CAM Applicability Analysis and CAM Plansweb.epa.state.oh.us/dapc/transfer/BPHUSKY/P0104782/A0037896/264112[1].pdfCAM applicability is evaluated on a pollutant-specific emission unit

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BP-Husky Refining LLC Toledo Refinery

CAM Applicability Analysis

and CAM Plans Prepared for:

4001 Cedar Point Road Oregon, Ohio 43616

Prepared by:

URS Corporation Waterfront Plaza Tower One 325 West Main Street, Suite 1200 Louisville, KY 40202

Project Number 41916940

April 9, 2009

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EXCUTIVE SUMMARY ................................................................................................. 1

1.0 OVERVIEW OF CAM .............................................................................................. 4

1.1 CAM PLAN DUE DATE .................................................................................... 4

1.2 CAM PLAN REQUIREMENTS ......................................................................... 4

1.3 CAM APPLICABILITY TEST ............................................................................ 5

1.4 EXEMPT RULES AND EMISSION LIMITS ...................................................... 7

2.0 CAM ANALYSIS METHODOLOGY ........................................................................ 9

2.1 BOILERS / HEATERS ...................................................................................... 9

2.2 PROCESS UNITS .......................................................................................... 10

2.3 FCC/CO BOILER ............................................................................................ 11

2.4 CRUDE VAC 1 ............................................................................................... 12

2.5 CRUDE VAC 2 ............................................................................................... 13

2.6 TANKS ............................................................................................................ 13

2.7 FUGITIVE SOURCES AND LOADING OPERATIONS .................................. 14

ATTACHMENT A

ATTACHMENT B

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EXECUTIVE SUMMARY

This report documents URS’ analysis of the applicability of 40 CFR Part 64, the Compliance Assurance Monitoring (CAM) rule, to BP-Husky’s Toledo refinery. Generally, CAM is required for emission sources which utilize a control device to meet a non-exempt emission standard and have pre-control emissions above the major source threshold (i.e. 100 tpy for a criteria pollutant, 10 tpy for a HAP). (Note, emission standards from MACT rules and certain other regulations are exempt from CAM) The CAM applicability analysis results are illustrated in Attachment A and discussed in detail below. This analysis has determined that the existing monitoring already required is adequate for the purposes of CAM. CAM applicability is separately determined for each pollutant emitted by an emission unit, or as it is defined in Part 64, pollutant-specific emission units (PSEU). At BP-Husky’s Toledo refinery, twenty-nine (29) PSEUs covering twenty-eight (28) emission units were determined to be subject to the CAM rule. Twenty of these are heaters and boilers which utilize the fuel gas system to reduce H2S in fuel gas to comply with SO2 emission limits (i.e. 20 PSEUs). The other eight emission units each have at least one pollutant subject to CAM (i.e. 9 PSEUs). The PSEUs and a summary of the CAM approach for each is shown in Table 1 below. Detailed CAM plans, where necessary, for each PSEU are presented in Attachment B.

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Table 1 PSEU Subject to CAM and Summary of CAM Approach/Plan

Emission Unit Pollutant Rule Control Device CAM Approach/Plan Summary

Boilers/Fuel Burning Equipment

SO2 OAC 3745-18-54(W) Amine Treaters

SO2 emissions have been historically correlated with H2S concentration in the fuel gas. H2S is monitored via continuous emission monitoring (CEM) in accordance with the Title V permit. Compliance with the H2S limits ensures compliance with the SO2 limitations. See CAM Plan in Attachment B

FCC/CO Boiler Stack (P007)

PM OAC 3745-17-10 and -17-11 ESP

Continuous Opacity Monitoring (i.e. COM). See CAM Plan in Attachment B

NOX Consent Decree SNCR NOX is directly monitored via CEM. See CAM Plan in Attachment B

Crude/Vac 1 (P011) Offgas VOC OAC 3745-21-

09(M)(1) Boiler 15 (B015)

Monitoring of bypasses. See CAM Plan in Attachment B

Crude/Vac 2 (P010) Offgas SO2 OAC 3745-18-54(W)

RFG Amine Treaters

Since this gas is routed to the refinery fuel gas (RFG) system, the monitoring of H2S in RFG (described above for the boilers and heaters) demonstrates compliance per the Title V permit. A CAM plan, in addition to the one proposed above for the boilers and heaters, is not proposed.

Alky I (P021) Blowdown Drum

VOC OAC 3745-21-09(UU)

Flare

40 CFR Part 63 Subpart CC and 40 CFR Part 61 Subpart FF also require the use of a flare for VOC (as a surrogate for organic HAPs) and Benzene control, respectively. The flare monitoring specified in both of these requirements is already specified in the Title V permit for OAC 3745-21-09(UU) compliance and is presumptively acceptable CAM monitoring because the Subpart CC and Subpart FF monitoring is exempt from CAM. Therefore, no additional monitoring for CAM is proposed for OAC 3745-21-09(UU). CAM for OAC 3745-21-09(UU) is compliance with the Subpart CC and Subpart FF monitoring requirements.

Alky II (P022) and Alky III (P023) Blowdown Drum

WWT System (P025) Benzene NESHAPs Sewer

Cat Poly Plant (P043) Flash Drum Vent

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A source by source summary of the CAM applicability analysis results is presented in a tabular format in Attachment A. The table in Attachment A lists the emission units and relevant “regulated” contaminants. Each cell in the table corresponds to a single PSEU. A red “X” indicates a PSEU is subject to CAM and requires a CAM plan. Empty or uncolored cells indicate the pollutant is not regulated for that particular emission unit and therefore not subject to CAM. Conversely, shaded cells and cells that contain the letters “CEM” indicate that the pollutant is regulated for that particular emission unit, but the PSEU is exempt from CAM. In particular, “CEM” indicates that the current Title V specifies a continuous compliance demonstration method and thus qualifies as an exemption from CAM (see detailed discussion of CAM exemptions below). The particular color for shaded cells indicates the reason the PSEU is exempt from CAM. The table below provides a summary of the color coding.

Color of Shaded Cell/PSEU Reason for Exemption Green Emission unit is an insignificant activity. Uncontrolled PTE is therefore

less than the CAM applicability threshold of 100 tpy. Tan There is no control device for this PSEU. This is relevant to the PM, NOX,

CO, VOC and PM10 emission limits for the fuel burning equipment, fuel and asphalt loading operations, cooling towers, most of the tanks, and a few other emission units.

Blue The PSEU is subject to an exempt VOC emission limit from 40 CFR Part 63 Subpart CC. Most of the PSEUs associated with tanks and a few PSEUs associated with the process operations fall into this category.

