### From: Shine, Brenda < Shine.Brenda@epa.gov > To: Higgins, Cortney Cc: Lassiter, Penny; Johnson, Ann; Tierney, Jan Sent: Wednesday, April 10, 2013 8:43 AM Subject: RE: RIN 2060-0146 Interagency comments under EO 13563

Hi Cortney, Welcome back. Attached are our responses to the interagency comments. Also attached are the 2 docket items that were requested by the reviewers. Let me know if you have any other questions or comments. Brenda (919) 541-3608

<< EO_12866_Refinery_MACT_2060-0146_Interagencycomments and EPA response.docx >> << EPA-HQ-OAR-2003-0146-0229.pdf >> << EPA-HQ-OAR-2003-0146-0230.pdf >>

From: Higgins, Cortney < Cortney_Higgins@omb.eop.gov > To: Shine, Brenda Cc: Lassiter, Penny; Johnson, Ann Sent: Wednesday, March 20, 2013 11:27 AM Subject: RE: RIN 2060-0146 Interagency comments under EO 13563

Thanks Brenda!

### From: Shine, Brenda < Shine.Brenda@epa.gov > To: Higgins, Cortney Cc: Lassiter, Penny; Johnson, Ann Sent: Wednesday, March 20, 2013 10:31 AM Subject: RE: RIN 2060-0146 Interagency comments under EO 13563

Hi Cortney, I’ve had a chance to look through the comments and don’t see any comments that we cant address either through edits to the language or with additional explanation in the margins. I think we can make these edits and have it ready for your review when you come back.

From: Higgins, Cortney < Cortney_Higgins@omb.eop.gov > To: Brenda Shine/RTP/USEPA/US@EPA Cc: Penny Lassiter/RTP/USEPA/US@EPA Sent: Tuesday, March 19, 2013 7:06 PM Subject: RIN 2060-0146 Interagency comments under EO 13563

Hi Brenda, Attached is a redline of the preamble with edits/comments from the interagency reviewers. Please let me know if you have any questions. I’m going to be on vacation from 3/21 (Thursday) through 4/8. Can you let me know tomorrow if you think you’ll need to have a call or talk with someone about the rule before I get back? If not, we can just plan to follow up on your edits/changes to the document after I return. Thanks, Cortney 202.395.7856***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** EO 12866_Refinery MACT 2060-0146 FinalAmendments_20120125

6560-50-P

**ENVIRONMENTAL PROTECTION AGENCY**

**40 CFR Part 63 [EPA-HQ-OAR-2003-0146; FRL- ]** 

**RIN 2060-AP84 National Emission Standards for Hazardous Air Pollutants From**  **Petroleum Refineries**

**AGENCY:** Environmental Protection Agency (EPA).

**ACTION:** Final rule.

**SUMMARY:** This action amends the national emission standards for hazardous air pollutants for heat exchange systems at petroleum refineries located at 40 CFR part 63, subpart CC. The amendments address issues raised in a petition for reconsideration of the EPA’s final rule setting maximum achievable control technology rules for these systems and also provides additional clarity and regulatory flexibility with regard to that rule. This action does not change the level of environmental protection provided under those standards. The final amendments do not add any new cost burdens to the refining industry and may result in cost savings by establishing an additional monitoring option that sources may use in lieu of the monitoring provided in the original standard. Comment [A1]: As a general comment – i t is difficult to follow what was in the prior rule, what you reproposed, and what you are finalizing. I think this can be fixed with a careful read through and checking of tenses. Comment [BBC2]: Yes there are several changes in this version that were made to address this concern.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 2 of 87

**DATES:** The final amendments are effective on **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . The incorporation by reference of certain publications listed in the final rule amendments is approved by the Director of the Federal Register

as of **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**

. **ADDRESSES:** The EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2003-0146. All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the EPA Docket Center, National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries, EPA West Building, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3 of 87

**FOR FURTHER INFORMATION CONTACT:** Ms. Brenda Shine, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, Refining and Chemicals Group (E143-01), Environmental Protection Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-3608; fax number: (919) 541-0246; email address: shine.brenda@epa.gov.

**SUPPLEMENTARY INFORMATION:** The information in this preamble is organized as follows: I. General Information A. Does this action apply to me? B. Where can I get a copy of this document? C. Judicial Review II. Background Information A. Executive Summary B. Background of the Refinery NESHAP III. Summary of the Final Amendments to NESHAP for Petroleum Refineries and Changes Since Proposal IV. Summary of Comments and Responses A. Uniform Standards for Heat Exchange Systems B. Refinery MACT 1 Requirements for Heat Exchange Systems V. Summary of Impacts VI. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions to Address***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 4 of 87 Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act **I. General Information** A. Does this action apply to me? The regulated category and entities potentially affected by this final action include: Category NAICS 1 Code Examples of Regulated Entities Industry . . . 324110 Petroleum refineries located at a major source that are subject to 40 CFR part 63, subpart CC. 1 North American Industry Classification System. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this final rule. To determine whether your facility is regulated by this action, you should carefully examine the applicability criteria in 40 CFR 63.640 of subpart CC (National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries). If you have any questions regarding the applicability of this action to a particular entity, contact the person listed in the preceding **FOR FURTHER INFORMATION CONTACT** section. B. Where can I get a copy of this document? In addition to being available in the docket, an electronic copy of this final action is available on the Worldwide Web***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 5 of 87 (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN’s policy and guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg/. The TTN provides information and technology exchange in various areas of air pollution control. The EPA has created a redline document comparing the existing regulatory text of 40 CFR part 63, subpart CC and the final amendments to aid the public’s ability to understand the changes to the regulatory text. This document has been placed in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2003- 0146). C. Judicial Review Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of this final rule is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by **[INSERT DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  . Under section 307(d)(7)(B) of the CAA, the requirements established by these final rules may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 6 of 87 Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for us to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW, Washington, DC 20460, with a copy to both the person(s) listed in the preceding **FOR**

**FURTHER INFORMATION CONTACT** section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW, Washington, DC 20460. **II. Background Information** A. Executive Summary 1. Purpose of the Regulatory Action***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 7 of 87 This action finalizes amendments that were proposed on January 6, 2012, to address reconsideration issues related to the maximum achievable control technology standards (MACT) for heat exchange systems we promulgated on October 28, 2009. This action also finalizes additional amendments intended to clarify rule provisions and to provide additional flexibility. 2. Summary of Major Provisions We are finalizing three significant revisions to the standards for heat exchange systems that were promulgated on October 28, 2009. First, we are revising the regulations to include an alternative monitoring option for heat exchange systems that would allow owners and operators at existing sources to monitor quarterly using a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 parts per million by volume (ppmv); the current regulations (40 CFR 63.654) provide only one monitoring option, which requires monitoring monthly at a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 6.2 ppmv. We performed modeling of the monitoring alternative and the modeling indicates that quarterly monitoring at the lower leak action level provides equivalent emission reductions to monthly monitoring at the higher leak action level in the existing regulations. These Comment [A3]: Will this modeling be included in the docket? Comment [BBC4]: This modeling approach is alreadyin the docket as items EPAHQ-OAR-2003-0146-0229 (the general technology review) and -0230 (as applied to refineries). These items wer e placed in the docket in support of the January 2012 proposal and will be sent to OMB.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 8 of 87 amendments also include specific recordkeeping and reporting requirements for owners and operators electing to use the alternative monitoring frequency. The second significant amendment is the revision to the definition of heat exchange system to improve clarity regarding applicability of the monitoring and repair provisions for individual heat exchangers within the heat exchange system. The third significant revision is an amendment to the monitoring requirements for once-through cooling systems to allow monitoring at an aggregated location for once-through cooling water heat exchange systems, provided that the combined cooling water flow rate at the monitoring location does not exceed 40,000 gallons per minute.These final amendments do not include the proposed crossreferencing of the Uniform Standards for Heat Exchange Systems (40 CFR part 65, subpart L). These final amendments also do not include the use of direct water sampling methods that were proposed as alternatives to using the “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” (Modified El Paso Method), Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003 (incorporated by reference— see §63.14) within the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 9 of 87 Uniform Standards for Heat Exchange Systems. The EPA concluded that the alternative as proposed was not feasible for petroleum refineries and that alternatives suggested during the comment period were not equivalent. 3. Costs and Benefits The actions we are taking will have no cost, environmental, energy or economic impacts beyond those impacts presented in the October 2009 final rule for heat exchange systems at petroleum refineries and may result in a cost savings for refiners who select the proposed alternative monitoring frequency. For sources that choose the quarterly monitoring alternative, the cost is projected to be less than the cost of the monthly monitoring requirement in the October 2009 final rule, while achieving the same environmental impacts. Similarly, sources that choose to monitor at an aggregated location, for the small number of refineries that operate once-through systems, will have reduced monitoring costs. The clarifications and other changes we are proposing in response to reconsideration are

cost-neutral. B. Background of the Refinery NESHAP Section 112 of the CAA establishes a regulatory process to address emissions of hazardous air pollutants (HAP) from stationary sources. After the EPA has identified categories of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 10 of 87 sources emitting one or more of the HAP listed in section 112(b) of the CAA, section 112(d) calls for us to promulgate national emission standards for hazardous air pollutants (NESHAP) for those sources. For “major sources” that emit or have the potential to emit any single HAP at a rate of 10 tons or more per year or any combination of HAP at a rate of 25 tons or more per year, these technology-based standards must reflect the maximum reductions of HAP achievable (after considering cost, energy requirements and nonair quality health and environmental impacts) and are commonly referred to as MACT standards. For MACT standards, the statute specifies certain minimum stringency requirements, which are referred to as floor requirements. See CAA section 112(d)(3). Specifically, for new sources, the MACT floor cannot be less stringent than theemission control that is achieved in practice by the bestcontrolled similar source. The MACT standards for existing sources can be less stringent than standards for new sources, but they cannot be less stringent than the average emission limitation achieved by the best-performing 12 percent ofexisting sources in the category or subcategory (or the bestperforming five sources for categories or subcategories with fewer than 30 sources). In developing MACT, we must also consider control options that are more stringent than the floor.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 11 of 87 We may establish standards more stringent than the floor based on the consideration of the cost of achieving the emissions reductions, any nonair quality health and environmental impacts and energy requirements. We published the first set of MACT standards for petroleum refineries (40 CFR part 63, subpart CC) on August 18, 1995 (60 FR 43620). These standards are commonly referred to as the “Refinery MACT 1” standards because certain process vents were excluded from this source category and subsequently regulated under a second MACT standard specific to these petroleum refinery process vents (40 CFR part 63, subpart UUU, referred to as “Refinery MACT 2”). We issued an initial proposed rule to include requirements for heat exchange systems for the petroleum refineries subject to the Refinery MACT 1 on September 4, 2007, and held a public hearing in Houston, Texas, on November 27, 2007. In response to public comments on the initial proposal, we collected additional information and revised our analysis of the MACT floor. Based on the results of these additional analyses, we issued a supplemental proposal on November 10, 2008, that proposed a new MACT floor for heat exchange systems. A public hearing for the supplemental proposal was held in Research Triangle Park, North Carolina, on November 25, 2008. We took final action to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 12 of 87 establish standards for heat exchange systems in the Refinery MACT 1 standards (40 CFR part 63, subpart CC) on October 28,

2009. On December 23, 2009, the American Petroleum Institute (API) requested an administrative reconsideration under CAA section 307(d)(7)(B) of certain provisions of 40 CFR part 63, subpart CC that they had identified in an April 7, 2009, letter to the EPA. On January 6, 2012, we issued a proposed rule addressing the issues in the reconsideration petition and proposed amendments to 40 CFR part 63, subpart CC. As part of the January 6, 2012, proposal, we also proposed Uniform Standards for Heat Exchange Systems (40 CFR part 65, subpart L), which included the same substantive provisions for heat exchange systems that were in the October 2009 Refinery MACT 1 final standards (40 CFR part 63, subpart CC). We proposed to remove from the Refinery MACT 1 standards most of the substantiveprovisions addressing heat exchange systems and to crossreference the Uniform Standards from Refinery MACT 1. **III. Summary of Final Amendments to NESHAP for Petroleum Refineries and Changes Since Proposal**  As described in section II.B. of this preamble, we proposed, on January 6, 2012, Uniform Standards for Heat Exchange Systems as 40 CFR part 65, subpart L and amendments to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 13 of 87 Refinery MACT 1 (40 CFR part 63, subpart CC). We are not finalizing the Uniform Standards for Heat Exchange Systems at this time because we are still evaluating comments received on the March 26, 2012 proposed Uniform Standards for storage vessels, equipment leaks and closed vent system and control devices (see (77 FR 17898). We believe it is appropriate to consider all the comments received on the Uniform Standards proposed rules together, particularly since some of the comments received on the March 26, 2012 proposal relate to the overall concept and implementation of Uniform Standards across multiple industry categories. We are retaining in Refinery MACT 1 the substantive requirements for heat exchange systems. However, we are revising Refinery MACT 1 to incorporate many of the substantive changes in the work practice standards for heat exchange systems at petroleum refineries included in the Uniform Standards as part of the January 6, 2012, proposal. First, we are amending the definition of “heat exchange system” based on the proposed clarification of the definition and the public comments received. As proposed, we are replacing “series of devices” with “collection of devices.” In response to comments, we also are amending the definition of “heat exchange system” to improve clarity regarding the applicability of the monitoring and repair requirements for individual heat Deleted: are still considering the many comments we received on the proposed changes to the standards

