5 Citgo Petroleum Savannah GA Xheaters and boilers, unitsemitting benzene39 Chevron USA Inc.Barber'sPoint HI X X Xheaters and boilers, unitsemitting benzene41 Citgo Petrol. (formerly UNO-VEN) Lemont IL X X X Xheaters and boilers, unitsemitting benzene43 Marathon Ashland Petrol. Robinson IL X X X Xheaters and boilers, unitsemitting benzene45Premcor Refining Group (formerly Clark Oiland Refining Corp.) Hartford IL X heaters and boilers46ConnocoPhillips (formerly Tosco Refining,Equilon, Wood River, & ShellOil) Wood River IL X X X Xheaters and boilers, unitsemitting benzene51 National Cooperative Refinery Association McPherson KS X X X Xboilers, contaminatedgroundwater53 Marathon Ashland Petroleum LLC Catlettsburg KY X X X Xwastwater treatment,containment in storageareas, heaters and boilers,units emitting benzene9FacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other61 Citgo Petroleum Corp.LakeCharles LA X X X Xheaters and boilers, unitsemitting benzene65 Marathon Ashland Petroleum LLC Garyville LA X X X Xheaters and boilers, unitsemitting benzene66 Motiva Enterprises (formerly Star) Convent LA X X X Xheaters and boilers, unitsemitting benzene67 Motiva Enterprises (formerlyShell Oil Co.) Norco LA X X X Xheaters and boilers, unitsemitting benzene69Valero (formerly Orion Refining Corp,formerly TransAmerican Refining Corp) Norco LA X X X Xheaters and boilers, unitsemitting benzene73ConocoPhillips (formerly, Tosco RefiningCo., formerly BP Oil Co.)BelleChasse LA X X X Xheaters and boilers, unitsemitting benzene74 Valero (formerly Basis Petroleum, Inc.)KrotzSprings LA X X Xheaters and boilers, unitsemitting benzene75 Marathon Ashland Petrol. LLC Detroit MI X X Xheaters and boilers, unitsemitting benzene77 Marathon Ashland Petrol. LLCSt. PaulPark MN X X Xcontaminated groundwater(WWTP), heaters andboilers, units emittingbenzene78 Chevron USA Inc. Pascagoula MS X X X Xheaters and boilers, unitsemitting benzene79 Ergon Refining Inc. Vicksburg MS Xheaters and boilers, unitsemitting benzene, drainsystems, oil-waterseparators, aggregatefacilities10FacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other85 Montana Refining Co. Great Falls MT X X X units that emit benzene87.6 Citgo Asphalt Refining Co. Paulsboro NJ X Xheaters and boilers, unitsemitting benzene88Sunoco (formerly Coastal Eagle Point OilCo.) Westville NJ X X X Xrefinery fuel gas system,heaters and boilers, unitsemitting benzene89ConocoPhillips (formerly Tosco RefiningCo., formerly Bayway) Linden NJ X X X Xheaters and boilers, unitsemitting benzene90 Valero Energy Corp. (formerlyMobil Oil) Paulsboro NJ X X X Xheaters and boilers,wastewater plant separator,units emitting benzene93 Navajo Refining Co. Artesia NM X X X Xheaters and boilers, unitsthat emit benzene96 Marathon Ashland Petrol. LLC Canton OH X X X Xindividual drain systems,storage tanks, oil-waterseparator, heaters andboilers, units emittingbenzene98 Sunoco, Inc. Toledo OH X X X Xheaters and boilers, unitsemitting benzene102 Sunoco, Inc. Tulsa OK X Xheaters and boilers, unitsemitting benzene103Valero (formerly Ultramar/DiamondShamrock, formerly Total Petroleum Inc.) Ardmore OK X X X Xheaters and boilers,alkylation neutralizationsystem, units emittingbenzene105 Sunoco, Inc.MarcusHook PA X X X Xheaters and boilers, unitsemitting benzene11FacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other106 Sunoco (combined Sun & Chevron)Phil. (GirardPt & PtBreeze) PA X X X Xheaters and boilers, unitsemitting benzene107ConocoPhillips (formerlyTosco RefiningCo., formerly BP)Trainer(MarcusHook) PA X X X Xheaters and boilers, unitsemitting benzene115 CitgoCorpusChristi TX X X X Xheaters and boilers, unitsemitting benzene123 Marathon Ashland Petrol. LCC Texas City TX X X X Xheaters and boilers, unitsemitting benzene124 Motiva Enterprises (formerlyStar) Port Arthur TX X X X Xheaters and boilers, unitsemitting benzene125ConocoPhillips (formerly Phillips PetroleumCo.) Borger TX X X X Xheaters and boilers, unitsemitting benzene126ConocoPhillips (formerly Phillips PetroleumCo.) Sweeny TX X X X Xheaters and boilers, unitsemitting benzene128Shell -Deer Park Refining LimitedPartnership Deer Park TX X X Xheaters and boilers, unitsemitting benzene130Valero (formerly Ultramar/DiamondShamrock Corp.)ThreeRivers TX X X X Xheaters and boilers, unitsemitting benzene131Valero (formerly Ultramar/DiamondShamrock Corp.) Sunray TX X X X Xheaters and boilers, sulfuricacid plant, units emittingbenzene132 Valero Refining Co.CorpusChristi TX X X X Xheaters and boilers,hydrodesulfurization unit,units emitting benzene12FacilityNo. FacName City StateUnits Subject to Consent DecreeFlares FCCU SRUEq.Leaks Other133 Valero (formerly Basis Petroleum, Inc.) Houston TX X X X Xheaters and boilers, unitsemitting benzene134 Valero (formerly Basis Petroleum, Inc.) Texas City TX X X X Xheaters and boilers, unitsemitting benzene136 Chevron USASalt LakeCity UT X X X X units emitting benzene142Shell Oil (formerly Equilon Enterprises,formerly Texaco Refining & Marketing Inc.) Anacortes WA X X X Xheaters and boilers, unitsemitting benzene145ConocoPhillips (formerly Tosco RefiningCo.) Ferndale WA X X X Xheaters and boilers, unitsemitting benzene147Ergon-West Virginia inc. (formerly QuakerState Oil Refining Corp.) Newell WV X Xheaters and boilers, unitsemitting benzene, drains148 Murphy Oil USA Inc. Superior WI X X X process heaters and boilersN/A Global Companies LLC Waltham MACompliance AssuranceProgram for gasolineblendingN/A Navajo Refining Lovington NM X Xheaters and boilers, unitsthat emit benzene13 