Purple The PSEU is subject to an exempt emission limit from 40 CFR Part 63 Subpart UUU. This exemption applies to various PSEUs associated with the Reformers, SRUs and FCC.

Orange The PSEU has an uncontrolled PTE less than 100 tpy. This is relevant to only a few emission units, including the plant roadways, cokers and a few tanks.

In summary, with the exception of the PSEUs listed in Table 1, all PSEUs are exempt because they have an uncontrolled PTE less than 100 tons per year, don’t have a control device, are subject to a MACT standard, or are an insignificant activity. A discussion of the applicability determination approach and results is provided below along with a summary of the CAM rule.

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1.0 OVERVIEW OF CAM The CAM rule was promulgated in the October 22, 1997 Federal Register. The rule potentially applies to emission units at major stationary sources required to obtain Title V operating permits. If an emission unit meets the applicability test specified in the rule, then the source must submit a CAM plan proposing monitoring to provide reasonable assurance of compliance with the applicable emission limitation along with a justification for choosing the proposed monitoring. Since existing monitoring may be sufficient, a CAM plan may propose no new monitoring. The regulatory agency will review the plan, and incorporate any new, approved monitoring into the Title V permit. Absent the use of a CEM, CAM plans must establish monitoring parameters for affected control devices, and specify a range for the parameter that indicates compliance. Record keeping and reporting is required to document that the ranges have been met.

1.1 CAM PLAN DUE DATE The effective date of the rule was November 21, 1997. However, sources like BP-Husky, with an initial Title V permit application that was deemed complete by April 20, 1998, were deferred from the requirement to submit CAM plans until either the Title V renewal application was due or an application for a significant permit revision for the CAM unit was submitted. BP-Husky’s initial Title V application was deemed complete prior to April 20, 1998, and no significant permit revisions have been submitted for potential CAM units. Therefore, initial CAM plans are due with the Title V renewal application, which is due on April 13, 2009.

1.2 CAM PLAN REQUIREMENTS The rule requires that a CAM plan contain the following elements:

• Indicators to be monitored, with indicator ranges or the process to be used to establish the ranges

• Justification for the use of the parameters, ranges, and monitoring approach

• Emissions test data or a test plan and schedule, unless the source demonstrates that testing is unnecessary to establish indicator ranges at levels that satisfy the CAM criteria

• If necessary, an implementation plan for installing, testing, and operating the proposed monitors

The final Title V permit will include the monitoring plan approved by the agency. CAM monitoring must start upon issuance of the Title V permit, unless the proposed monitoring requires installation, testing, or final verification of operational status. In such cases, the

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permit will include an enforceable schedule for implementing the monitoring (see 40 CFR 64.6(d)).

1.3 CAM APPLICABILITY TEST CAM applicability is evaluated on a pollutant-specific emission unit (PSEU) basis. A PSEU is an emission unit considered separately with respect to each regulated air pollutant. The CAM rule applies to each PSEU that meets a three-part test. The PSEU must:

1. Be subject to a non-exempt emission limitation or standard for the regulated air

pollutant (see below for a discussion on exempt emission standards), and

2. Use a control device to achieve compliance with that emission limitation or standard, and

3. Have potential pre-control device emissions of the regulated air pollutant greater than or equal to the major source threshold for that pollutant in tons per year (e.g. 100 tons per year for criteria pollutants, 10 tons per year for HAPs, etc).

It is important to understand the definition of two of the above terms, “emission limitation or standard” and “control device.” The Part 64 definitions for these terms is provided below: “Emission limitation or standard means any applicable requirement that constitutes an emission limitation, emission standard, standard of performance or means or emission limitation as defined under the Act. An emission limitation or standard may be expressed in terms of the pollutant, expressed either as a specific quantity, rate or concentration of emissions (e.g., pounds of SO2 per hour, pounds of SO2 per million British thermal units of fuel input, kilograms of VOC per liter of applied coating solids, or parts per million by volume of SO2) or as the relationship of uncontrolled to controlled emissions (e.g., percentage capture and destruction efficiency of VOC or percentage reduction of SO2). An emission limitation of standard may also be expressed either as a work practice, process or control device parameter, or other form of specific design, equipment, operational, or operation and maintenance requirement. For purposes of this part, an emission limitation or standard shall not include general operation requirements that an owner or operator may be required to meet, such as requirements to obtain a permit, to operate and maintain sources in accordance with good air pollution control practices, to develop and maintain a malfunction abatement plan, to keep records, submit reports, or conduct monitoring.” “Control device means equipment, other than inherent process equipment, that is used to destroy or remove air pollutant(s) prior to discharge to the atmosphere. The types of equipment that may commonly be used as control devices include, but are not limited to,

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fabric filters, mechanical collectors, electrostatic precipitators, inertial separators, afterburners, thermal or catalytic incinerators, adsorption devices (such as carbon beds), condensers, scrubbers (such as wet collection and gas absorption devices), selective catalytic or non-catalytic reduction systems, spray dryers, spray towers, mist eliminators, acid plants, sulfur recovery plants, injection systems (such as water, steam, ammonia, sorbent or limestone injection), and combustion devices independent of the particular process being conducted at an emissions unit (e.g., the destruction of emissions achieved by venting process emission streams to flares, boilers or process heaters). For purposes of this part, a control device does not include passive control measures that act to prevent pollutants from forming, such as the use of seals, lids, or roofs to prevent the release of pollutants, use of low-polluting fuel or feedstocks, or the use of combustion or other process design features or characteristics. If an applicable requirement establishes that particular equipment which otherwise meets this definition of a control device does not constitute a control device as applied to a particular pollutant-specific emission unit, then that definition shall be binding for purposes of this part.” The CAM rule excludes inherent process equipment from the definition of control devices. Inherent process equipment is defined as: “Inherent process equipment means equipment that is necessary for the proper or safe functioning of the process, or material recovery equipment that the owner or operator documents is installed and operated primarily for purposes other than compliance with air pollution regulations. Equipment that must be operated at an efficiency higher than that achieved during normal process operations in order to comply with the applicable emission limitation or standard is not inherent process equipment. For the purposes of this part, inherent process equipment is not considered a control device.” It should be noted that under these definitions, while the use of floating roofs (either internal or external) would be considered an emission limitation or standard because they are a “…form of specific design, equipment, operational, or operation and maintenance requirement,” they are not considered control devices because they are “…passive control measures that act to prevent pollutants from forming, such as the use of seals, lids, or roofs to prevent the release of pollutants…”. Conversely, the Title V requirement to minimize fugitive emissions from roadways constitutes a “work practice” and thus an emission limitation or standard and the methods used to minimize emissions, such as water sprays, are considered a control device. Finally, regarding the third applicability test, due to the complexity of calculating pre-control emissions for most refinery operations, in general it was conservatively assumed that pre-

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control device emissions were greater than the applicability threshold. However, most PSEUs were either exempt from CAM because the underlying emission limitation or standard was exempt (i.e. MACT standards and Title V specified CEMs) or were not subject to CAM because a control device is not needed to meet the applicable emission limitation or standard. Insignificant and trivial activities, by definition, have potential emissions less than 5 tons per year and are thus exempt from CAM.