. proposal

. Comment [A5]: Suggested addition – can EPA add some text to explain why they are not finalizing the stnadards? Comment [BBC6]: Ok. See revised language.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 14 of 87 exchangers within the heat exchange system. Specifically, we are revising the definition of “heat exchange system” to focus on heat exchangers (and not sample coolers) that are in organic HAP service and that are associated with a petroleum refinery process unit. Therefore, we are finalizing the definition of “heat exchange system” to mean a device or collection of devices used to transfer heat from process fluids to water without intentional direct contact of the process fluid with the water (i.e., non-contact heat exchanger) and to transport and/or cool the water in a closed-loop recirculation system (cooling tower system) or a once-through system (e.g., river or pond water). For closed-loop recirculation systems, the heat exchange system consists of a cooling tower, all petroleum refinery process unit heat exchangers that are in organic HAP service (as defined in this subpart) serviced by that cooling tower, and all water lines to and from these petroleum refinery process unit heat exchangers. For once-through systems, the heat exchange system consists of all heat exchangers that are in organic HAP service (as defined in this subpart) servicing an individual petroleum refinery process unit and all water lines to and from these heat exchangers. Sample coolers or pump seal coolers are not considered heat exchangers for the purpose of this definition and are not part of the heat exchange system. Intentional direct***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 15 of 87 contact with process fluids results in the formation of a

wastewater. In the January 2012 proposal, we included clarifications of the sampling requirements and leak action level for once-through heat exchange systems when determining strippable hydrocarbon concentrations for the inlet water stream. We are finalizing these clarifications as proposed. After considering public comments, we are also revising the sampling requirement for once-through systems to allow monitoring at an aggregated location for once-through heat exchange systems, provided that the combined cooling water flow rate at the monitoring location does not exceed 40,000 gallons per minute. In the January 2012 proposal, we also proposed a direct water sampling and analysis option as an alternative to using the “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” (Modified El Paso Method), Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003 (incorporated by reference— see §63.14), as well as amendments to the recordkeeping and reporting requirements when this alternative is elected. After considering public comments, we are not revising Refinery MACT 1 to include this alternative.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 16 of 87 In the January 2012 proposal, we included an alternative monitoring frequency for heat exchange systems at existing sources. This monitoring frequency is quarterly using a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv; the only monitoring frequency in existing Refinery MACT 1 is monthly at a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 6.2 ppmv. We are revising Refinery MACT 1 to include the alternative monitoring frequency, as proposed. We proposed a clarification that the water flow rate could be determined based on direct measurement, pump curves, heat balance calculations or other engineering methods. We are finalizing this clarification as proposed. We also proposed clarifications to the applicability dates for heat exchange systems at new sources. We are finalizing these clarifications as proposed. The proposed Uniform Standards at 40 CFR 65.610(b) contained three exemptions: one based on pressure differential, one based on not being “in regulated material service,” and one based on size (targeted to exclude sample coolers). As previously noted, we are not finalizing the Uniform Standards or the cross-references to those Uniform Standards from Refinery***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 17 of 87 MACT 1. The corresponding section in Refinery MACT 1 ( 40 CFR

63.654 , Subpart CC) that we are finalizing in today’s action contains only two exemptions: one based on pressure differential and one for intervening fluid. The exemptions for “in HAP service” and small heat exchangers are not needed based on the revised definition of “heat exchange system.” These heat exchangers are not part of the affected heat exchange system as that term is defined in these final amendments. We are finalizing several technical and clarifying corrections in response to issues identified by public commenters. One of these amendments is in response to a commenter’s request for clarity on how delay of repair emissions are to be calculated and for confirmation that the emissions should be estimated for the period of time that the delay of repair occurred. The October 2009 standards required the calculation of emissions projected for the “expected duration of delay” using the monitored leak concentration. As the heat exchange system for which repair is delayed must be monitored monthly, we interpret the rule to require a monthly estimate of the emissions projected for the duration of the delay of repair. However, the reporting requirement is an estimate of the emissions that occur as a result of delayed repairs over the reporting period. As such, the owner or operator must actually Deleted: Comment [A7]: Can you add a parenthetical like (Subpart ###) or (current regulations), something to give a little more context.

Deleted:

Deleted: to clarify how delay of repair emissions are to be calculated. Comment [A8]: Is the method described below an approach that was provided by public commenters? Comment [BBC9]: No the commenter asked for confirmation that the emissions should be estimated for the period of time that the delay of repair occurred because the proposed language was unclear. We agreed with the commenter and clarified the language. See revised text here.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 18 of 87 calculate the emissions projected over each monitoring intervaland sum these estimates for the period covered by the semiannual report. Therefore, in order to better align the calculation, recordkeeping and reporting requirements, we have revised the requirement to develop a monthly emission estimate for “the duration of the expected delay of repair” to require calculation of emissions projected for “each monitoring interval.” We also revised the recordkeeping requirements to keep records of these “monitoring interval” emission estimates, which can be directly used to develop the emission estimates required in the semi-annual reports. We are also clarifying that the delay begins on the date the leak would have had to be repaired had the repair not been delayed. We are revising the recordkeeping requirement for the “identification of all heat exchangers at the facility” to instead require records for “identification of all petroleum refinery process unit heat exchangers at the facility” commensurate with our revision of the definition of “heat exchange system” and our desire to focus the Refinery MACT 1 heat exchange system requirements on heat exchangers associated with petroleum refinery process units. Finally, we are specifying that records related to the heat exchanger provisions be retained for 5 years, consistent with retention requirements for other emissions sources.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 19 of 87 Today’s final rule also addresses 10 reconsideration issues raised by the API. The API requested an administrative reconsideration under CAA section 307(d)(7)(B) of certain provisions of 40 CFR part 63, subpart CC that they had identified in an April 7, 2009, letter to the EPA. As described in detail in the January 6, 2012, proposal (see 77 FR 964), we denied API’s request for six of the reconsideration issues either because they were irrelevant after the subsequent withdrawal of the amendments to the Refinery MACT 1 storage vessel requirements or because the issues could have been raised during the public comment period. We granted reconsideration on the following issues: (1) the use of the promulgation date to describe the applicability for new sources in 40 CFR 63.640(h)(1); (2) the definition of “heat exchange system” in 40 CFR 63.641 as it relates to once-through heat exchange systems and refinery process units; (3) the monitoring procedures for once-through heat exchange systems in 40 CFR 63.654(c); and (4) the determination of the cooling water flow rate in 40 CFR 63.654(g). This final action reflects our reconsideration of issues raised in API’s request for reconsideration. **IV. Summary of Comments and Responses** A. Uniform Standards for Heat Exchange Systems***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 20 of 87 On January 6, 2012, we proposed Uniform Standards for Heat Exchange Systems (40 CFR part 65, subpart L). We also proposed to remove most of the substantive requirements for heat exchange systems from Refinery MACT 1, to include them in the Uniform Standards, and to cross-reference the Uniform Standards from Refinery MACT 1. We received numerous comments on the creation of Uniform Standards for Heat Exchange Systems and the proposed cross-referencing to the Uniform Standards within Refinery MACT 1 (40 CFR part 63, subpart CC). We are not taking final action to create Uniform Standards for Heat Exchange Systems at this time. We will address the comments that focused on the creation of the Uniform Standards in the context of future Uniform Standards regulatory actions. Section IV.B of this preamble addresses the comments regarding the substance of requirements that we proposed to include in the Uniform Standards but that we are now finalizing as part of Refinery MACT 1, or requirements proposed in the Uniform Standards that we have decided not to finalize as they would apply to heat exchange systems at refineries. B. Refinery MACT 1 Requirements for Heat Exchange Systems 1. Definition of Heat Exchange System Deleted: consider

Deleted: rulemaking packages, as appropriate. Comment [A10]: What does this mean? How will the commenters know how/when their comments will be addressed? Comment [BBC11]: We do not have a schedule for completion of these uniform standards at this time, nor a final implementation plan for what source categories we would propose to reference these standards. We can only say that we will consider comments received in the context of future US actions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 21 of 87

Comment : One commenter supported the proposed change to the definition of “heat exchange system” that clarifies that heat exchangers need not be piped in series. Response : We appreciate support of this clarification.

Comment : One commenter stated that including the cooling tower in the definition of “heat exchange system” means there can be only one heat exchange system per cooling tower, and this unduly complicates the rule (because the rule has to discuss requirements for individual exchangers and groups of exchangers as well as the heat exchange system). The commenter also suggested that the definition be limited to heat exchangers that serve petroleum refining process units to clarify that heat exchangers outside of the affected source are not subject to the Refinery MACT 1 requirements, which would be clearer than relying on the affected source description in 40 CFR 63.640 to limit applicability. Another commenter stated that monitoring provisions in 40 CFR 63.654(a) should focus on heat exchangers that service refinery process units because there is no legalbasis for applying the rule to heat exchangers that service nonrefinery processes even if they share a cooling tower. Response : We disagree that including the cooling tower in the definition of heat exchange system creates confusion. Even if the cooling tower were not part of the heat exchange system, Comment [A12]: How does a facility monitor or show compliance if they have more than one heat exchange system per cooling tower? Is this a hypothetical or is EPA aware of such facilities? Comment [BBC13]: The definition of heat exchange system means there can be only one heat exchange system per cooling tower. The comment refers to how we describe the heat exchangers that are associated with a cooling tower and whether we include the cooling tower in the definition of heat exchange system. Commenters wanted to make sure they could monitor not only at the cooling tower return, but heat exchangers upstream of the return if it allowed them to exclude some heat exchangers that are not in HAP service or are not refinery heat exchangers. The proposed rule allowed this, but in the final rule, we attempted to further clarify that they do, indeed, have the ability to do that.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 22 of 87 the regulatory language would still have to discuss heat exchangers, groups of heat exchangers and heat exchange systems to allow both centralized and separate monitoring of heat exchangers (or groups of heat exchangers). The flexibility provided in the monitoring locations, not the inclusion of the cooling tower, appears to be the primary source of complexity in the rule. As we allow monitoring of the cooling water at the cooling tower, it is logical that the cooling tower be part of the heat exchange system. Furthermore, the cooling tower is a central and essential part of a closed-loop heat exchange system for the system to operate properly. It is easily identifiable for permitting and enforcement personnel and it is the location at which most refineries are expected to perform the required monitoring. The cooling tower is also the location at which the strippable hydrocarbons are emitted. With respect to limiting the definition to heat exchangers that serve petroleum refining process units, we find that this comment has merit. Because Refinery MACT 1 is a NESHAP, in this final action, we intentionally limited repairs to heat exchangers that are “in organic HAP service.” The rule as finalized in 2009 also limited applicability by defining as part

of the affected source “all heat exchange systems associated with refinery process units and which are in organic HAP Deleted: We

Deleted: the

Deleted: rule to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 23 of 87 service ” in 40 CFR 63.640(c)(8). While we expect most heat exchange systems at petroleum refineries to process cooling water from heat exchangers associated only with refinery process units, we recognize that there may be other process units at a refinery, particularly ethylene units and units subject to the National Emission Standards for Organic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry (40 CFR part 63, subpart F) (“HON”). We generally prefer not to include applicability criteria in emission source definitions , but recognizing the complexity of the current construct, we considered whether revising the definition of heat exchange system might increase the clarity of the monitoring and repair requirements for specific heat exchangers within the heat exchange system. Specifically, we considered defining a closed-loop heat exchange system as “a cooling tower, all petroleum refinery process unit heat exchangers serviced by that cooling tower that are in organic HAP service, as defined in this subpart, and all water lines to and from these petroleum refinery process unit heat exchangers.” The qualifications in this definition provide clarity that the repair requirements in 40 CFR 63.654 apply only to refinery process unit heat exchangers that are in organic HAP service; other heat exchangers that might be serviced by a common cooling Comment [A14]: Is this a change in response to the comment or what you had at proposal? If the former, suggest adding to the beginning “After consider the comment, we amended the applicability ..” Comment [BBC15]: This was already part of the 2009 final rule but it still apparently wasn’t that clear in the latest proposal, so we revised definitions to eliminate confusion, as described below.

Deleted: Generally, we do

Deleted: into Deleted: (e.g., defining Group 1 and Group 2 sources), Comment [A16]: What does EPA mean? If not necessary suggest deleting.

Deleted: evaluated the inclusion of certain applicability requirements within Deleted: systems to see if a revised definition could provide better Deleted: regarding***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 24 of 87 tower are not part of the “heat exchange system.” A similar revision for once-through systems would be “all heat exchangers that are in organic HAP service, as defined in this subpart, servicing an individual petroleum refinery process unit and all water lines to and from these heat exchangers.” Considering the broad definition of “petroleum refinery process unit” and the existing exclusions in 40 CFR 63.640(g), we are finalizing these revisions to the definition of heat exchange system because we believe that these revisions clarify the intent of the requirements within Refinery MACT 1 as finalized in October 2009 and limit the applicability of the repair requirements to individual heat exchangers servicing refinery process units.

Comment : Two commenters suggested that all sample coolers and pump seal coolers should be specifically exempted from the monitoring requirements and/or that the threshold in 40 CFR 65.610(b)(3) should be raised from 10 gallons per minute to 50 gallons per minute. The commenters stated that it was burdensome to have to evaluate the flow rate for every sample cooler at the refinery in order to assess the monitoring applicability and that sample coolers were not considered in the EPA analysis of heat exchange systems. Response : In the January 2012 proposal, we included an exemption for very small heat exchange systems (those with water Deleted: descriptions because we believe that these amendments***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 25 of 87 flow rates less than 10 gallons per minute). This exemption was specifically targeted to exempt sample coolers and pump seal

coolers because we did not consider these coolers significant sources of emissions and did not include them in our MACT floor and impacts analysis for the October 2009 final rule. We considered providing a higher flow exclusion to individual heat exchangers, but this would still require the refinery owners and operators to identify and assess the flow rates of each sample cooler. After reviewing the options, we have concluded that adding language to specifically exclude sample coolers and pump seal coolers from the definition of heat exchange system provides the clearest means to ensure that the regulations do not unintentionally capture these “coolers” that were not considered part of a “heat exchange system” in our original analysis and that we did not intend to be monitored under the Refinery MACT 1 regulations. See the new regulatory definition

at 40 CFR 63.641 for heat exchange system.

Comment : One commenter suggested that the EPA define the term “strippable hydrocarbons” to mean the hydrocarbons measured by any of the methods specified in 40 CFR 65.610(a)(3). Response : We considered providing a specific definition of “strippable hydrocarbons” in these final amendments, but the suggested definition is unnecessary since we are not finalizing Deleted: , Deleted: were not considered

Comment [A17]: Was there any other reason to exempt them that would be better here or add to the discussion? This reads like you would have regulated them except that you didn’t include them in the analysis.

Deleted: excluding

Deleted: exclude

Deleted: had never intended

Comment [A18]: e.g. use this above Deleted:

.