### 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 us e 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 lead er in infrared cameras” – GasFindIR infrared

camera 4. Regulatory agencies: Article quotes Davi d Markwordt as saying that USEPA is in the process of writing regulations to take advantage of the technology.

Pacific Advanced Technology website: produc t brochure and informa tion about Sherlock

1. Manufacturer: Pacific Advanced Te chnology with support fro m US DOE, state of California, and the Gas Technology Institute (u nder 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 Met hod 21: Testing shows that IMSS can measure target spectral signatures consisting of multiple species si multaneously 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 ambi ent light is needed. In Phase I tests, IMSS successfully imaged leaks as small as 0.01 ft 3 

### /min. 5. Any other issues/ questions: The product broc hure contains fairly detailed specs for the product.

Erin Young, Petro-Canada. Optical Emissions Detection Technology – Technical Abstract. Prepared for Petroleum Technology A lliance Canada. September 2004.

1. Manufacturer: (a) Raytheon (Palm IR 250) a nd (b) Leak Systems, Inc. (US)/Maverick Inspection LTD (Canada) (HAWK)

3. Performance relative to Met hod 21: (a) Operating temperature ra nge is -20° to 49°C (-4° to 120°F). Cost is about $20,000. (b) Maverick LSI HAWK technology is proprietary and14 

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

and the consultant f ee is about $4,000/day. 5. Any other issues/ questions: Abstract says th at most cameras use passive infrared instead of

active infrared because it uses ambient radiat ion, consumes less power, and is much easier to use in a number of ways.

Thermal-eye website (http://www.thermal-eye.co m) 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 Pollu tion Prevention Equipment Program tested the PalmIR Pro on its ability to loca te harbor oil spills. Accordin g to PPEP, it reduces chemical testing required to locate spill s, reduces the amount of petroleum products in harbors by quickly identifying the source of discharge and determining a ccountability, 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 de tection as one of the applica tions. 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 Met hod 21: (a) Operating temperature range is -15° to 50°C (5° to 122°F). 5. Any other issues/ questions: Detaile d 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: Exam ined 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 leas t 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 purch ase 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 indi cating that the Hawk is used more on a “rental” basis.

TCEQ Regulatory Watch – July 2005

2. Who is using the system: The contractor fo r this project is Lamar University, who is using Leak Surveys, Inc. (LSI), as its subcontracto r. LSI is performing mo st 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 inform ation on the source, id entity, 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 Factor s and/or Correlation Equations fo r 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 Ev aluation 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 Na perville, IL, was used for the tests. Electric power facilities use the LIS GasVue® to detect SF 6



### . 3. Performance relative to Method 21: (t wo phases; lab testi ng and field study): - EPA developed Monte Carlo simulation softwa re, 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 gr ams per hour (g/hr) would result in equivalent environmental protection to Method 21. Theref ore, EPA has accepted a 60 g/hr threshold for gas imaging. - Cameras tested in a laboratory in A ugust 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 propylen e 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 la boratory 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 bac kground; 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 d eck (0 leaks detected), propylene pumps, and a butadiene separation area. The sp ecific components (e.g., valves) found to be leaking were not detailed. Report does say th at 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 butad iene separation area), 7 by the long-wave BAGI (did not survey the butadiene separati on area), and 8 by IMSS (did not survey the 1-butadiene pump). Above the 60 g/hr thres hold, 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 test s 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 practi ce at the time of this study. This study team provided comments on EPA’s draf ts 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 agenci es 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. (T CEQ does not appear to have acted on this alternative protocol yet; as of January 2005, thei r regulations still requi re emissions factors, correlation equations, or Method 21.)