1.4 EXEMPT RULES AND EMISSION LIMITS Part 64 offers several exemptions from CAM. The exemptions are related to rules or emission limits, and not to specific equipment. The exemptions are based on EPA’s finding that certain rules and emission limits already contain monitoring requirements sufficient to provide compliance assurance, so that no additional monitoring analysis is required for the rule. The specific exemptions are:

• Emission limits from Section 111 and 112 standards (40 CFR Parts 60 New Source Performance Standards, and 61 and 63 National Emission Standards for Hazardous Air Pollutants) promulgated after November 15, 1990

• Emission limits or standards imposed under the stratospheric ozone protection requirements of Title IV of the Clean Air Act

• Emission limits or standards imposed under an emissions trading program

• Emission caps that meet the requirements in 40 CFR 70.4(b)(12) or 71.6(a)(3)(iii)

• Emission limits or standards for which a Part 70 or 71 (i.e. Title V) permit specifies a continuous compliance determination method that provides data either in units of the standard or correlated directly with the compliance limit

It is important to note that if a PSEU is subject to one of the exempted rules, and is also subject to other non-exempt rules, even for the same pollutant, then a CAM plan must still be submitted for the non-exempt rule or emission limitation. (see FR 54196, October 22, 1997 and U.S. EPA FAQ for the CAM rule). For example, SO2 from combustion sources at the refinery is regulated by both an NSPS and Ohio State regulation. In the case of the NSPS standard, H2S is used as a surrogate for SO2 and the Title V permit (Part 70 rule) specifies a continuous compliance determination method for H2S (i.e. CEMs). SO2, as regulated by the NSPS standard, is therefore exempt from CAM (see last bullet above). The Ohio State regulation does not contain a similar monitoring requirement (i.e. H2S as surrogate); therefore, SO2, as regulated by the Ohio standard, is not exempt from CAM. However, the Ohio EPA recognizes that SO2 emissions have historically been correlated to H2S concentration in the fuel gas, and, as a streamlining measure, have stated in the Title

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V permit that compliance with the H2S limit ensures compliance with the SO2 limit. Therefore, the CAM plan for SO2 emissions from the refinery fuel burning sources, as regulated by the Ohio standard, is simply to use the current H2S monitoring as a surrogate. (Note: the referenced NSPS standard, NSPS J, was promulgated prior to November 15, 1990; therefore, both SO2 and H2S are NOT exempt under bullet one above. Further, since the NSPS standard specifies a limit on H2S, H2S itself is also a regulated pollutant. However, since the current Title V specifies the use of a CEM, the H2S emission standard is exempt from CAM (see last bullet above).

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2.0 CAM ANALYSIS METHODOLOGY To determine the applicability of the CAM rule on BP-Husky’s Toledo facility, URS reviewed the applicable requirements in the most recent Title V permit, the most recent fee emission report, applicable regulations, and a preliminary CAM applicability analysis completed in 1998. We also incorporated information from our previous and on-going work at the facility. From these data sources, we assembled a table of emission units and pollutants with emission limitations or standards, thus defining the PSEUs. For each PSEU, we then determined if any exemption from the CAM rule applied. As shown in Attachment A, many of the PSEUs were exempt because there was no associated control device, the PTE was less than 100 tons per year (by definition, insignificant activities have a PTE < 100 tpy) or the PSEU was subject to a 40 CFR Part 63 (MACT) regulation. A more detailed discussion of the CAM applicability analysis results by either process type or specific emission unit is provided below.

2.1 BOILERS/HEATERS All of the boilers and heaters (not including the CO boiler associated with the FCC) have emission limits on SO2, H2S, and either PM or PM10. Additionally, the newer boilers and heaters have emission limits on NOX, CO and VOC. The boilers and heaters do not employ control devices to abate emissions of PM, PM10, NOX, CO and VOC; therefore, CAM is not applicable to these pollutants.

Since SO2 emissions from the boilers and heaters results from the combustion of RFG which contains H2S, the most effective way to control SO2 emission is to control the H2S concentration in the RFG. BP-Husky’s Toledo refinery uses several amine treaters to remove H2S, a by-product of the refining process, from the fuel gas before it enters one of several RFG supply headers. A continuous emission monitor (CEM) is used to monitor the H2S concentration in the RFG at each mix drum (i.e. after amine treatment). Since the current Title V permit specifies a continuous compliance determination method, the emission limit on H2S is exempt from CAM. However, since the Title V permit does not similarly explicitly specify a continuous compliance determination method for SO2, and uncontrolled SO2 emissions are assumed to be greater than 100 tpy from each boiler or heater, CAM is arguably applicable to the boilers and heaters for the SO2 emission limits that are complied with through the use of the amine treaters which can be interpreted to serve as the upstream “control device.” SO2 emissions from the fuel burning equipment and crude/vac units have historically been correlated to the H2S concentration (in the fuel combusted). H2S, which is converted to SO2 during combustion, is, by far, the predominant sulfur containing compound in refinery

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fuel gas (RFG) prior to removal by amine treatment. EPA recognizes this, and has used H2S as a surrogate for SO2 in its regulation of refinery fuel burning equipment (see NSPS J and Ja). Further, H2S concentration is directly related to the efficiency of the amine treaters, the “control device” for SO2 emissions from fuel burning equipment using RFG. For these reasons, we propose the current monitoring conducted for H2S concentration in RFG (i.e. a surrogate for amine treater operating efficiency) to satisfy the CAM monitoring requirements for SO2. In cases where CEMs that meet the monitoring requirements and performance specifications in 40 CFR Part 64.3(d) are already in place (such as those required by the current Title V permit, an applicable MACT, or other exempt emission standard), a detailed CAM Plan is not required (see 40 CFR 64.3(d) and 64.4(b)(2)). This is the case for the SO2 emissions from combustion sources (indirectly via H2S CEM on RFG). The H2S CEM is a reliable indicator of the performance of the amine treaters, the “control device” for SO2 emissions from the fuel burning equipment. The CAM plan presented in Attachment B for the fuel burning equipment proposes that the current exempt continuous compliance determination method for H2S be used for SO2 as well. This is also consistent with the SO2 compliance demonstration method in the current Title V permit.