Deleted: ### Comment [A19]: Suggest adding a cross reference.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 26 of 87 the use of water methods as an alternative monitoring method for petroleum refineries. The monitoring method required by the regulations, the Modified El Paso Method, provides the best definition of strippable hydrocarbons as it relates to potential emissions from heat exchange systems. 2. Applicability and Exemptions

Comment : One commenter supported the proposed revisions clarifying the construction date criteria for defining a new source for the purpose of the heat exchange provisions. Response : We appreciate support of this clarification.

Comment : One commenter recommended deleting the provision that limits once-through heat exchange systems to a single process unit because the MACT floor analysis does not support this approach. Although the process unit restriction is currently in 40 CFR 63.641, the commenter noted that this language was not in the September 4, 2007, proposal or the November 10, 2008, supplemental proposal and, therefore, has not been subject to public comment until now. The commenter stated that, if the process unit restriction is maintained, the EPA should limit the rule to monitoring systems with a flow greater than 5,000 gallons per minute because the EPA’s analysis shows control for smaller systems is not cost effective. The commenter***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 27 of 87 also suggested that the EPA’s analysis did not consider monitoring once-through systems individually. Response : Although the original MACT floor and impacts analysis (see the technical memorandum titled, “Cooling Towers:Control Alternatives and Impact Estimates,” Docket Item No. EPAHQ-OAR-2003-0146-0143) referred to “cooling towers” rather than “heat exchange systems,” we believe the analysis adequately considered all heat exchange systems at all petroleum refineries. We projected the nationwide total number of “cooling towers” to be 520 using information from the Texas Commission on Environmental Quality (TCEQ) for 50 petroleum refineries and extrapolating (considering capacity) to all U.S. petroleum refineries. Based on this analysis, every refinery was projected to have several “cooling towers” or “heat exchange systems” in our MACT floor and impacts analysis, and we assumed that refineries with once-through cooling systems would have a similar number of heat exchange systems (per refining capacity) as refineries with closed-loop (cooling tower) systems. We conducted analyses to determine how the number of cooling towers or heat exchange systems would affect our MACT floor calculations if there were more than our estimated 520. Becausethe monitoring and repair requirements for many of the bestperforming heat exchange systems were identical, we determined***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 28 of 87 that the MACT floor requirements for existing sources would be the same even if there were as many as 666 affected “cooling towers” or “heat exchange systems” (see the technical memorandum titled, “Revised Impacts for Heat Exchange Systems at Petroleum Refineries,” Docket Item No. EPA-HQ-OAR-2003-0146-0230). To further verify our MACT floor calculations, we reviewed the information collected during the detailed information collection request (ICR) for petroleum refineries (see Docket Item Nos. EPA-HQ-OAR-2010-0682-0061 through 0069). The definition for heat exchange system in the ICR was identical to the definition in Refinery MACT 1 (with once-though systems limited to individual process units). Based on the ICR responses, there are 525 heat exchange systems that are in organic HAP service and that do not qualify for the exemption from monitoring based on higher water-side pressures; only 21 of these 525 are once-through heat exchange systems. We note that there are 50 additional closed-loop heat exchange systems for which respondents did not answer these “applicability” questions, so we project that the total number of affected heat exchange systems is somewhat more than 525 but less than 575. Therefore, our estimate of 520 affected heat exchange systems (including once-through systems) was reasonably accurate, and the existing source MACT floor monitoring requirements would not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 29 of 87 be impacted had we used the upper range estimate from the ICR data. As such, we disagree that our MACT floor analysis is inconsistent with the restriction of once-through systems to a single process unit. With respect to the suggestion that we limit the monitoring of closed-loop heat exchange systems to only those with flows of 5,000 gallons per minute or more, we note that closed-loop heat exchange systems that have flow rates less than 5,000 gallons per minute are common at refineries . These smaller heat exchange systems were included in our MACT floor and impacts analysis, and we did not subcategorize these heat exchange systems by size. The assertion that monitoring these smaller heat exchange systems is not cost effective is not relevant; we do not consider costs in developing the MACT floor requirements. We only consider costs when evaluating alternatives beyond the MACT floor. As described previously, we believe we adequately considered the total number of affected heat exchange systems (including once-through and small heat exchange systems) when establishing the MACT floor requirements for existing sources. We noted in the January 2012 proposal that: “A once-through heat exchange system could include all heat exchangers at the entire facility. The potential to aggregate all cooling water at a facility (as opposed to a single process unit) prior to Deleted: there are a reasonablesignificant n umber of Comment [A20]: What does this mean? Can we go with “majority” or just provide the number?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 30 of 87 sampling for a once-through system would greatly reduce the effectiveness of the leak monitoring methods and would allow HAP or VOC leaks to remain undetected, based solely on the dilution effect from the vast quantity of water processed at the facility.” (See 77 FR 967). We specifically requested comment on how we might allow some aggregation across units but not allow dilution across all units at the plant. The commenter did not provide any suggestions on this point, but rather suggested that if aggregation were not allowed, once-through heat exchange systems with flow less than 5,000 gallons per minute should be

excluded. For closed-loop heat exchange systems, there are physical limitations on the cooling tower that limit the number of units that can be serviced by the cooling tower. Again, our analysis suggested there would be several heat exchange systems perrefinery compared to a single heat exchange system for oncethrough systems. On the other hand, we recognize that the definition of “heat exchange system” in the October 2009 final rule limits aggregation for refineries operating once-through systems more than refineries that operate closed-loop systems. Therefore, we evaluated several ways to afford some aggregation for once-through heat exchange systems so that these systems would be more comparable to the “cooling tower” heat exchange***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 31 of 87 systems identified in the MACT floor memorandum (Docket Item No. EPA-HQ-OAR-2003-0146-0143). We identified no appropriate way to allow some, but constrained, aggregation across process units within the definition of heat exchange system. Therefore, we are not modifying the definition of “heat exchange system” as it relates to once-through systems (i.e., a once-through heat exchange system is still limited to the heat exchangers associated with a single refinery process unit). As an alternative, we evaluated allowing monitoring for once-through cooling systems at locations that include cooling water from several heat exchange systems. Based on the responses from the detailed ICR, approximately 90 percent of all cooling towers (i.e., closed-loop heat exchange systems) at petroleum refineries have flow rates of 40,000 gallons per minute or less. As such, we consider that this 90th percentile value provides a reasonable proxy of the upper level of aggregation provided to facilities with closed-loop heat exchange systems. By allowing once-through heat exchange systems to monitor at locations that include cooling water from several heat exchange systems, provided that the combined cooling water flow rate at the monitoring location does not exceed 40,000 gallons per minute, we are providing a means to aggregate across process units in a manner similar to that afforded to closed-loop heat exchange***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 32 of 87 systems, which is the assumption made in our MACT floor and impacts analyses. As this level of aggregation is similar to that for closed-loop heat exchange systems, we expect that this provision will achieve the same emission reductions at the same costs as projected for our model closed-loop heat exchange systems. We also note that this approach is preferable to the suggested exemption for all once-through heat exchange systems below 5,000 gallons per minute because it achieves greater emission reductions at similar costs. Therefore, we have amended the monitoring location for once-through heat exchange systems to allow monitoring at a point where discharges from multiple heat exchange systems are combined, provided that the combined cooling water flow rate at the monitoring location does not exceed 40,000 gallons per minute.

Comment : Several commenters stated that the EPA should retain the exemption for heat exchange systems that have an intervening cooling fluid that contains less than 5 percent by weight of HAP. Response : This exemption was included in the October 2009 final standards for refinery heat exchange systems and it was our intent to retain this existing exemption for petroleum refineries. However, when the heat exchange system Uniform Standards were proposed, we inadvertently omitted a cross-***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 33 of 87 reference to this exemption from Refinery MACT 1. As noted previously, we are not promulgating the Uniform Standards or the cross-references to the Uniform Standards from Refinery MACT 1. The provision to exempt heat exchange systems that use an intervening fluid that is less than 5 percent by weight HAP is retained as a part of Refinery MACT 1.

Comment : One commenter suggested that the introductory paragraph in 40 CFR 65.610(b) should specify that engineering judgment may be used to determine whether any of the exemption criteria are met. Response : As noted in section III of this preamble, heat exchangers may be excluded from a “heat exchange system” based on differential pressure or the presence and content of an intervening fluid. We did not specify that engineering judgment can be used for the differential pressure exemption, either in the October 2009 final rule or the January 2012 proposed amendments. We expect that direct pressure measurements of the process fluids and cooling water lines will be made in a representative location at which the pressure exclusion can be documented. With respect to the intervening fluid exemption, we intended that the same requirements used to determine “in organic HAP service” would apply to the intervening fluid. We revised the description of this exemption to specify that the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 34 of 87 provisions of 40 CFR 63.180(d) of subpart H should be used; 40 CFR 63.180(d) allows the use of “good engineering judgment” under most circumstances. 3. Compliance Date

Comment : One commenter suggested that the compliance date be reset to be at least 1 year after the promulgation date of the final amendments to provide time for the refineries to develop procedures for complying with the proposed options and any other changes made in response to public comments. Response : Petroleum refinery owners and operators have been on notice of the October 29, 2012, compliance date since promulgation of the heat exchange standards in October 2009. Refinery owners and operators that follow the requirements in the October 2009 final rule will be in compliance with these final amendments. If a facility elects to change to quarterly monitoring at the lower leak definition, there are provisions in the final amendments for how this change can be made. Therefore, there is no need to reset the compliance date. 4. Monitoring Locations and Analytical Methods

Comment : Several commenters requested that a leak be determined based on the difference between inlet and outlet concentrations. One commenter specifically noted that the EPA should reconsider this approach, which is used in the Hazardous***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 35 of 87 Organic NESHAP (“HON”; 40 CFR part 63 subpart F), for refinery heat exchange systems. The commenter disputed the EPA claims that accumulating hydrocarbons in the cooling water are evidence of a leak and that small leaks are cost effective to repair, stating the build-up of organic chemicals can be caused by the use of chemical additives for corrosion or biological growth prevention and these heavy compounds are not stripped in the cooling tower as completely as they are in the Modified El Paso Method stripping column. Response : The rule does not provide for the use of inlet and outlet sampling for closed-loop heat exchange systems because the MACT floor requirements for heat exchange systems were based on existing monitoring of the cooling water return line only. If the rule allowed the use of a concentration differential, it would be less stringent than the MACT floor because the MACT floor monitoring was not based on a differential concentration, but the direct concentration in the cooling water return line. Although we expect that the strippable hydrocarbons measured by the Modified El Paso Method will be largely removed (i.e., released to the air) in the cooling tower so that the cooling water inlet to the heat exchangers will have limited concentrations of strippable hydrocarbons, it is unlikely that this concentration would be Comment [A21]: Please explain why it would be less stringent? It’s different, yes, but it’s not clear why a differential concentration is inherently less stringent. Comment [BBC22]: Because when you take the difference between the cooling water supply (after the cooling tower) and the cooling water return (prior to the cooling tower), you are subtracting two concentration values; unless the cooling water supply concentration is zero, the differential approach produces a concentration that has been adjusted to account for hydrocarbons still in the water after the cooling tower and is lower and less likely to trigger the leak definition.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 36 of 87 exactly zero. Therefore, using a concentration differential produces a concentration that has been adjusted to account for hydrocarbons still in the water after the cooling tower and is lower and less likely to trigger the leak definition. We did not allow this option for closed–loop heat exchangers. The rule doesprovide for the use of inlet and outlet sampling for oncethrough heat exchange systems. While we have taken the position that once-through heat exchange systems have a similar emission potential as closed-loop systems, we acknowledge that these systems are different in operation and that contaminants may be present in the pond, river or other source of once-through cooling water that is beyond the control of the refinery owner or operator and that will not be “pre-stripped” in a cooling tower. Therefore, we conclude that it is reasonable and necessary to allow a concentration differential to be used to determine a leak for once-through heat exchange systems.

Comment : One commenter noted that the requirements in 40 CFR 65.610(e) are unnecessarily burdensome because they require a source to monitor all heat exchangers to find a leak and they appear to require continued monthly testing of all heat exchangers even if the leak is not from an exchanger that is subject to the repair requirements. This commenter also recommended simply requiring the leaking exchanger to be Deleted: for closed–loop heat exchangers is not provided.

Deleted: concluded Comment [A23]: Conclude?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 37 of 87 identified by the most expeditious process and then requiring repair only if the leaking exchanger is in service associated with a referencing subpart. Response : The cited provisions do not require monitoring of all affected heat exchangers to find a leak. The refinery owner or operator can use any method they choose to identify the leaking heat exchanger. If the identified leaking heat exchanger is not in HAP service, then the refinery owner or operator has two options: (1) fix the leak and continue to monitor in the main cooling tower return line or (2) demonstrate that all heat exchangers within the heat exchange system that are subject to the monitoring and repair provisions are not leaking by monitoring each heat exchanger or group of heat exchangers subject to the repair provisions. Thus, the option of monitoring each heat exchanger or group of heat exchangers is not required to identify the leaking heat exchanger; rather, this monitoring option is provided only for the case in which the refinery owner or operator elects not to fix a leak that was identified through monitoring of the cooling tower return line on the grounds that the leaking heat exchanger is not subject to the repair provisions in Refinery MACT 1.

Comment : One commenter suggested that the monitoring frequency/leak definition alternatives for existing sources***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 38 of 87 should be allowed on an individual or group of heat exchangers basis as well as on a heat exchange system basis. Response : The rule allows monitoring at the individual heat exchanger (or group of heat exchangers) level or at the heat exchange system level (i.e., monitoring at the cooling tower). However, in order to allow this flexibility for either aggregate or individual monitoring to be performed without any notification to the EPA, all heat exchangers that are part of a heat exchange system must use the same monitoring frequency and leak definition. We considered allowing the suggested alternative for individual heat exchangers within a heat exchange system, but concluded that it would likely result in uncertainty regarding what compliance monitoring, reporting and recordkeeping requirements would be required for individual heat exchangers. As the affected facility is the heat exchange system, we consider it appropriate that the same monitoring frequency and leak definition be used for all monitoring locations within one heat exchange system. The final rule clearly allows (in 40 CFR 63.654(c)(4)) the owner or operator of existing sources to use the alternative quarterly monitoring option for some heat exchange systems and the monthly monitoring option for others but all heat exchangers or groups of heat***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 39 of 87 exchangers within a single heat exchange system must use the same monitoring frequency and leak definition.