2.2 PROCESS UNITS (except FCC/CO Boiler, Crude/Vac 1 and Crude/Vac 2) The various refinery process units are primarily sources of VOC emissions from fugitive component leaks or miscellaneous process vents. The fugitive component leaks have no “control device” and otherwise generally have an uncontrolled VOC PTE less than 100 tons per year. Therefore, VOC emissions from fugitive component leaks are not subject to CAM. Several of the refinery process units have miscellaneous process vents required by both OEPA regulation (OAC 3745-21-09(UU)) and U.S. EPA regulation (40 CFR Part 63 Subpart CC) to be vented to a flare or the fuel gas system for VOC control (Subpart CC uses VOC as a surrogate for organic HAPs). While the MACT VOC emission standards are exempt from CAM, the OEPA regulation for the same pollutant is not. However, in instances where both an exempt emission standard and a non-exempt emission standard apply to the same pollutant at an emission unit, CAM allows for using the same monitoring to address both standards. In fact, proposing the use of monitoring from an exempt standard as the CAM plan for a non-exempt emission standard is considered “presumptively acceptable monitoring” under Part 64 (see 40 CFR 64.4(b)(4)). For four of the five emission units with miscellaneous process vents (P021, P022, P023, and P043), the monitoring specified in the Title V permit for regulation OAC 3745-21-09(UU) already specifies that compliance with the State regulation is accomplished by following the MACT

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monitoring requirements. Therefore, the CAM plan/approach for these emission units is to comply with the monitoring already required in the Title V permit and we propose no additional monitoring beyond that. As such, Attachment B contains no additional CAM plan information for these emission units. Similarly, the P025 Benzene Strippers have a miscellaneous process vent that is required by both OEPA regulation (OAC 3745-21-09(UU)) and U.S. EPA regulation (40 CFR Part 61 Subpart FF) to be vented to a flare for VOC and Benzene control, respectively. While the VOC emission standards under the U.S. EPA regulations are exempt from CAM, the OEPA regulation for the same pollutant is not. Even though these two regulations focus on different pollutants, in the case of P025, monitoring related to control device performance is the same for both pollutants. That is, the presence of a pilot flame at the flare. Again, proposing the use of monitoring from an exempt standard as the CAM plan for a non-exempt emission standard is considered “presumptively acceptable monitoring” under Part 64 (see §64.4(b)(4)). The monitoring specified in the Title V permit for regulation -21-09(UU) already states to follow the Subpart FF monitoring requirements. Therefore, the CAM plan/approach for this emission unit is to comply with the monitoring already required in the Title V permit and proposes no additional monitoring beyond that. As such, Attachment B contains no additional CAM plan information for these emission units.

The only exceptions to the above are:

• Coker 3 (P017) which is not subject to CAM because it has uncontrolled PTE less than 100 tpy of VOC, and

• Natural Gas System (P005) has no regulated pollutants and is therefore not subject to CAM.

Additional pollutants, such as SO2, PM, NOX, CO, and HCl are also regulated at a few of the process units. However, these emission standards are all exempt from CAM for the following reasons:

• There is no associated control device or

• The emission standard came from 40 CFR Part 63 Subpart CC or 40 CFR Part 63 Subpart UUU.

2.3 FCC/CO BOILER (P007) The FCC/CO Boiler is regulated for SO2, H2S, PM, NOX, CO, NH3 and Ni; however, except for PM and NOX, the emission limits for the remaining pollutants are exempt from CAM for the following reasons:

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• The emission standards for both CO and Ni are exempt from CAM because these emission standards are from 40 CFR Part 63 Subpart UUU, which is an exempt emission standard.

• Uncontrolled PTE for NH3 is less than 100 tpy, and is therefore not subject to CAM.

• A continuous compliance demonstration method is specified in the current Title V permit for SO2 and H2S; therefore, these emission limits are exempt from CAM.

The remaining PSEUs, PM and NOX from the FCC/CO Boiler, are subject to CAM since uncontrolled PTE is assumed to be greater than 100 tpy. As already required by the Title V permit, a continuous opacity monitor (COM) is used to demonstrate compliance with the opacity limit for the FCC/CO Boiler. However, a COM can be used to demonstrate compliance with the State and Consent Decree PM emission limits. Though the COM is already required to be operated and maintained by the Title V permit, a CAM plan is required for the COM to detail the opacity range that demonstrates compliance with the PM emission limits and provides a justification for the selected range. Attachment B includes a CAM plan for the FCC/CO Boiler-PM PSEU which proposes maintaining opacity at or below 10% on an hourly average basis. In cases where CEMs that meet the monitoring requirements and performance specifications in 40 CFR Part 64.3(d) are proposed, a detailed CAM Plan is not required (see 40 CFR 64.3(d) and 64.4(b)(2)). This is the case for the NOX CEM which is proposed to be used to monitor NOX emissions. Attachment B includes a CAM plan for the FCC/CO Boiler-NOX PSEU.

2.4 CRUDE/VAC 1 (P011) Crude/Vac 1 is regulated for VOC, H2S and SO2 emissions from the overhead gas produced in the process. As required by the Title V permit, for abatement of these pollutants, the overhead gas is normally routed to the Crude/Vac 1 Amine Contactor before being combusted in the Crude 1 Furnace (B015). Monitoring for H2S (and indirectly the resultant SO2) is performed immediately after the Crude/Vac 1 Amine Contactor. Since the Title V permit specifies a continuous compliance demonstration method for H2S and SO2, the emission standards for H2S and SO2 are exempt from CAM. The VOC emission standard is non-numeric – the standard is simply to combust the overhead gases in a suitable combustion device. Since there are no performance specifications required of the combustion device to which gases are routed, the combustion device, in this case, is considered inherent process equipment. Therefore, no

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VOC CAM plan is required for the control device. However, since the “control device” for both VOC and H2S/SO2 can be bypassed at Crude/Vac 1, CAM monitoring for bypasses is proposed (see Attachment B).