Comment : Two commenters noted that section 5.1.1.4 of the Modified El Paso Method specifies that samples must be drawn from a location prior to the risers. The commenter requested clarification that monitoring may instead be conducted either prior to the risers or in any individual riser because the concentration of hydrocarbons is distributed equally to each riser and the system has no openings to the atmosphere prior to discharge into the cooling tower cells. They also noted that refineries often monitor in a riser and changes needed to enable monitoring prior to the riser would require a significant capital expenditure. Response : The final amendments describe monitoring locations specific for Refinery MACT 1 and then separately describes the allowed monitoring methods. Reference to the Modified El Paso Method is confined to the monitoring method section of Refinery MACT 1, and the Modified El Paso Method’s restriction on sampling in the riser is not applicable. Nonetheless, we have provided specific clarifications in the monitoring location section that monitoring in the cooling tower riser (prior to exposure to the atmosphere) is allowed.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 40 of 87

Comment : One commenter stated that, in addition to a flame ionization detector, the EPA should allow use of other detectors, such as a photo ionization detector or mass spectrometry and online gas chromatograph (GC) capable of equivalent sensitivity for target compounds when using the Modified El Paso Method. Response : We specifically require the stripping gas concentration to be determined in ppmv as methane. While a refinery owner or operator may elect to use a GC and other analyzers to speciate the compounds present in the cooling water in order to identify the specific heat exchangers or group of heat exchangers responsible for the leak, the leak itself must be determined using a flame ionization detector calibrated with methane following the procedures in section 6.1 of the Modified El Paso Method. As discussed in further detail in the following comment and response, we find that speciated analysis of target compounds in the stripping gas is likely to result in incomplete characterization of the total hydrocarbon concentration and could be less stringent than the MACT floor determined for petroleum refinery heat exchange systems. We have further clarified this requirement in these final amendments by specifically referencing section 6.1 of the Modified El Paso Method. However, this requirement does not preclude the refinery Comment [A24]: Did they provide any reasons for making this request? Comment [BBC25]: The commenter did not specifically state why they were asking this question. Comment [A26]: Inline? If online, please explain what this is? Comment [BBC27]: Online means continuously monitoring the cooling water stream—it is not a grab sample.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 41 of 87 owner or operator from conducting additional analysis of the stripping gas as a means to identify the leaking heat exchanger.

Comment : Several commenters requested that the rule allow additional measurement methods in order to characterize the compounds that could leak into the cooling water. The measurement methods suggested include EPA Method 624 of Appendix A to 40 CFR part 136 and SW-846 Methods 8270 and 8315. Commenters also stated that characterizing all volatile compounds (or even all volatile organic HAP) is often impossible due to the high number of compounds that may be in a process stream, and it is not necessary, as detection of key compounds from the process is all that is needed to identify a leak. One commenter suggested that this rule should be like the TCEQ’s rule that requires characterization of compounds with boiling points less than 140 degrees Fahrenheit (°F). This commenter recommended allowing any measurement method that is sensitive to at least 90 percent of the species with boiling points less than 140 °F, and allowing subtraction of compounds with boiling points greater than 140 °F from the “total strippable hydrocarbon” concentration. Several commenters recommended including a general procedure for monitoring surrogate species or indicator species rather than requiring full speciation. For example, one commenter requested that the rule allow the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 42 of 87 analysis to focus on one compound that the method easily detects and then estimate the total strippable hydrocarbon concentration assuming the ratio of that compound to all organic compounds in the cooling water is the same as in the process fluid. Response : We acknowledge the difficulty characterizing all compounds in a petroleum refinery process stream. While we considered including additional test methods, the inclusion of additional test methods did not appear to address the primary issue regarding the ability to fully characterize the compounds that could leak into the cooling water. We disagree that the characterization of compounds should be limited to compounds with boiling points less than 140 °F. Hexane, benzene and toluene all have boiling points above 140 °F; these compounds are expected to be emitted from heat exchange systems and are expected to be detectable using the Modified El Paso Method. The Modified El Paso Method was designed to have high (99 percent or higher) recovery of compounds with boiling points below 140 °F and avoids potential losses of highly volatile compounds associated with direct water sampling methods. For this reason, while the Modified El Paso Method is required to be used by the TCEQ for cooling tower sampling when pollutants have boiling points below 140 °F, it is incorrect to conclude that the Comment [A28]: Isn’t EPA concerned about HAP being emitted? Comment [BBC29]: Yes, but there are numerous HAPs in the cooling water, and they are not all accounted for using the available methods. Additionally, the MACT Floor leak definition is based on the El Paso method strippable hydrocarbons in ppmv as methane.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 43 of 87 Modified El Paso Method will not measure any compounds with boiling points greater than 140 °F. Since the data used to establish the MACT floor were based on the Modified El Paso Method, in order to be at least as stringent as the MACT floor, any alternative monitoring option provided in the rule must be as effective as the El Paso Method in detecting the HAP that are indicative of a leak. Limiting the direct water method analysis only to compounds with boiling points less than 140 °F would be less stringent than the Modified El Paso Method and thus we disagree with the commenter that direct water methods should be provided as an option. In the proposed Heat Exchanger Uniform Standards, we proposed to allow the use of a water method that would identify all leaked compounds as an alternative monitoring method. Our intent was for this approach to be used where a heat exchanger cooled a process fluid that contained a very limited number of compounds. We expected that very few, if any, petroleum refinery heat exchange systems would choose to use the water methods for most heat exchangers, given the requirement to fully characterize all compounds that could leak into the cooling

water. The proposed water methods were expected to be at least as stringent as the Modified El Paso Method because the requirement***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 44 of 87 to fully characterize the pollutants that could leak into the wastewater would include all compounds, even those that may not be effectively stripped in the stripping column (or cooling tower). Options to limit the full characterization requirement call into question the ability of the water methods to be as stringent as the total strippable hydrocarbon analysis using the Modified El Paso Method. In light of the complexity of most petroleum refinery process streams, we are concerned that there may be a leak that exceeds 40 parts per billion by weight (ppbw) total strippablehydrocarbons in the water-phase as determined by backcalculation from the Modified El Paso Method results, but because of the number of different compounds present in the petroleum refinery stream (often on the order of 50 to 100 different compounds), the concentrations of the individual compounds could all be below the analytical detection limit (typically about 5 to 10 ppbw in the cooling water). In such a case, the water methods, even with low detection limits, may not provide a suitable alternative to the Modified El Paso Method for refinery heat exchange systems. To further evaluate our concerns regarding the use of water measurement methods for refinery heat exchange systems, we reviewed the source test data received in response to the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 45 of 87 cooling water testing required as part of the detailed information collection request for petroleum refineries. We compared the stripping column gas sampling results with those from the direct water methods (see the memorandum titled, “Evaluation of the Refinery ICR Cooling Water Analysis Results” in Docket ID No. EPA-HQ-OAR-2003-0146). We found that the analytical methods for chemical species (in both stripping gas analysis and water samples) greatly underestimated the overall concentrations of hydrocarbons, primarily because these analyses were conducted using a specific target analyte list. As the water methods (or gas-phase speciated analysis methods) generally include a specific list of target analytes, we now expect that these methods could lead to less effective leak identification. We considered the alternative of monitoring a specific compound and extrapolating that compound concentration to determine a total strippable hydrocarbon concentration, but we determined that this approach generally would be more complicated and burdensome than direct Modified El Paso monitoring, given the complexity of petroleum refinery process fluids and the likelihood that several different heat exchangers (with process fluids of differing compositions) may be serviced by a single cooling tower (i.e., heat exchange system). We see***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 46 of 87 no easy way to specify “a general procedure for monitoring surrogate species or indicator species” while ensuring equivalency with the Modified El Paso Method. One would need to use the Modified El Paso Method to develop the extrapolation factor for each process fluid that could potentially leak into the cooling water and to verify that the method used provides adequate detection limits. This would be difficult to do and complex, considering the potential variation in compounds and concentrations across process streams. Given the complexity of most petroleum refinery process streams, we were unable to identify from the currently available water methods a method that would be suitable for determining the total strippable hydrocarbon concentration with the accuracy and sensitivity needed to be comparable to the Modified El Paso Method. Therefore, we are not finalizing any alternative water methods for monitoring petroleum refinery heat exchange systems.

Comment : Several commenters requested that the rule allow measurement of surrogates. One commenter requested inclusion of the full spectrum of monitoring methods currently listed in the HON, the National Emission Standards For Ethylene Manufacturing Process Units: Heat Exchange Systems And Waste Operations (40 CFR part 63, subpart XX) (“Ethylene NESHAP”), and the online monitoring for ethylene and propylene that is allowed in TCEQ***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 47 of 87 HRVOC Rule (TAC Title 30 Part I Chapter 115 Div. 2 §115.764). One commenter noted that the proposed methods would require most facilities to use offsite test resources, but other methods, particularly if surrogates can be measured, would allow sites to conduct analyses themselves and respond more quickly to any

leaks. Response : We disagree with the comments suggesting all measurement methods provided in the HON, the Ethylene NESHAP or the TCEQ rules should be allowed. The leak definition for petroleum refineries is lower than specified in those rules. In our revised impacts analysis for the proposed amendments(see the technical memorandum titled, “Revised Impacts for Heat ExchangeSystems at Petroleum Refineries,” Docket Item No. EPA-HQ-OAR2003-0146-0230), the leak detection level was generally the most important parameter influencing the effectiveness of the heat exchange system monitoring program. We evaluated a series of “surrogate” methods when evaluating different heat exchange system monitoring alternatives for the October 2009 final rule and concluded that these surrogate methods were not as effective as identifying leaks as the Modified El Paso Method. We acknowledge that the proposed water method alternatives would often require the use of external laboratories; however, as discussed previously, we are not finalizing the proposed Comment [A30]: Please add clarification as suggested and amend if incorrect Comment [BBC31]: Ok as suggested Comment [A32]: Please provide to us. Comment [BBC33]: Yes, we will provide this item as well as docket item -299***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 48 of 87 water method alternatives. The Modified El Paso Method, on the other hand, is performed on-site. The method is relatively simple and can be operated by refinery personnel or outside contractors to provide immediate leak monitoring results, so it has the same advantages of the “surrogate” methods while also being able to detect small leaks.

Comment : One commenter requested that sources be allowed up to 7 calendar days for re-monitoring a heat exchange system to verify repair when a repaired heat exchanger is returned to service either after the end of the 45-day normal repair window (as long as the heat exchanger was taken out of service before the end of that 45-day window) or after an allowed delay of repair period. The commenter noted that if the heat exchanger is taken out of service as the means of repair and then brought back into service after the 45-day window, then additional time is needed to start up, line-out, and retest that heat exchanger. Response : In the January 2012 proposal, we proposed to clarify that under the existing MACT standard, “repair” includes verification that the actions taken to repair the leak were effective through re-monitoring of the heat exchange system. We consider the 45-day repair window for a typical repair as well as the additional time provided for a delayed repair to be adequate considering the time necessary to re-monitor the heat***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 49 of 87 exchange system. We expect that repairs will be made as expeditiously as possible and that the actions will be taken with sufficient time to confirm the repairs within the 45-day repair window. Refinery MACT 1 specifically allows the use of removing a heat exchanger from service as a means to effect repair in 40 CFR 63.654(d)(5). The heat exchange system would need to be re-monitored within the 45-day window to verify that the removal of the heat exchanger effectively reduced the total hydrocarbons in the cooling water to below the leak threshold levels. In this case, the removal of the heat exchanger from service would accomplish the repair and the owner or operator could revert back to their chosen monitoring frequency. The rule is silent on a special monitoring event for the case in which the removed heat exchanger is subsequently placed back into service. This case is similar to the case where a new heat exchanger (or group of heat exchangers) is added to an existing heat exchange system. We interpret the rule to require only the routine heat exchange system monitoring with no special monitoring event required when adding these “new” heat exchangers to the heat exchange system. We anticipate that any “new” or “repaired” heat exchanger would be properly pressure tested prior to being placed in service. As such, these heat exchangers would be unlikely to leak, so the routine monitoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 50 of 87 frequency is considered sufficient. We also note that, if an owner or operator removes a heat exchanger from service as a means to effect a repair, but then returns the same heat exchanger to service without any modification or repair, that owner or operator could be subject to potential enforcement actions for not complying with the operating and maintenance requirement “...to maintain any affected source...in a manner consistent with safety and good air pollution control practices for minimizing emissions” as required in the General Provisions at 40 CFR 63.6(e). 5. Delay of Repair

Comment : One commenter suggested allowing delay of repair until the next scheduled process shutdown if the source opts to strip hydrocarbon from the cooling water and either recover it (as fuel or for process use) or collect and convey it to combustion control. Response : Provided that the stripped gases are properly captured and controlled, the current provisions would not exclude these actions as a means of compliance. The rule only lists those repair actions that are most likely to occur but we explicitly indicate that the list of repair actions is not all inclusive. If the actions described by the commenter reduce the concentration of strippable hydrocarbons to below the applicable***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 51 of 87 leak action levels while preventing the release of those hydrocarbons to the atmosphere, we consider that these actions qualify under 40 CFR 63.654(d) as a repair, in which case the delay of repair would not be needed. If the actions described by the commenter do not reduce the strippable hydrocarbon concentration to below the leak action level, the existing delay of repair provisions, if applicable, can be used to continue operating until the next scheduled shutdown. In this case, the actions described by the commenter could be used to help prevent an exceedance of the delay of repair action level and thereby maintain the delayed repair. However, if the leak ever exceeds the delay of repair action level, the owner or operator could not use these actions merely to reduce the strippable concentration to below the delay of repair action level. Once the delay of repair threshold is exceeded, the owner or operator of the affected heat exchange system must repair the source within 30 days by reducing the strippable hydrocarbon concentration to below the leak action

level.