2.5 CRUDE/VAC 2 (P010) As with Crude/Vac 1, Crude/Vac 2 is regulated for VOC, H2S and SO2 emissions from the overhead gas produced in the process. As required by the Title V permit, for abatement of these pollutants, the overhead gas from Crude/Vac 2 is routed to a boiler or heater via the refinery fuel gas system. Though the Title V permit conditions for Crude/Vac 2 do not separately require monitoring of H2S (and thus SO2) in the RFG, monitoring of RFG H2S concentration is conducted as part of the compliance demonstration method for the SO2 emission limits at the boilers and heaters. As stated in the Title V permit, compliance with the H2S concentration limit for heaters from NSPS J demonstrates compliance with the H2S and SO2 limits for Crude/Vac 2. Additional discussion of the proposed monitoring approach for heater H2S and SO2 is discussed in detail in the section on Boiler/Heaters (which addresses H2S and SO2 monitoring at the RFG mix drums). The VOC emission standard for P010 is non-numeric – the standard is simply to combust the overhead gases in a suitable combustion device. Since there are no performance specifications required of the combustion device to which gases are routed, the combustion device, in this case, is considered inherent process equipment. Therefore, no VOC CAM plan is required for the control device. Additionally, the routing of overhead gases from Crude/Vac 2 to the RFG system cannot be bypassed, nor can the H2S/SO2 controls (i.e. amine treaters). Therefore, no bypass monitoring is necessary for Crude/Vac 2.

2.6 TANKS Except for the Foul Condensate tanks (T164, Tank 295; and T170, Tank 294), the only regulated pollutant from the tanks is VOC. While many of the tanks employ internal or external floating roofs to limit emissions, these design features are considered “inherent process equipment” and not “control devices.” Therefore, with the exception of the Foul Condensate tanks all of the tanks are exempt from CAM because they do not employ a control device, though some also have insignificant emissions. Further, almost all tanks are also subject to 40 CFR Part 63 Subpart CC, a CAM exempt emission standard. The Foul Condensate tanks are regulated for both VOC and SO2; however, uncontrolled PTE for both pollutants is less than 100 tpy. Therefore, the Foul Condensate tanks are not subject to CAM.

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2.7 FUGITIVE SOURCES AND LOADING OPERATIONS The non-insignificant fugitive emission units, including the plant roadways (F001), coke handling (F005) and coke crusher (F006) all have uncontrolled PTE of less than 100 tpy of particulate matter, the only regulated pollutant for these emission units. Therefore, the fugitive emission units are not subject to CAM. The aviation gas loading (J001), marine loading (J002), asphalt loading (J005) and special fuels loading (J006) do not employ control devices for VOC, the only regulated pollutant for these emission units. Therefore, the loading operations emission units are not subject to CAM.

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Attachment A CAM Applicability Summary

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Attachment B CAM Plans

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Plan #1: Boilers & Heaters/SO2 CAM Plan

Plan #2: FCC/CO Boiler PM CAM Plan Plan #3: FCC/CO Boiler NOX CAM Plan Plan #4: Crude/Vac 1 VOC CAM Plan

BP-Husky Plan #1: Boilers & Heaters/SO2 CAM Plan

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Section 1. Monitoring Approach for SO2 Emission Abatement Systems for the Boilers and Heaters

I. Background/Summary Source Information A. Emission Unit/Sources

Description: Boilers and Heaters Identification:

Emission Source Title V ID Hydrogen Furnace B001 Reformer 2 Regen. Furnace B005 Reformer 2 Furnace B006 Iso 2 Feed Heater B008 Iso 2 Stabilizer Reboiler B009 Iso 2 Splitter Reboiler B010 Reformer 1 Regenerator Furnace B013 Reformer 1 Furnace B014 Crude 1 Furnace B015 Coker 2 Heater B017 FCC Preheat B018 Crude Vac 2 Furnace B019 Naphtha Treater Heater B022 Asphalt Heater (T108, T109) B024 External Asphalt Heater B025 ADHT Furnace B029 BGOT Furnace B030 Vac 1 Furnace B031 Coker 3 Furnace B032 BGOT East Furnace B033 East Alstom Boiler B034 West Alstom Boiler B035 Reformer 3 Furnace (not yet permitted) B0XX

B. Applicable Regulation, Emission Limit, and Monitoring Requirements

Permit ID

Applicable Regulation

Permit Condition Emission Limit

Monitoring Requirement

B001

OAC 3745-18-54(W)(1)

A.I.1

Not specified – limit is less stringent than H2S limit

specified by OAC 3745-31-02(A)(2)

None

B005 B006 B008 B009 OAC 3745-18-54(W)(5) B010 B014

OAC 3745-18-54(W)(1) B015 B017 B018 OAC 3745-18-54(W)(5) B019 OAC 3745-18-54(W)(1) B022 OAC 3745-18-54(W)(1)


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Permit ID

Applicable Regulation

Permit Condition Emission Limit

Monitoring Requirement

B029

OAC 3745-18-54(W)(1) A.I.1

2.53 tons of SO2 per year per OAC 3745-31-05(A)(3)

None – compliance with H2S limit is

deemed compliance with the SO2 limit.

B030 6.39 tons of SO2 per year per OAC 3745-31-05(A)(3)

B031 2.8 pounds of SO2 per hour per OAC 3745-31-05(A)(3)

B032 20.46 tons of SO2 per year per OAC 3745-31-05(A)(3)

B033 0.88 pounds per hour and 3.86 tons per year of SO2 per OAC

3745-31-05(A)(3)

B034 7.80 pounds per hour and

22.00 tons per year of SO2 per OAC 3745-31-05(A)(3)

B035 7.80 pounds per hour and

22.00 tons per year of SO2 per OAC 3745-31-05(A)(3)

B0XX Not yet permitted. C. Control Technology

Each emission source listed above uses refinery fuel gas that has been processed by one of several amine treaters that remove H2S, which converts to SO2 in the combustion process, from the fuel gas. Fuel gas H2S concentration is monitored at each fuel gas mix drum (i.e. post amine treatment) and prior to use in any of the boilers or heaters.

II. Monitoring Approach

The key elements of the monitoring approach are presented in the following table. The selected amine treater unit performance indicator is H2S concentration in the fuel gas. The performance indicator will be directly monitored via a continuous emission monitor meeting the 40 CFR Part 60 Appendix B performance specifications. The control device for these sources cannot be bypassed (40 CFR Part 64.3(a)(2) and 64.4(a)(2)); therefore, no bypass monitoring is necessary and none is proposed.