Comment : One commenter requested confirmation that the guidelines given in TCEQ’s Sampling Procedures Manual, Appendix P, paragraph 7.2 should be used for determining the molecular***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 52 of 87 weight to use in equation 7.1 of the Modified El Paso Method when determining potential emissions during a delayed repair. Response : The TCEQ’s Sampling Procedures Manual, Appendix P, is the Modified El Paso Method that is incorporated by reference in the heat exchange system provisions of Refinery MACT 1. In 40 CFR 63.654(g)(4), we specifically indicate that the stripping air concentration must be converted to a water concentration using Equation 7-1 of the Modified El Paso Method. Paragraph 7.2 of the Modified El Paso Method specifically notes that “[f]or total VOC based on the portable FID analyzer procedure in Section 6.1, calculate total VOC concentration in the water and emission rate based on the molecular weight of methane...” We specifically require the use of the stripping gas concentration to be determined using flame ionization detector (FID), as noted in section 6.1 of the Modified El Paso Method, calibrated with methane (“as methane”). Therefore, the molecular weight of methane (16 grams per mole) should be used when determining the equivalent water concentration using Equation 7-1 of the Modified El Paso Method when calculating the potential strippable hydrocarbon emissions for a delayed repair. We have clarified this requirement in these final standards. 6. Reporting and Recordkeeping Provisions***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 53 of 87

Comment : One commenter requested clarification that the requirement to record water flow rates applies only to monitoring events in which a leak is detected and the equipment is placed on delay of repair because this is the only occasion in which flow rates are needed. Another commenter stated that records of water flow and emissions estimates should be required only if the rule allows delay of repair based on a demonstration that the emissions caused by delaying repair are less than the emissions caused by a process unit shutdown, if needed, to effect the repair because this is the only situation where water flow and emissions are relevant. If these requirements are not deleted, one of the commenters stated that the EPA should clarify that the recordkeeping requirement is an estimate of “potential strippable hydrocarbon emissions” instead of “potential emissions” because the latter might be misinterpreted to mean organic HAP emissions, which are only a fraction of the hydrocarbon emissions. In addition, a commenter stated that the EPA should clarify that reporting of “an estimate of total strippable hydrocarbon emissions for each delayed repair over the reporting period” covers only the time period from the date by which repair would have had to be completed if it were not delayed until the repair was completed.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 54 of 87 Response : The October 2009 final rule requires a record of the cooling water flow rate for each monitoring event. However, the commenter correctly notes that the requirement in 40 CFR 63.654(g)(4)(ii) to determine the flow rate of cooling water only applies during periods in which repair is delayed. As such, we agree with the commenter that the regulations should not require records of the cooling water flow rate for all cooling towers or heat exchangers because the flow rate only needs to be determined for heat exchange systems for which repair is delayed. Therefore, we are moving the requirement to keep a record of the cooling water flow rate to the paragraph that is limited to delayed repairs, which is 40 CFR 63.655(i)(4)(v) in today’s final rule. We disagree that recordkeeping and reporting of flow rate and potential emissions should only be required where emission caused by delay of repair are demonstrated to be less than they otherwise would be during a shutdown. Stakeholders including the public should be made aware of the potential air emissions releases that may occur based on the decision to delay repair. We agree that the phase “potential strippable hydrocarbon emissions” more accurately describes the delay of repair emission estimate than the phrase “potential emissions” and we are clarifying the language as suggested by the commenter. Comment [A34]: How will the public get this information? Comment [BBC35]: This is reported semiannually to the impleme n ting agencies; these emission are also generally reported through the state emission inventory reporting programs. Further, OAQPS is developing electronic reporting and information exchange system that in the future will be accessible by the public and will provide information on excess emissions and other events reported through the semiannual reports.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 55 of 87 Specifically, we are revising “potential emissions” to instead read “potential strippable hydrocarbon emissions” in the heat exchange system requirements at 40 CFR 63.654(g)(4), the reporting requirements at 40 CFR 63.655(g)(9)(v) and the recordkeeping requirements at 40 CFR 63.655(i)(4)(v) in today’s final rule. As described previously in section III of this preamble, today’s final rule requires that these emission estimates be determined for each monitoring interval instead of over the “expected duration of the delay.” To address the commenter’s concern, we are specifying in 40 CFR 63.654(g)(4)(iii) that “The duration of the delay of repair monitoring interval is the time period starting at midnight of the day of the previous monitoring event or midnight of the day the repair would have had to be completed if the repair had not been delayed, whichever is later,...” Given this clarification in the start of the delay of repair interval and the coordination between the emission estimate methodology and reporting requirements, we do not believe that additional language is needed in 40 CFR 63.655(g)(9)(v) to further clarify that the delay of repair starts at the end of the 45-day period provided to complete a repair under normal circumstances.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 56 of 87

Comment : One commenter requested clarification of the term “original date” in the reporting requirements in 40 CFR 63.655(g)(9)(v) for delayed repair. Response : We are clarifying this regulatory provision by revising the phrase “original date” to instead say “date when the delay of repair began.” As noted in the clarified language regarding the calculation of potential emissions during a delayed repair, the date the delay of repair began is equivalent to the day the repair would have had to be completed if the repair had not been delayed.

Comment : One commenter stated that the proposed requirements to identify the “measured or estimated average annual regulated material concentration of process fluid or intervening cooling fluid processed in each heat exchanger” will be a very burdensome and unnecessary ongoing requirement rather than one-time requirement as specified in 40 CFR 63.655(i)(4)(i). Response : We agree that we should retain this as a one-time requirement. We did not intend to make this an ongoing requirement. The revised language cited by the commenter was part of the proposed Uniform Standards, which we proposed to cross-reference from Refinery MACT 1 but are not finalizing in***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 57 of 87 this action. We are not revising the “one-time” requirement as specified in 40 CFR 63.655(i)(4)(i).

Comment : One commenter suggested deleting paragraphs (b) and (c) in 40 CFR 65.620 (i.e., reporting the number of heat exchange systems in regulated material service found to be leaking and the summary of the monitoring data that indicate a leak) because they duplicate the information required by paragraph (d) (i.e., reporting the date a leak was identified, the date the source of the leak was identified and the date of repair) or are unnecessary. Alternatively, the commenter suggested that the EPA should at least revise 40 CFR 65.620(b) to require reporting of the number of leaking heat exchangers rather than heat exchange systems, and revise 40 CFR 65.620(c) to clarify what monitoring data to report and eliminate the redundancy. Response : The comments refer to the reporting and recordkeeping provisions that we proposed to codify as part of the Uniform Standards, which we are not finalizing in this action. The similar provisions in Refinery MACT 1, which we are retaining rather than cross-referencing the Uniform Standards, as proposed, are the reporting provisions in 40 CFR 63.655(g)(9)(ii) through (iv). We disagree with the commenter that there is undue overlap in these provisions. The number of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 58 of 87 heat exchange systems at the plant site found to be leaking (40 CFR 63.655(g)(9)(ii)) provides a useful summary to the report review. Analogous to the number of fugitive components found to be leaking over a semiannual period which is also required to be reported under Refinery MACT 1, this information is an indicator of both leak program effectiveness and the refinery’s operating and maintenance practices. While one could count each entry in the list of leaking heat exchange systems required in 40 CFR 63.655(g)(9)(iii), we do not consider this duplicative of the list. We do agree that the “summary of monitoring data” could be more clearly delineated. To address this concern, we have revised the provisions in 40 CFR 63.655(g)(9)(iii) to specifically list the desired reporting elements. We also consolidated some of the reporting elements from 40 CFR 63.655(g)(9)(iv) into 40 CFR 63.655(g)(9)(iii) and revised 40 CFR 63.655(g)(9)(iv) to focus on reporting elements for leaks that were repaired during the reporting period. These reporting requirements are now more clear and distinct with no duplication.

Comment : One commenter noted that it would be burdensome to identify, characterize or include pump seal coolers and sample coolers in the heat exchanger inventory and applicability determination. The commenter stated that there is no need for Comment [A36]: How is this information useful? How will EPA use this number?***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 59 of 87 this requirement because those that are once-through coolers should be presumed to meet the low flow exemption criteria and those that are part of a recirculating system with large heat exchangers would be effectively regulated by monitoring of the cooling tower return lines. Response : We never intended to require monitoring of sample coolers and pump seal coolers. As discussed previously, sample coolers and pump seal coolers are specifically excluded from the definition of heat exchange system in today’s final rule, so these coolers do not have to be identified as part of the heat exchange system recordkeeping provisions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 60 of 87 **V. Summary of Impacts** These final amendments will have no cost, environmental, energy or economic impacts beyond those impacts presented in the October 2009 final rule for heat exchange systems at petroleum refineries. If the owner or operator of an existing petroleum refinery elects the quarterly monitoring alternative at thelower leak definition or if the owner or operator of a oncethrough system can aggregate flows across process unit boundaries, we anticipate that the facility will realize a net cost savings compared to the costs estimated for the October2009 final rule. All other amendments are projected to be costneutral. **VI. Statutory and Executive Order Reviews** A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a “significant regulatory action” because it may raise novel legal or policy issues. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and any changes made in response to OMB***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 61 of 87 recommendations have been documented in the docket for this action. B. Paperwork Reduction Act This action does not impose any new information collection burden. The final amendments are clarifications and technical corrections that do not affect the estimated burden of the existing rule. Therefore, we have not revised the information collection request for the existing rule. However, OMB has previously approved the information collection requirements contained in the existing rule (40 CFR part 63, subpart CC) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq ., and has assigned OMB control number 2060-0340. The OMB control numbers for the EPA’s regulations are listed in 40 CFR part 9. C. Regulatory Flexibility Act The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities (SISNOSE). Small entities include small businesses, small organizations and small governmental jurisdictions. Comment [A37]: I s this true? Please confirm? Comment [BBC38]: Y es this is true.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 62 of 87 For the purposes of assessing the impacts of this final rule on small entities, small entity is defined as: (1) a small business that meets the Small Business Administration size standards for small businesses at 13 CFR 121.201 (a firm having no more than 1,500 employees); (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of lessthan 50,000; and (3) a small organization that is any not-forprofit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of this final rule on small entities, I certify that this action will not have a SISNOSE. In determining whether a rule has a SISNOSE, the impact of concern is any significant adverse economic impact on small entities, since the primary purpose of the regulatory flexibility analyses is to identify and address regulatory alternatives “which minimize any significant economic impact of the rule on small entities.” 5 USC 603 and 604. Thus, an agency may certify that a rule will not have a SISNOSE if the rule relieves regulatory burden, or otherwise has a positive economic effect on all of the small entities subject to the rule. Based on our economic impact analysis, the amendments will have no direct cost impacts (or they will result in a nationwide***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 63 of 87 net cost savings). No small entities are expected to incur annualized costs as a result of the final amendments; therefore, no adverse economic impacts are expected for any small or large entity. Thus, the costs associated with the final amendments will not result in any “significant” adverse economic impact for any small entity.

D. Unfunded Mandates Reform Act This rule does not contain a federal mandate that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or to the private sector in any one year. As discussed earlier in this preamble, these amendments are cost neutral and may result in net cost savings for the private sector. Thus, this rule is not subject to the requirements of sections 202 or 205 of the Unfunded Mandates Reform Act (UMRA). This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. The final amendments contain no requirements that apply to such governments, and impose no obligations upon them. E. Executive Order 13132: Federalism This action does not have federalism implications. It will not have substantial direct effects on the states, on the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 64 of 87 relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. These final amendments do not add new control and performance demonstration requirements. They do not modify existing responsibilities or create new responsibilities among EPA Regional offices, states or local enforcement agencies. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicited comment on the proposed amendments from state and local officials. F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). The final amendments will not have substantial direct effects on tribal governments, on the relationship between the federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175. The final amendments impose no requirements on tribal governments. Thus, Executive Order 13175 does not apply to this action.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 65 of 87 G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it is based solely on technology performance. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution or use of energy. Further, we have concluded that the final amendments are not likely to have any adverse energy effects because they are cost neutral and may result in cost savings if the quarterly monitoring option is

elected. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards (VCS) in its regulatory activities, unless to do so***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 66 of 87 would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the agency decides not to use available and applicable VCS. This action does not involve any new technical standards. Therefore, the EPA did not consider the use of any additional

VCS. J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice (EJ). Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the United

States.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 67 of 87 The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. The final amendments do not relax the control measures on regulated sources, and, therefore, do not change the level of environmental protection. K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801, et seq ., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. The EPA will submit a report containing this final rule and other required information to the United States Senate, the United States House of Representatives and the Comptroller General of the United States prior to publication of the final rule in the **Federal Register** . A major rule cannot take effect until 60 days after it is published in the **Federal Register** . This action is not a “major rule” as defined by 5 U.S.C. 804(2). This final rule will be effective on **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]** 

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries Page 68 of 87 **List of Subjects in 40 CFR Part 63** Environmental protection, Air pollution control, Hazardous substances, Incorporation by reference, Reporting and recordkeeping requirements.

Dated:

Lisa P. Jackson, Administrator.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 69 of 87 For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows: **PART 63--[AMENDED]** 1. The authority citation for part 63 continues to read as

follows: **Authority:** 42 U.S.C. 7401, et seq . **Subpart A--[AMENDED]** 2. Section 63.14 is amended by revising paragraph (n)(1) as

follows: **§63.14 Incorporations by reference.**

* * * * * (n) * * * (1) “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” (Modified El Paso Method), Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003, IBR approved for §§63.654(c), 63.654(g), 63.655(i), and 63.11920.

* * * * * **Subpart CC--[AMENDED]** 3. Section 63.640 is amended by: a. Revising paragraph (a) introductory text; b. Revising paragraph (c)(8); and c. Revising paragraph (h)(1).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 70 of 87 The revisions read as follows: **§63.640 Applicability and designation of affected source.** (a) This subpart applies to petroleum refining process units and to related emissions points that are specified in paragraphs (c)(1) through (8) of this section that are located at a plant site and that meet the criteria in paragraphs (a)(1) and (2) of this section:

* * * * * (c) * * * (8) All heat exchange systems, as defined in this subpart.

* * * * * (h) * * * (1) Except as provided in paragraphs (h)(1)(i) and (ii) of this section, new sources that commence construction or reconstruction after July 14, 1994, shall be in compliance with this subpart upon initial startup or August 18, 1995, whichever is later. (i) At new sources that commence construction or reconstruction after July 14, 1994, but on or before September 4, 2007, heat exchange systems shall be in compliance with the existing source requirements for heat exchange systems specified in §63.654 no later than October 29, 2012. (iv) At new sources that commence construction or reconstruction after September 4, 2007, heat exchange systems***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 71 of 87 shall be in compliance with the new source requirements in §63.654 upon initial startup or October 28, 2009, whichever is

later.

* * * * * 4. Section 63.641 is amended by revising the definitions of “Heat exchange system” and “In organic hazardous air pollutant service” to read as follows:

**§ 63.641**  **Definitions.**

* * * * * Heat exchange system means a device or collection of devices used to transfer heat from process fluids to water without intentional direct contact of the process fluid with the water (i.e., non-contact heat exchanger) and to transport and/or cool the water in a closed-loop recirculation system (cooling tower system) or a once-through system (e.g., river or pond water). For closed-loop recirculation systems, the heat exchange system consists of a cooling tower, all petroleum refinery process unit heat exchangers that are in organic HAP service, as defined in this subpart, serviced by that cooling tower, and all water lines to and from these petroleum refinery process unit heat exchangers. For once-through systems, the heat exchange system consists of all heat exchangers that are in organic HAP service, as defined in this subpart, servicing an individual petroleum refinery process unit and all water lines to and from Deleted: **60.101*****E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 72 of 87 these heat exchangers. Sample coolers or pump seal coolers are not considered heat exchangers for the purpose of this definition and are not part of the heat exchange system

. Intentional direct contact with process fluids results in the formation of a wastewater.

* * * * * In organic hazardous air pollutant service or in organic HAP service means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percent by weight of total organic HAP as determined according to the provisions of §63.180(d) of subpart H of this part and table 1 of this subpart. The provisions of §63.180(d) also specify how to determine that a piece of equipment is not in organic HAP service.

* * * * * 5. Section 63.654 is amended by: a. Revising paragraphs (b) and (c); b. Revising paragraph (d) introductory text; c. Revising paragraphs (e) and (f); d. Revising paragraph (g) introductory text and paragraph (g)(4). The revisions read as follows: **§63.654 Heat exchange systems.**

* * * * ****E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 73 of 87 (b) A heat exchange system is exempt from the requirements in paragraphs (c) through (g) of this section if all heat exchangers within the heat exchange system either: (1) Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than the maximum pressure on the process side; or (2) Employ an intervening cooling fluid containing less than 5 percent by weight of total organic HAP, as determined according to the provisions of §63.180(d) of subpart H of this part and table 1 of this subpart, between the process and the cooling water. This intervening fluid must serve to isolate the cooling water from the process fluid and must not be sent through a cooling tower or discharged. For purposes of this section, discharge does not include emptying for maintenance

purposes. (c) The owner or operator must perform monitoring to identify leaks of total strippable volatile organic compounds (VOC) from each heat exchange system subject to the requirements of this subpart according to the procedures in paragraphs (c)(1) through (6) of this section. (1) Monitoring locations for closed-loop recirculation heat exchange systems . For each closed loop recirculating heat exchange system, collect and analyze a sample from the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 74 of 87 location(s) described in either paragraph (c)(1)(i) or (c)(1)(ii) of this section. (i) Each cooling tower return line or any representative riser within the cooling tower prior to exposure to air for each heat exchange system. (ii) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat exchangers within a heat exchange system is covered by the selected monitoring location(s). (2) Monitoring locations for once-through heat exchange systems . For each once-through heat exchange system, collect and analyze a sample from the location(s) described in paragraph (c)(2)(i) of this section. The owner or operator may also elect to collect and analyze an additional sample from the location(s) described in paragraph (c)(2)(ii) of this section. (i) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat exchangers within a heat exchange system is covered by the selected monitoring location(s). The selected monitoring location may be at a point where discharges from multiple heat exchange systems are combined provided that the combined cooling water flow rate at the monitoring location does not exceed 40,000 gallons per minute. (ii) The inlet water feed line for a once-through heat exchange system prior to any heat exchanger. If multiple heat exchange systems use the same water feed (i.e., inlet water from***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 75 of 87 the same primary water source), the owner or operator may monitor at one representative location and use the monitoring results for that sampling location for all heat exchange systems

that use that same water feed. (3) Monitoring method . Determine the total strippable hydrocarbon concentration (in parts per million by volume (ppmv) as methane) at each monitoring location using the “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see §63.14) using a flame ionization detector (FID) analyzer for on-site determination as described in Section 6.1 of the Modified El Paso Method. (4) Monitoring frequency and leak action level for existing

sources . For a heat exchange system at an existing source, the owner or operator must comply with the monitoring frequency and leak action level as defined in paragraph (c)(4)(i) of this section or comply with the monitoring frequency and leak action level as defined in paragraph (c)(4)(ii) of this section. The owner or operator of an affected heat exchange system may choose to comply with paragraph (c)(4)(i) of this section for some heat exchange systems at the petroleum refinery and comply with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 76 of 87 paragraph (c)(4)(ii) of this section for other heat exchange systems. However, for each affected heat exchange system, the owner or operator of an affected heat exchange system must elect one monitoring alternative that will apply at all times. If the owner or operator intends to change the monitoring alternative that applies to a heat exchange system, the owner or operator must notify the Administrator 30 days in advance of such a change. All “leaks” identified prior to changing monitoring alternatives must be repaired. The monitoring frequencies specified in paragraphs (c)(4)(i) and (ii) of this section also apply to the inlet water feed line for a once-through heat exchange system, if monitoring of the inlet water feed is elected as provided in paragraph (c)(2)(ii) of this section. (i) Monitor monthly using a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 6.2 ppmv. (ii) Monitor quarterly using a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv unless repair is delayed as provided in paragraph (f) of this section. If a repair is delayed as provided in paragraph (f) of this section, monitor monthly. (5) Monitoring frequency and leak action level for new

sources . For a heat exchange system at a new source, the owner or operator must monitor monthly using a leak action level***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 77 of 87 defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv. (6) Leak definition . A leak is defined as described in paragraph (c)(6)(i) or (c)(6)(ii) of this section, as applicable. (i) For once-through heat exchange systems for which the inlet water feed is monitored as described in paragraph (c)(2)(ii) of this section, a leak is detected if the difference in the measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this section and the measurement value of the corresponding sample taken from the location specified in paragraph (c)(2)(ii) of this section equals or exceeds the leak action level. (ii) For all other heat exchange systems, a leak is detected if a measurement value of the sample taken from a location specified in either paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this section equals or exceeds the leak action

level. (d) If a leak is detected, the owner or operator must repair the leak to reduce the measured concentration to below the applicable action level as soon as practicable, but no later than 45 days after identifying the leak, except as specified inparagraphs (e) and (f) of this section. Repair includes remonitoring at the monitoring location where the leak was***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 78 of 87 identified according to the method specified in paragraph (c)(3) of this section to verify that the measured concentration is below the applicable action level. Actions that can be taken to achieve repair include but are not limited to:

* * * * * (e) If the owner or operator detects a leak when monitoring a cooling tower return line under paragraph (c)(1)(i) of this section, the owner or operator may conduct additional monitoring of each heat exchanger or group of heat exchangers associated with the heat exchange system for which the leak was detected as provided under paragraph (c)(1)(ii) of this section. If no leaks are detected when monitoring according to the requirements of paragraph (c)(1)(ii) of this section, the heat exchange systemis considered to meet the repair requirements through remonitoring of the heat exchange system as provided in paragraph (d) of this section. (f) The owner or operator may delay the repair of a leaking heat exchanger when one of the conditions in paragraph (f)(1) or (f)(2) of this section is met and the leak is less than the delay of repair action level specified in paragraph (f)(3) of this section. The owner or operator must determine if a delay of repair is necessary as soon as practicable, but no later than 45 days after first identifying the leak.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 79 of 87 (1) If the repair is technically infeasible without a shutdown and the total strippable hydrocarbon concentration is initially and remains less than the delay of repair action level for all monthly monitoring periods during the delay of repair, the owner or operator may delay repair until the next scheduled shutdown of the heat exchange system. If, during subsequent monthly monitoring, the delay of repair action level is exceeded, the owner or operator must repair the leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay of repair action level. (2) If the necessary equipment, parts, or personnel are not available and the total strippable hydrocarbon concentration is initially and remains less than the delay of repair action level for all monthly monitoring periods during the delay of repair, the owner or operator may delay the repair for a maximum of 120 calendar days. The owner or operator must demonstrate that the necessary equipment, parts, or personnel were not available. If, during subsequent monthly monitoring, the delay of repair action level is exceeded, the owner or operator must repair the leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay of repair action level. (3) The delay of repair action level is a total strippable hydrocarbon concentration (as methane) in the stripping gas of 62 ppmv. The delay of repair action level is assessed as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 80 of 87 described in paragraph (f)(3)(i) or (f)(3)(ii) of this section, as applicable. (i) For once-through heat exchange systems for which the inlet water feed is monitored as described in paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded if the difference in the measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this section and the measurement value of the corresponding sample taken from the location specified in paragraph (c)(2)(ii) of this section equals or exceeds the delay of repair action

level. (ii) For all other heat exchange systems, the delay of repair action level is exceeded if a measurement value of the sample taken from a location specified in either paragraphs (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this section equals or exceeds the delay of repair action level. (g) To delay the repair under paragraph (f) of this section, the owner or operator must record the information in paragraphs (g)(1) through (4) of this section.

* * * * * (4) An estimate of the potential strippable hydrocarbon emissions from the leaking heat exchange system or heat exchanger for each required delay of repair monitoring interval***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 81 of 87 following the procedures in paragraphs (g)(4)(i) through (iv) of this section. (i) Determine the leak concentration as specified in paragraph (c) of this section and convert the stripping gas leak concentration (in ppmv as methane) to an equivalent liquid concentration, in parts per million by weight (ppmw), using equation 7–1 from “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see §63.14) and the molecular weight of 16 grams per mole (g/mol) for

methane. (ii) Determine the mass flow rate of the cooling water at the monitoring location where the leak was detected. If the monitoring location is an individual cooling tower riser, determine the total cooling water mass flow rate to the cooling tower. Cooling water mass flow rates may be determined using direct measurement, pump curves, heat balance calculations, or other engineering methods. Volumetric flow measurements may be used and converted to mass flow rates using the density of water at the specific monitoring location temperature or using the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 82 of 87 default density of water at 25 degrees Celsius, which is 997 kilograms per cubic meter or 8.32 pounds per gallon. (iii) For delay of repair monitoring intervals prior to repair of the leak, calculate the potential strippable hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the monitoring interval by multiplying the leak concentration in the cooling water, ppmw, determined in (g)(4)(i) of this section, by the mass flow rate of the cooling water determined in (g)(4)(ii) of this section and by the duration of the delay of repair monitoring interval. The duration of the delay of repair monitoring interval is the time period starting at midnight on the day of the previous monitoring event or at midnight on the day the repair would have had to be completed if the repair had not been delayed, whichever is later, and ending at midnight of the day the of the current monitoring event. (iv) For delay of repair monitoring intervals ending with a repaired leak, calculate the potential strippable hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the final delay of repair monitoring interval by multiplying the duration of the final delay of repair monitoring interval by the leak concentration and cooling water flow rates determined for the last monitoring event prior to the re-monitoring event used to verify the leak was repaired. The duration of the final***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 83 of 87 delay of repair monitoring interval is the time period startingat midnight of the day of the last monitoring event prior to remonitoring to verify the leak was repaired and ending at the time of the re-monitoring event that verified that the leak was repaired. 6. Section 63.655 is amended by: a. Revising paragraph (f)(1)(vi); b. Revising paragraph (g)(9); c. Adding paragraph (h)(7); and d. Revising paragraph (i)(4). The addition and revisions read as follows: **§63.655 Reporting and recordkeeping requirements.**

* * * * * (f) * * * (1) * * * (vi) For each heat exchange system, identification of the heat exchange systems that are subject to the requirements of this subpart. For heat exchange systems at existing sources, the owner or operator shall indicate whether monitoring will be conducted as specified in §63.654(c)(4)(i) or §63.654(c)(4)(ii).

* * * * * (g) * * * (9) For heat exchange systems, Periodic Reports must include the following information:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 84 of 87 (i) The number of heat exchange systems at the plant site subject to the monitoring requirements in §63.654. (ii) The number of heat exchange systems at the plant site found to be leaking. (iii) For each monitoring location where the total strippable hydrocarbon concentration was determined to be equal to or greater than the applicable leak definitions specified in §63.654(c)(6), identification of the monitoring location (e.g., unique monitoring location or heat exchange system ID number), the measured total strippable hydrocarbon concentration, the date the leak was first identified, and, if applicable, the date the source of the leak was identified; (iv) For leaks that were repaired during the reporting period (including delayed repairs), identification of the monitoring location associated with the repaired leak, the totalstrippable hydrocarbon concentration measured during remonitoring to verify repair, and the re-monitoring date (i.e., the effective date of repair); and (v) For each delayed repair, identification of the monitoring location associated with the leak for which repair is delayed, the date when the delay of repair began, the date the repair is expected to be completed (if the leak is not repaired during the reporting period), the total strippable hydrocarbon concentration and date of each monitoring event conducted on the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 85 of 87 delayed repair during the reporting period, and an estimate of the potential strippable hydrocarbon emissions over the reporting period associated with the delayed repair. (h) * * * (7) The owner or operator of a heat exchange system at an existing source must notify the Administrator at least 30 calendar days prior to changing from one of the monitoring options specified in §63.654(c)(4) to the other. (i) * * * (4) The owner or operator of a heat exchange system subject to this subpart shall comply with the recordkeeping requirements in paragraphs (i)(4)(i) through (v) of this section and retain these records for 5 years. (i) Identification of all petroleum refinery process unit heat exchangers at the facility and the average annual HAP concentration of process fluid or intervening cooling fluid estimated when developing the Notification of Compliance Status report. (ii) Identification of all heat exchange systems subject to the monitoring requirements in §63.654 and identification of all heat exchange systems that are exempt from the monitoring requirements according to the provisions in §63.654(b). For each heat exchange system that is subject to the monitoring requirements in §63.654, this must include identification of all***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 86 of 87 heat exchangers within each heat exchange system, and, for closed-loop recirculation systems, the cooling tower included in each heat exchange system. (iii) Results of the following monitoring data for each required monitoring event: (A) Date/time of event. (B) Barometric pressure. (C) El Paso air stripping apparatus water flow milliliter/minute (ml/min) and air flow, ml/min, and air temperature, °Celsius. (D) FID reading (ppmv). (E) Length of sampling period. (F) Sample volume. (G) Calibration information identified in Section 5.4.2 of the “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see §63.14). (iv) The date when a leak was identified, the date the source of the leak was identified, and the date when the heat exchanger was repaired or taken out of service.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 87 of 87 (v) If a repair is delayed, the reason for the delay, the schedule for completing the repair, the heat exchange exit line flow or cooling tower return line average flow rate at the monitoring location (in gallons/minute), and the estimate of potential strippable hydrocarbon emissions for each required monitoring interval during the delay of repair.