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SO2 Abatement System (Amine Treater) Monitoring Approach

Indicator No. 1

I. Indicator 40 CFR 64.3(a)(1)-(2), 40

CFR 64.4(a)(1)

H2S concentration in the fuel gas

Measurement Approach

Continuous emission monitor

II. Indicator Range 40 CFR 64.3(a)(3), 40 CFR

64.4(a)(2)

Maximum concentration of 0.10 gr H2S/dscf (3-hour average)

III. Performance Criteria 40 CFR 64.3(b), 40 CFR

64.4(a)(3)

A. Data Representativeness

The CEM will meet the 40 CFR Part 60 Appendix B Performance Specification 7– “Specifications and Test Procedures for Hydrogen Sulfide Continuous Emission Monitoring Systems in Stationary Sources”

B. Verification of Operation Status

CEM certification as per 40 CFR 60 Appendix B Perform. Spec. 7.

C. QA/QC Practices and Criteria

Daily zero/span calibration checks and certification as per 40 CFR 60 Appendix B Perform. Spec. 7.

D. Monitoring Frequency

Complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period except as allowed for calibrations, audits, malfunctions, etc.

Data Collection Procedures

A CEM will be located at each RFG mix drum and at the exit of the Crude/Vac 1 Amine Contactor such that representative measurements of H2S concentration are obtained.

Averaging period 40 CFR 64.3(d)

The H2S standard is proposed as a 3-hour average.


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III. Monitoring Approach Justification (§64.4(b)) A. Background/Emission Unit Description

The boilers and heaters at the BP-Husky Refinery are predominantly fired with refinery fuel gas (RFG) which contains trace amounts of H2S that converts to SO2 in the combustion process. H2S in the RFG originates from sulfur the crude oil processed by the refinery. As the crude oil is processed by various refinery units, off-gas similar to natural gas is produced that can be used to fire the refinery’s boilers and heaters. However, the off-gas has relatively high levels of H2S that must be removed prior to use at the boilers in order to comply with applicable SO2 emission limits. Therefore, prior to entering the RFG system via one of several mix drums, the off-gas gas is processed by one of several amine treaters. H2S in the off-gas gas is readily absorbed by liquid amine, which is circulated through the treater in a manner to promote contact with the gas stream. Spent amine is regenerated (i.e. H2S is removed from the amine) and re-used in the treaters while the H2S is routed to a sulfur recovery unit. In order to determine the H2S concentration at the boilers and heaters, and to minimize the number of CEMs as much as possible, RFG is routed through mix drums prior to distribution to individual heaters and boilers. H2S concentration is measured at each mix drum.

B. Rationale for Selection of Performance Indicators

Limiting H2S in the RFG effectively limits SO2 emissions. Therefore, the performance indicator selected for the amine treaters is H2S concentration in the fuel gas prior to combustion. The concentration will be measured directly and continuously via a CEM meeting the 40 CFR Part 60 performance specifications. Further, the concentration will be maintained at or below the concentration specified in 40 CFR Part 60 Subpart J, 0.10 gr H2S/dscf, which is more stringent than the applicable OEPA SO2 emission limitation specified in the Title V permit. Historic H2S monitoring data, which has been submitted to the agency previously as part of the refinery’s compliance certification reports, indicates that H2S concentrations have generally been well below this limit. This proposed monitoring approach is “presumptively acceptable” (40 CFR Part 64.4(b)(4)) since continuous monitoring of H2S concentration is specified in the current Title V permit as the compliance monitoring approach for the applicable SO2 regulations, 40 CFR Part 60 Subpart J and Ohio SIP regulations 3745-18-54(W) and 3745-31-05.

C. Rationale for Selection of Indicator Ranges

Not applicable. A range is not proposed. Rather, the current ceiling value for H2S concentration specified in 40 CFR Part 60 Subpart J is proposed since it is a currently applicable emission limit and is more stringent than the applicable Ohio SIP SO2 emission limitations.

BP-Husky Plan #2: FCC/CO Boiler PM CAM Plan

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Section 1. Monitoring Approach for PM Emission Abatement System for the FCC/CO Boiler


Description: FCC/CO Boiler Identification: P007


Regulation: Voluntary limit from a Consent Decree incorporated in Ohio EPA PTI 04-01330 (issued Aug. 28, 2003) as allowed per OAC 3745-31-02(F) Voluntary limits on allowable emissions and incorporated in the facility’s Title V Permit. OAC/ORC 3745-17-10 and -17-11

Current Permit Condition: Existing Title V Permit: Part III, P007, A.I.1 and A.I.2d Emission Limit: 1 pound particulate per 1000 pounds coke burned

(Consent Decree) 0.02 lb/MMBtu heat input to boiler (3745-17-10) 91.7 lb PM/hr (3745-17-11)

Monitoring Requirement: Stack test, if required (Title V, Part III, P007, A.V.1f) (Opacity is currently monitored for compliance with OAC/ORC rule 3745-17-07(A), but not for the PM limits.)

C. Control Technology

The emission source listed above uses an electrostatic precipitator to remove particulate matter from the exhaust stream of the FCC/CO Boiler.


The key elements of the monitoring approach are presented in the following table. The selected electrostatic precipitator unit performance indicator is opacity. The performance indicator will be directly monitored via a continuous opacity monitor meeting the requirements of 40 CFR Part 51, Appendix P, and 40 CFR Part 60 Appendix B Performance Specification 1. Additionally, it is important to note that during startup, shutdowns and some malfunctions situations, the FCCU regenerator overhead gases may bypass the CO Boiler and ESP and instead be routed directly to a bypass stack. BP-Husky monitors the temperature in the bypass stack as an indicator to detect any bypass of the CO Boiler and ESP control device. A bypass would only occur during periods of startup, shutdown or malfunction. The permit condition does not explicitly state whether or not this 1 lb/1000 lb coke burn emission limitation is applicable during periods of startup, shutdown or malfunction. However, it is BP-Husky’s interpretation that it does not apply in these instances for the following reasons.

�1. The permit condition states that the facility will achieve compliance with this limit

“through the installation of an electrostatic precipitator”. It was clearly not anticipated at the time this consent decree requirement was negotiated that BP-Husky would have to install two ESP’s, one on the CO boiler and one on the bypass stack.


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2. This permit condition is similar to FCCU particulate limits in NSPS and 40 CFR Part 63 Subpart UUU, both of which contain SSM exemptions. That fact was known to all parties at the time that this emissions limit was negotiated. Had U.S. EPA desired for it to apply more broadly than other similar limits, U.S. EPA would have been explicit about it. (Note: the SSM exemption of Part 63 is being legally challenged. Nevertheless, this exemption was in effect at the time that this similar, non-Part 63 emission limit was negotiated.)