* * * * *

### FROM: Jeff Coburn, RTI International TO: Brenda Shine, EPA/OAQPS FOR: EPA Docket No. EPA-HQ-OAR-2011-0002 DATE: July 12, 2011 SUBJECT: Technology Review for Heat Exchange Systems

1. Purpose This memorandum documents the technology review for heat exchange systems. It reviews control alternatives and estimates the costs a nd environmental impacts for the alternatives identified. 2. Legislative Background The Clean Air Act (CAA) requires EPA to review promulgated standards periodically to ensure new source performance standards (NSPS) and na tional emissions standards for hazardous air pollutants (NESHAP) reflect advances in emissi ons reduction technology. Specifically, Section 112(d)(6) of the Clean Air Act (CAA) states that “[t]he Administrator shall re view, and revise as necessary (taking into account de velopments in practices, proce sses, and control technologies), emission standards promulgated und er this section no less often th an every 8 years.” Similarly, Section 111(b)(1)(B) requires EPA to review NSPS for a given source category every 8 years, and, if appropriate, revise such standards. To facilitate these required re views, EPA is evaluating key emission sources that exist across severa l source categories to provide a consistent framework when evaluating the emissions from these key sources for a particular source category. This memorandum documents one such t echnology review for heat exchange systems. 3. Introduction Heat exchangers are devices or coll ections of devices used to transf er heat from process fluids to another fluid (typically air or wa ter) without intentional direct c ontact of the process fluid with the cooling fluid ( i.e. , non-contact heat exchanger). The focus of this technology memorandum is on water-cooled heat exchangers. The term “heat exchange system” is used in this memorandum to refer collectively to water-cooled heat exchangers and the associated cooling water handling system. There are two types of heat exchange sy stems: closed-loop recirculation systems and once-through systems. Closed-loop recirculation systems are marked by the use of a cooling tower to cool the heated water leavi ng the heat exchanger and then return the newly cooled water to the heat exchanger for reuse. For closed-loop recirculat ion systems, the heat exchange system consists of a cooling tower, all heat exchangers that are serviced by that cooling tower, and all water lines to and from the heat exchanger(s). Once-through systems typically use

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

2 river or pond water as the influe nt cooling fluid to the heat ex changers, and the heated water leaving the heat exchangers is then discharged from the facility. For once-through systems, the heat exchange system consists of one or more heat exchangers servicing an individual process unit and all water lines to and fr om the heat exchanger(s). At times, the heat exchanger’s internal tubing material can corrode or crack, allowing some process fluids to mix or become entrained with the cooling water. Pollutants in the process fluids may subsequently be released from the c ooling water into the atmosphere when the water is exposed to air ( e.g. , in a cooling tower fo r closed-loop systems or trenches/ponds in a oncethrough system). This technology memorandum specifically considers methods to reduce emissions from cooling water that has unintentiona lly contacted a process fluid within in a heat exchanger. Note that intenti onal direct contact of water with process fluids results in the formation of a wastewater, which is not covered in this technology memorandum. 4. Description of Emission Releases Once-through heat exchange syst ems generally transport the c ooling water leaving the heat exchangers in open sewer lines or trenches to a holding pond to allow the water to cool prior to discharge. Fugitive air emissions of polluta nts from the water may occur along the transport lines and from the surface of the holding pond or receiving water body. So me facilities may use a spray in the holding pond to help cool the water, but this also increases water contact with the air and therefore the potential fo r air emissions. Emissions from once-through heat exchange systems are similar to releases from wastewater treatment units and are fugitive in nature. The emissions occur via volatilization at the air-liquid inte rface within the trans port lines or in the surface impoundments. Not all pollutants will be emitted from the cooling water to the same extent. Highly volatile compounds ( i.e. , those with high Henry’s Law constants) are expected to be nearly completely released from the coo ling water while only a small fraction of the less volatile compounds are emitted; the remainder of the less volatile compounds would remain in the water through the collection and holding units. It is costly to completely cover these once-throu gh cooling water sources to prevent air releases. Furthermore, covering these units would only serv e to suppress the volatile emissions that would be released later from the receiving water body. It would be very costly to build a treatment system for the cooling water which would not actu ally need treatment excep t for the small period of time a leak at the heat exchanger might exist. That is, it is not generall y feasible to prescribe or enforce a standard of performance because the pollutant or pollutants are not emitted through a conveyance designed and constructed to emit or capture such pollutant(s) and that the application of a measurement methodology, whic h would require such a conveyance to be installed, is not generally feas ible in light of the technolog ical and economic limitations. Closed-loop heat exchange systems typically use cl osed piping to transport the water to and from the cooling tower. Emissions from closed-loop heat exchange systems occur primarily at the cooling tower, as this is gene rally the only point for exposure of the cooling water with the atmosphere. Cooling towers may be designed as either natural draft or mechanical draft. Natural draft cooling towers are large hyperbolic st ructures (often associat ed with nuclear power plants) that use natural convection of warmed ai r to create air flow across the water, thereby cooling the water. Mechanical dr aft cooling towers use large fans to force air through or across

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

3 the cooling water to cool the water. Figure 1 shows a typical mechanical, induced-draft industrial cooling tower. The cooling towers are designed to have a high surface area for airwater contact for the purposes of cooling the wa ter. Most industrial cooling towers have multiple exhaust fans that are used to draw ambient air through water that is cascading down the outer-portion of the tower; the air is then e xhausted from very short, wide fan openings at multiple locations across the top of the cooling tower. Emissions can also occur across the openings at the sides of cooling towers as wind blows across the unit. Em issions occur primarily due to volatilization of light organics from the wa ter. A small fraction of the recirculating water may become entrained in the exhausted air and le ave the cooling tower as a water mist. This water mist is commonly referred to as “drift” or “drift losses.” All po llutants contained in the water mist, including low volatility compounds, can be released to the atmosphere via the cooling tower drift.

Figure 1. An induced-draft industrial cooling tower. Although emissions from closed-loop systems are expected to be released primarily in the exhaust air from the cooling towers, it is not gene rally feasible to prescribe or enforce a standard of performance because the pollutant or po llutants are not emitted through a conveyance designed and constructed to emit or capture such pollutant(s) and that the application of a measurement methodology, which would require su ch a conveyance to be installed, is not feasible due to technological and economic limitations . First, not all of the emissions occur from the exhaust gas fans at the top of the cooling tower; fugitive releases can also occur through openings along the side or bottom of the cooling tower. To capture all of the emissions would require that the whole cooling tower be enclosed. This is not practical or technically feasible considering the size of the cooling towers and th e volume of gas that would be required to be handled within the enclosure system and consid ering the heat transfer requirements of the

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

4 cooling tower. While it may be technically feas ible to install ducts on each exhaust fan to capture and route the primary exhaus t gas to a single stack for poten tial treatment and/or release, such an installation still suffers from techni cal and economic limitations. Such a proposed capture and exhaust stack would still have to be very large due to the size of the physical dimensions of the cooling towers, the volume of air exhausted, and the need to transport the exhaust air away from the cooling tower (oth erwise, the stack itself will reduce the cooling efficiency of the cooling tower, leading to pro cess operation issues for the heat exchanger served by the cooling tower). Given the large exhaust volumes and the high moisture content of the exhaust, routine measurements that provide th e necessary detection limits needed to identify typical heat exchanger leaks are not available. Furthermore, such a capture system would not capture all of the emissions from the cooling tower. Based on the nature of the emission releases fr om heat exchange systems (both once-through and closed-loop systems as described above), it is ge nerally not feasible to prescribe or enforce a standard of performance for heat exchange systems. Specifically, the application of a measurement methodology, which would require a conveyance designed and constructed to emit or capture the emissions from the heat exchange syst em to be installed, is not feasible in light of the technological and economic lim itations associated with atmo spheric releases from heat exchange systems. Differences in emissions from once-through h eat exchange systems and closed-loop heat exchange systems were evaluated using emissi on models. This evaluation was completed because direct emission measurements are not available for these sources (due to the measurement method limitations just discu ssed). Wastewater emission models ( e.g. , using mass transfer correlations) can be us ed to predict the releases from the open cooling water sources used in a once-through heat exchange system. Although the emissions will vary based on the design and operation of the cooling water collec tion and holding units in once-through systems, highly volatile compounds are projected to be ne arly 100 percent emitted from the cooling water while only a small fraction of low volatility compounds will be released. These results are similar to modeling results for th e releases projected for cooling towers used in closed-loop heat exchange systems. Again, emissions from the cooling tower can vary based on the air-liquid flow ratio and mass transfer efficiency. Given th e uncertainty and variabili ty of emissions from these sources, the emissions potential for bot h once-through and closed -loop heat exchange systems are expected to be essentially equivalent. 5. Identification of Control Alternatives Since it is not feasible to prescribe or enfor ce a standard of performance for heat exchange systems, design, equipment, work practice, a nd operational standards for reducing emissions from heat exchange systems were identified and evaluated. Potential Equipment Design and Operational Standards As the heat exchange systems evaluated in this memorandum are designed as non-contact systems, any contact that does occur happens as a result of an unintentional equipment failure that results in a leak of the process fluid into the cooling water. No construction material was identified that, in all cases, could not unint entionally leak. Certain design or operational

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

5 conditions were identified that would effectively reduce or eliminate the leak from the heat exchanger from contaminating the cooling water and subsequently be emitted. A brief description of these design and operational conditions follows:

• Heat exchangers where the cooling water pre ssure significantly exc eeds the process fluid pressure . For these heat exchangers, if a crack in the heat exchanger occurs, water will leak into the process fluid rather than the process fluid leaking into the cooling water. Note that there will be a pressure drop acr oss the heat exchanger for both the water and process fluid, and most heat exchangers opera te with countercurrent flow. The process fluid inlet side of the heat exchanger, which will be the location of the maximum process fluid pressure within the heat exchanger, will also be the water outlet side of the heat exchanger (location of minimum water pressu re within the heat exchanger). It is conceivable that a leak into the cooling water can still o ccur even though the inlet water pressure exceeds the inlet fluid pressure. Ther efore, it is necessary to specify that the minimum cooling water pressure at any poi nt within the heat exchanger exceeds the maximum process fluid pressure within the he at exchanger. Typical language used in previous rules for heat exchangers describe th ese heat exchangers as those that “operate with the minimum pressure on the cooli ng water side at least 35 kilopascals [ i.e. , 5.0 pounds per square inch absolute (psia)] greater than the maximum pressure on the process side.”

• Heat exchangers that employ an inert (not vol atile) intervening coo ling fluid between the process and the cooling water and isolates the cooling water from the process fluid . The intervening fluid must remain enclosed a nd cannot be sent through a cooling tower or otherwise allowed routine c ontact with the atmosphere; otherwise, emissions would simply be transferred from the cooling wate r release points to the intervening fluid release points. Provisions would be need ed for draining the in tervening fluid for maintenance purposes. One could conceive of a situation in which a leak develops between the process fluid and a second leak develops between the intervening fluid and the cooling water. If this occurs, and the process flui d pressure exceeds the water pressure, the intervening process fluid chamber would become filled with process fluid and the process fluid would leak into the c ooling water. Thus, while a heat exchanger designed to use an intervening fluid is much less likely to leak (because two leaks would have to occur) than a heat exchanger that doe s not employ an intervening fluid, this type of design does not necessarily guarantee that process fluid leaks that contaminate the cooling liquid will never occur. The question arises: should these design and operational alternativ es be required for all new or modified sources? As process fl uid pressures are dictated by process operational conditions, and many chemical processes operate at elevated pre ssure, it is impractical to require the cooling water supply to operate at a pre ssure exceeding the process fluid pr essures in all cases. Typical industrial water supply systems operate at a of 30 to 100 psi gauge pressure (psig). If the process fluid is at a high pressure, co mmonly available water supply syst ems could not supply cooling water at these same high pressures. Additionally , the heat exchanger housing would have to be designed to handle these high pressu res. It would be cost-prohi bitive and energy intensive to require heat exchanger water pressures to exceed process fluid pressures in all applications.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

6 The use of an intervening process fluid requires a specially designed pro cess heater. It would generally be impossible to retrofit a process heater to use an intervening fluid without completely replacing the heat exchanger. This would be a cost-prohibitive requirement for existing heat exchange systems. New installations could be de signed to use an intervening fluid; however, the use of an intervening fluid generally reduces the heat transfer effici ency of the heat exchanger, so there are additional costs associat ed with using an intervening fluid because the heat exchangers would be larger when using an intervening flui d. It is beyond the scope of this evaluation to determine the precise costs associated with requir ing the use of an intervening fluid, as this can vary significantly by size and ope rational needs of a specific heat exchanger. Also, it is difficult to quantify the emission reductions achieved by such an application because there are no data to determine how often these systems do eventually leak. However, the fact that such systems could eventually develop leaks in to the cooling water would sugge st that monito ring to identify incidence of leaks may still be needed. Therefore, a facility would have to undergo significant costs to design and install a heat exchanger w ith an intervening flui d, and still incur ongoing costs to monitor for leaks. As described pres ently, a monitoring and repair program to identify leaks is effective at reducing emissions from heat exchange systems. While it is not possible to develop a quantitative cost-effec tiveness value for a requirement to use an intervening fluid in new heat exchanger installations, the additional costs associated with such a requirement do not appear to be reasonable considering the limite d emission reductions that would be achieved beyond the implementation of a monitoring and repair program to identify leaks. In fact, in most cases, it would be extremely expensive to implem ent with little to no emission reductions. While the use of an intervening fluid may be evaluated in more detail for specific source categories, particularly for heat exchangers handling proces s fluids that are highly toxic or corrosive ( e.g. , hydrogen fluoride), it appears that, fo r typical heat exchanger systems, the use of an intervening fluid in new or existing heat exch angers is not practical, taking into consideration the cost of achieving limited emission reductions (beyond th ose achieved through a monitoring and repair program) and considering the e nvironmental and energy impact s of such a requirement. Potential Monitoring Alternatives A variety of different work prac tices were identified as potential emission reduction measures for heat exchange systems. These work practices can be loosely grouped as visual inspections, surrogate monitoring, water sampling and anal ysis, and stripping column air analysis. Visual inspections have been used by several facilities. For heat exchangers servicing a gaseous process fluid, gas entering the cooling water will coll ect in these high points in the line. If these locations have a site glass, visual inspections can be used to identify these leaks. For oncethrough cooling systems, the owner or operato r can visually inspect the holding pond for a visible organic sheen. The presen ce of an organic sheen indicates that a heat exchanger is likely to be leaking. Visual inspections are expected to be able to identify very large leaks, but they will not be able to identify leaks that do not exceed solubility limits of the cooling water. Surrogate monitoring methods include monitoring of chemical usage rates ( e.g. , chlorine, hypochlorite, or bromine usage rate s), monitoring of free chlorine in the cooling water, and monitoring of the oxidation/reducti on potential of the cooling water. When a leak of a degradable organic pollutant occurs, the added organic matte r in the cooling water causes