PM Abatement System (Electrostatic Precipitator) Monitoring Approach

Indicator No. 1

I. Indicator 40 CFR 64.3(a)(1)-(2), 40

CFR 64.4(a)(1)

Opacity


Continuous Opacity Monitor System (COMS)


64.4(a)(2)

Maximum opacity of 10% (one hour average)


64.4(a)(3)

E. Data Representativeness

The COM will meet the 40 CFR Part 60 Appendix B Performance Specification 1 – “Specifications and Test Procedures for Continuous Opacity Monitoring Systems in Stationary Sources”

F. Verification of Operation Status

COM certification as per 40 CFR 60 Appendix B Perform. Spec. 1.

G. QA/QC Practices and Criteria


H. Monitoring Frequency

40 CFR 51 Appendix P: (Complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 10-second period except as allowed for calibrations, audits, malfunctions, etc.


COM will be located in stack on the outlet of the CO Boiler/ESP such that representative measurements of opacity are obtained.


The Opacity standard is proposed as 10% opacity for a one hour average.


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III. Monitoring Approach Justification (§64.4(b))

A. Background/Emission Unit Description

The Fluid Catalytic Cracking (FCC) Unit uses a fluidized bed of fine catalyst that circulates through the unit and promotes hydrocarbon cracking reactions. During the cracking reactions, carbon is deposited on the catalyst which makes it less active. The catalyst is circulated to a regenerator unit where air is introduced to the hot catalyst to burn off the carbon deposits. The exhaust from the regenerator passes through a number of cyclones prior to exiting the top of the regenerator. It is then routed to a CO boiler to use the hot exhaust to make steam and to assure complete combustion of any residual carbon monoxide (CO). The exhaust of the CO boiler then goes through an electrostatic precipitator for final particulate control and is then discharged to the atmosphere. The CO Boiler/ESP stack contains numerous emissions monitors including a continuous opacity monitor. Note: During FCCU startups and shutdowns and some malfunctions (such as a steam tube leak in the CO boiler) the FCCU regenerator exhaust can bypass the CO boiler/ESP and be directly discharged to the atmosphere through the FCCU bypass stack. A CAM plan is required to demonstrate compliance with the particulate emissions limit of 1 lb per 1000 lb coke burn for the FCCU/CO Boiler (P007) which was originally negotiated as part of a 2001 Consent Decree (Civil No. 2:96 CV 095 RL) and which has subsequently been incorporated in Ohio EPA PTI 04-01330 and the facility’s Title V permit. This emission limit is more stringent than the OAC 3745-17-10 and -17-11 limits. Compliance with this emissions limit required BP-Husky’s agreement to install and operate an Electrostatic Precipitator (ESP) on this source. The ESP was installed during the 2007 Fall turn-around. Past stack testing during normal operation with the ESP in operation show emissions ranging from 0.03 to 0.299 lbs particulate per 1000 pounds of coke burn, which is well under the emissions limitation. This equates to annual emissions of about 20 tons/yr of particulate. (Note: uncontrolled emissions upstream of the electrostatic precipitator are approximately 2.0 lb PM/ 1000 lb coke burn, which is over the 100 ton/yr CAM applicability threshold).


Opacity is proposed as the performance indicator to assure proper operation of the electrostatic precipitator which provides compliance with the particulate limit in question. Opacity is widely accepted as a good surrogate parameter for particulate emissions. Besides opacity, another possible consideration would be monitoring the voltage and current use of the ESP. However, these would be a less direct indication of particulate emissions. 10% opacity is one of the options allowed by 40 CFR Part 63 Subpart UUU for compliance demonstration of a similar PM limit as discussed below.


BP-Husky proposes the use of 10% opacity as a one-hour average as the maximum allowable opacity to indicate compliance with the particulate emissions limit.


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The existing Title V permit (Part III, P007, A.V.1f) specifies the compliance demonstration methodology for this PM limit to be “If required, the procedures specified under 40 CFR 63.1571 and under the conditions specified in Table 4 of 40 CFR Part 63, Subpart UUU shall be used to demonstrate compliance.” This citation refers to the stack testing methodology for initial compliance demonstration for 40 CFR Part 63 Subpart UUU. Although this permit limit is not from the Subpart UUU, it is numerically equivalent to one of the compliance options in the that standard (40 CRR 63.1564 Option 2 provides for compliance with a PM emissions limit of 1 lb PM per 1000 lb coke burn). In addition to an initial compliance demonstration stack test, the Subpart UUU standard also specifies ongoing monitoring options such as a surrogate confirmation of the proper operation of the control device (ESP) and ongoing PM compliance. One such option is to maintain opacity at or below 10% opacity for a one hour average. (Note: Subpart UUU allows use of an opacity limit higher than 10% if a stack test demonstrates that a higher number is still in compliance with the PM limit. Opacity cannot be exactly correlated to particulate emissions - but it is a very good indicator of proper operation of the control system.) To summarize, BP-Husky proposes that CAM for this emissions limit be the use of opacity monitoring, with a maximum allowable opacity of 10% as a one hour average for the following reasons:

• Opacity is the parameter most commonly used for monitoring proper operation and effectiveness of an ESP control device. It is used for compliance assurance with particulate requirements in numerous NSPS, MACT and other standards.

• The proposed limit of 10% opacity is consistent with the Subpart UUU limit

allowed in Option 2 which is used in that regulation to demonstrate ongoing compliance with a similar particulate limit of 1 lb PM per 1000 lbs of coke burn.

• Opacity analyzers are typically ranged to read up to 80% opacity. Readings

below 10% opacity can be subject to significant error, making a lower standard difficult to monitor accurately and prone to erroneous indication of deviations.

• It is important to note that although 40 CFR Part 63 Subpart UUU applies to this

emissions unit, Option 2 for particulate monitoring is not the selected compliance monitoring option used by BP-Husky to demonstrate compliance with Subpart UUU due in part to the fact that compliance with Subpart UUU was required before the ESP was installed. For the purposes of Subpart UUU, BP-Husky is using Option 4 which calculates compliance with a nickel limit (pounds of nickel emissions per 1000 lbs of coke burn). Subpart UUU does not regulate PM, but Option 2 described previously allows for a simplified use of PM and opacity as surrogate measures to ensure metallic HAP/nickel compliance. BP-Husky uses the more rigorous nickel monitoring Option 4 for Subpart UUU compliance demonstration. However, for the Title V/Consent Decree PM limit, Option 4 is not appropriate. Therefore, for this PM limit, monitoring similar to Subpart UUU Option 2 is proposed.

BP-Husky Plan #3: FCC/CO Boiler NOX CAM Plan

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Section 1. Monitoring Approach for NOX Emission Abatement System for the FCC/CO Boiler


Description: FCC/CO Boiler dentification: P007


Regulation: 2001 Consent Decree (Civil No. 2:96 CV 095 RL) Current Permit Condition: Not addressed in current Title V permit. Emission Limit: NOX emissions limit of 97 ppmvd (at 0% O2) on a 365-day

average and 199 ppmvd (at 0% O2) on a 7-day average Monitoring Requirement: None currently


The emission source listed above uses a selective non-catalytic reduction (SNCR) system to remove nitrogen oxides from the exhaust stream of the FCC/CO Boiler.


The key elements of the monitoring approach are presented in the following table. The selected SNCR unit performance indicator is NOX concentration. The performance indicator will be directly monitored via a continuous emission monitor meeting the 40 CFR Part 60 Appendix B performance specifications. Additionally, it is important to note that during startup, shutdowns and some malfunctions situations, the FCCU regenerator overhead gases may bypass the CO Boiler and ESP and instead be routed directly to a bypass stack. BP-Husky monitors the temperature in the bypass stack as an indicator to detect any bypass of the ESP control device. The permit condition does not explicitly state whether or not this NOX emission limitation is applicable during periods of startup, shutdown or malfunction. However, it is BP-Husky’s interpretation that it does not apply in these instances.


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NOX Abatement System (SNCR) Monitoring Approach

Indicator No. 1

I. Indicator 40 CFR 64.3(a)(1)-(2), 40

CFR 64.4(a)(1)

NOX concentration in the exhaust stream


Continuous emission monitor


64.4(a)(2)

Maximum concentration of NOX of 97 ppmvd (at 0% O2) on a 365-day average and 199 ppmvd (at 0% O2) on a 7-day average


64.4(a)(3)

I. Data Representativeness

The CEM will meet the 40 CFR Part 60 Appendix B Performance Specification 2 – “Specifications and Test Procedures for SO2 and NOX

Continuous Emission Monitoring Systems in Stationary Sources”

J. Verification of Operation Status

CEM certification as per 40 CFR 60 Appendix B Perform. Spec. 2.

K. QA/QC Practices and Criteria


L. Monitoring Frequency

Complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period except as allowed for calibrations, audits, malfunctions, etc.


The sampling for the CEM will be located in stack on the outlet of the CO Boiler/ESP such that representative measurements of NOX concentration are obtained.


The NOX standards are proposed as 365-day and 7-day averages.


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III. Monitoring Approach Justification (§64.4(b)) A. Background/Emission Unit Description

Catalyst used by the Fluid Catalytic Cracking (FCC) Unit promotes hydrocarbon cracking reactions. During the cracking reactions, carbon is deposited on the catalyst which makes it less active. The catalyst is circulated to a regenerator unit where air is introduced to the hot catalyst to burn off the carbon deposits. The carbon combustion in the regenerator creates some NOX emissions. The exhaust from the regenerator is routed to a CO Boiler for steam production and to assure complete combustion of any CO in the FCC exhaust. Some supplemental refinery fuel gas is burned in the CO boiler, which can add additional NOX emissions. Emissions of NOX are reduced by the use of a Selective Non-Catalytic Reduction (SNCR) system. In this system, urea is injected into the CO boiler at a location where the temperature and residence time promotes a chemical reaction converting some of the NOX to nitrogen (N2). The CO Boiler/ESP stack contains numerous emissions monitors including a continuous NOX emissions monitor. This CAM plan is provided to demonstrate compliance with a NOX emissions limit of 97 ppmvd (at 0% O2) on a 365-day average and 199 ppmvd (at 0% O2) on a 7-day average for the FCCU/CO Boiler (P007). These limits originate from a 2001 Consent Decree (Civil No. 2:96 CV 095 RL). The Consent Decree required BP-Husky to install an SNCR system on the CO Boiler and to conduct a demonstration of that SNCR. At the end of the demonstration, BP-Husky was required to submit a report of the results of the demonstration to USEPA and to propose NOX limits. The Consent Decree required BP-Husky to comply with their proposed limits as interim limits until USEPA set the final limits. The above limits were proposed by BP-Husky in March 2007. When final NOX emission limits are established by USEPA, they will supersede the above limits. Note: During FCCU startups and shutdowns and some malfunctions (such as a steam tube leak in the CO boiler) the FCCU regenerator exhaust can bypass the CO Boiler/ESP and be directly discharged to the atmosphere through the FCCU bypass stack. The above interim limits are not applicable during such bypasses or during FCCU feed hydrotreater outages.


This proposed monitoring approach is “presumptively acceptable” (40 CFR Part 64.4(b)(2)) since it proposes to use a continuous emission monitor for NOX concentration as the compliance monitoring approach for the applicable NOX emission limitation.


Not applicable. A range is not proposed. Rather, the current ceiling value for NOX concentration specified in the currently applicable emission limitation is proposed.

BP-Husky Plan #4: Crude/Vac 1 VOC CAM Plan

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Section 1. Monitoring Approach for VOC Emission Abatement System for the Crude/Vac Unit 1


Description: Crude/Vac 1 Identification: P011


Regulation: OAC 3745-21-09(M)(1) Current Permit Condition: Part III A.I.2.a and Part II A.4.b Emission Limit: Emission shall be routed to the Crude 1 Furnace (B015) Monitoring Requirement: None


The emission source listed above routes process vent gases to a Crude 1 Furnace, where VOC emissions are abated through combustion, which is considered to be “inherent process equipment” as defined in 40 CFR Part 64.1. However, since the process vent gases can bypass this “control device,” monitoring of the bypass is proposed.


The VOC “control device” for this emission source is “inherent process equipment” and therefore does not require any monitoring. However, the “control device” for this source can be bypassed (40 CFR Part 64.3(a)(2) and 64.4(a)(2)); therefore, bypass monitoring is necessary and is proposed. Bypass of the normal routing of process vent gases can only occur by manually opening the bypass valve. Consequently, BP-Husky is always aware of a bypass event. A requirement to document the time when each bypass begins and ends is already required by the current Title V and is in BP-Husky’s current procedures. This requirement is proposed to meet the bypass monitoring requirements of Part 64.

Documents

CAM Applicability Analysis and CAM Plansweb.epa.state.oh.us/dapc/transfer/BPHUSKY/P0104782/A0037896/264112[1].pdfCAM applicability is evaluated on a pollutant-specific emission unit