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

7 increased microbial growth. The oxidation/reducti on potential or free ch lorine concentration may be used to monitor for microbial growth (Suslow, 2004). When microbial growth is found, disinfectant chemical use rates are increased to control the biological grow th. Microbial growth in the heat exchanger will reduce the heat tran sfer efficiency and ma y cause plugging of the water tubes. Consequently, esse ntially every closed-l oop heat exchange system is monitored for microbial growth. Several consecutive days of increased biological growth or increased disinfectant chemical use rates w ould indicate a leak has occurred. Since surrogate monitoring is commonly performed on a daily or per shift freq uency, these methods should be able to detect leaks fairly quickly. However, there may be lag period between the initiation of the leak and significant microbial growth, so there may be some delay between the first occurrence of the leak and a change in the surrogate monitoring level. For this same reason, surrogate monitoring may not be able to identify leaks in once-through sy stems even if monitoring is used to control microbial growth from the source water used in the system. Surrogate monitoring methods can detect leaks that do not exceed wa ter solubility limits, so these methods should be more sensitive than visual inspections. However, as there is commonly some background level of microbial growth and disinfectant use, surrogate monitori ng methods generally are not sensitive enough to identify smaller heat exchanger leaks. Based on the available data, monitoring of surrogate parameters will only detect relatively large l eaks and could miss leaks that would generate significant organic emissions (Corsi et al., 2004). Water sampling methods include total hydrocarbon (THC), total organic carbon (TOC), or speciated chemical analysis. Common industrial water supply can have TOC concentrations of 1 to 5 parts per million by weight (ppmw). Cons equently, THC or TOC monitoring may be able to identify an increase in THC or TOC of 1 ppmw by monitoring before and after the heat exchanger, but are generally not sensitive enough to identify smaller leaks. Using knowledge of the process fluid, analysis of speci fic pollutants can be used to iden tify a leak. For example, for an ethylene unit, monitoring for et hylene in the cooling water leav ing the heat exchanger can be used to identify a leak. By targeting a specific chemical or limited set of chemicals, very low water detection limits can be achieved; common de tection limits are approximately 10 to 20 parts per billion by weight (ppbw). For very volatile compounds, the direct water concentration and flow rate can be used to estimate the emissi ons from the heat exchange system by assuming 100 percent of the pollutant will be emitted. For less volatile compounds in closed-loop heat exchange systems, the concentration of semi-vol atile compounds can slowly build-up within the recirculated cooling water, because not all of the compound will be emitted from the cooling tower. For these compounds, direct water sa mpling of the cooling wa ter leaving the heat exchanger may be able to identify very small leak s, but this concentration may not correlate with the actual emissions from the system (when a ssuming 100 percent emissions). Sampling can be performed before and after the c ooling tower (which is the same as monitoring before and after a heat exchanger or set of heat exchangers) to get a better estimate of the actual emissions or leak rate, but this tends to re duce the sensitivity of the method. For example, if the concentration of a cresol builds up to 200 ppbw, it may be difficult to detect a change in concentration across the heat exchanger of 20 ppbw even though the detec tion limit for cresol may be less than 20 ppbw. Nevertheless, the elevated concentrations of cr esol provide reasonable evidence that a leak exists. It may be reasonable to compare the conc entrations in the cooling water leaving the heat exchanger with the source water used in a once- through system or the water used as make-up in

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

8 a closed-loop system to ensure that any elevated concentrations are due to a leak in the heat exchanger rather than background water contamination. The modified El Paso method (TCEQ, 2003) uses a dynamic or flow-through system for air stripping a sample of the water and analyzing the resultant off-gases for volatile organic compounds (VOC) using a common flame ionization detector (FID) analyzer. This method was originally developed for use by El Paso Products Company in the early 1970s for cooling tower water characterization, and it has been the popular monitoring choice in Texas for many years. The modified El Paso method helps to overcome potential losses of hi ghly volatile components during water sampling. Also, based on the liquid and air flow rates used in the modified El Paso method, the air concentration detection limit of approximately 1 ppm by volume (ppmv) (as methane) corresponds to a wate r concentration of approximate ly 15 ppbw. Therefore, the modified El Paso method provides similar detecti on limits as speciated water analysis. It also simulates, to some extent, the losses that might occur from the cooling water, so leaks of semivolatile compounds that are not eas ily stripped from the cooling water in the cooling tower are also not fully stripped in th e stripping column. While the stripping column may not exactly simulate the stripping efficiency of the specifi c cooling tower being mon itored within the heat exchange system, the stripping column provides a reasonable proxy of the air emissions from the heat exchange system. Leak Repair Considerations Regardless of the monitoring method used, once a l eak is identified, it must be repaired or isolated to prevent the process fluid from contam inating the cooling water. Many industrial heat exchangers use a shell and tube design, where the process fluid is in the tubes with the cooling water flow in the shell. If the specific tube th at is leaking can be iden tified, that tube can be plugged, thereby preventing the proc ess fluid from flowing through that tube and isolating the leaking section of the heat exchanger. This procedure diminishes the effective area for heat exchange, thereby reducing the overall efficiency of the heat exchanger bundle. Depending on the age of the heat exchanger and the number of tubes that have been blocked already, the heat exchanger bundle may need to be replaced. In some installations, the leaking heat exchanger bundle can be isolated, removed fr om service, and replaced wit hout interruption of the process served by the heat exchanger. However, there ca n be installations where a heat exchange system may not have excess capacity to allow one bundl e to be removed without shutting down the process unit. It takes time to identify the prec ise location of a leak and affect its repair. Some heat exchange systems may include multiple heat exchanger b undles from different processes. Speciated chemical analysis is typically used as a fingerp rint to identify which pr ocess fluid is leaking, thereby identifying the likely proc ess unit associated with the lea k. However, it takes additional monitoring to identify which heat exchanger bundle is leaking, and additional time to identify the specific tube that has the leak. Plugging a tube can be done fa irly quickly, but it may take additional time to obtain parts needed if the heat exchanger bundle must be replaced. The repair should be accomplished as soon as practical, and in most cases, this will take no longer than 45 days. For specially sized or designed heat exchangers, there may be instances where the necessary equipment may take several months to obtain. Under this ci rcumstance, it may be

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

9 reasonable to allow the repair to be delayed until the part can be obtained. Most special order parts can be obtained within 90 da ys of an order, so a total re pair time of 120 days should be sufficient to locate the leak, order the parts, and complete the repa ir. Delay of repairs may also be reasonable for small leaks that can only be repaired if the proce ss unit is shut down. Requiring the unit to shut down sp ecifically for the repair may generate more emissions than would occur by delaying repair. Also, requiring the unit to shut down c ould result in significant lost revenue, which could (potentially) make the requirement for immediate repair very costly. 6. Costs of Monitoring Alternatives This section describes the costs associated with various work practice monitoring alternatives. Costs were not developed for specific equipment de sign or operational alte rnatives because these costs can vary widely by application and are expe cted to be very high in most applications. While these equipment design or operational altern atives can be very expensive, there may be instances where they can be considered. For exam ple, if a certain source category has units that only operate at low pressures, it may be reasonable, at least for ne w sources, to require that the water-side pressure exceed the process fluid pressu re at all points in th e heat exchanger. The equipment or design alternatives id entified in Section 5 should be evaluated for a specific source category to determine if, based on the operational characteristics of the processes and the hazards associated with the pollutants contained in the pr ocess fluids, these alternatives are economically viable or needed to reduce risks associat ed with potential pollutant releases. General manufacturing industry sect or labor rates (May 2009 dollars) were used to develop the costs for labor-related requirements for the different work practice monitoring alternatives described in Section 5. These costs were based on mean hourly labor rates and were developed for different labor classes (tech nical, managerial, administrativ e, maintenance, and operating labor classes). The hourly labor rates were bur dened with fringe benefits and overhead to calculate the loaded hourly labor ra te for each labor class. The labor classes used in the analysis and the loaded hourly labor ra te calculated for each labor class are summarized in Table 1

.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

10 Table 1. Summary of 2009 Hourly Labor Rates

Labor Class (A) Mean hourly labor rate 1 ($/hr) (B) Fringe benefit loading

rate I Overhead and profit rate (D = A x B x C) Loaded wage rate ($/hr) 1. Professional specialty and Technical (SOC Code: 17-2081) 39.53 1.5 1.4 83.01 2. Executive, administrative and managerial (SOC Code: 11-9041) 57.80 1.5 1.4 121.38 3. Administrative support, including clerical (SOC Code: 43-0000) 17.31 1.5 1.4 36.35 4. Installation, Maintenance, and Repair (SOC Code: 49-0000) 22.08 1.5 1.4 46.37 5. Plant and System Operators, All (SOC Code: 51-8099) 22.72 1.5 1.4 47.71

1 Labor rates as reported by U.S. Department of Labor, Bur eau of Labor Statistics (U.S. DOL, 2010). Labor rates for

May 2009 for general manufacturing industry sector: 2-digit NAICS code 31 through 33 ( http://stats.bls.gov/oes/oes_dl.htm accessed in December 2010).



### Visual Inspections and Surrogate Monitoring Costs For the most part, visual inspecti ons and/or surrogate monitoring is already widely used in nearly all industrial cooling water applic ations. As such, there are li mited costs associated with a requirement to perform visual inspections and/ or surrogate monitoring. The primary additional cost associated with such a regulatory program would be the development of a quality assurance (QA) plan to document the inspections/monitoring procedures, the baseline monitoring value or acceptable range, and the parameter values that would trigger corrective action ( i.e. , indicate a leak that must be repaired). Thus, no addi tional equipment is assumed to be needed to implement visual inspections or surrogate monitoring, and only minimal labor costs would be incurred for QA plan development, recordkeeping, and reporting. Table 2 summarizes the costs associated with a visual inspections a nd surrogate monitoring program. The cost of developing a QA plan is expect ed to be a one-year cost per facility; if there are multiple heat exchange systems at the facility , the cost per heat exchange system would be the total QA plan cost divided by the number of heat exchange systems affected by the rule. It is assumed that the QA plan has a useful life of 5 years when annualizing these costs. The 6 hours for recordkeeping are based on an additional minute per day to record the results of the visual inspections and surrogate monitoring (beyond th ose routinely required by the facility).

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

11 Table 2. Summary of Costs Associ ated with Surrogate Monitoring

Activity/Requirement Number of labor hours by labor class per year for activity/requirement

Total Cost ($)TechnicalManagerialAdministrativeOperators

QA plan (1 st year cost only) 10 1 2 0 1,024 Recordkeeping 0 0 0 6 286 Reporting (assumes semi-annual reporting) 4 0.4 0.8 0 410



### Water Sampling Monitoring Costs Water sampling costs are dependent on the partic ular analytical method used and, for speciated organic analysis, the number of compounds that must be analytica lly determined. TOC analysis costs range from $50-75 per sample, and speciat ed chemical analysis via EPA Method 601/602 costs approximately $250/sample (based on on-line price lists: Analytical Laboratories, Inc., http://analyticallaboratories.com/page.cfm?pageid=90 ; Analytical Resources, Inc., http://arilabs.com/portal/ downloads/ARI_price_list.pdf ; Environmental Testing Inc., http://www.eti-lab.com/files/Price.pdf ). Since most cooling water can have fairly significant and potentially variable TOC concentrations, both in let and outlet samples from the heat exchanger may be needed to identify a leak. Traditionally, this “delta” concentration is determined using triplicate analysis at each samp ling location, requiring six samples total. Therefore, costs of typical TOC sampling can range from $300 to $450 per event. As such, TOC water sampling costs approximately the same or even more than speciated water sampling using only one sample of the cooling water after the heat exchanger. Of course, if a delta c oncentration were needed from the speciated organic monitoring, speciated organic monitoring would cost more than TOC monitoring, but if the speciated or ganic analysis can be correctly targeted, a single concentration analysis should be adequate. Like the surrogate monitoring approach, a QA plan will need to be developed for water sampling monitoring. Because these types of water sample s must be collected in specific ways and may require different sampling locations than those used for routine sampling used to control disinfectant addition. Therefore, additional hours are projected for this task compared to the surrogate monitoring QA plan. The cost of deve loping a QA plan is expected to be a one-year cost per facility; if there are multiple heat exchan ge systems at the facility, the cost per heat exchange system would be the total QA plan cost divided by the number of heat exchange systems affected by the rule. It is assumed that the QA plan has a useful life of 5 years when annualizing these costs. Labor time is also re quired to collect the samples for each sampling event and for recordk eeping and reporting. Table 3 provides the labor estimates for a water sampling monitoring program. As the annual cost of a water sampling program is dependent on the number of sampling events, the costs in Tabl e 3 are provided per sample or sampling event (except for the QA plan as discussed previously and reporting costs, wh ich are per periodic reporting event) so that the costs can be scaled for diffe rent monitoring frequencies.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

12 Table 3. Summary Costs Associated with Water Sampling Monitoring

Activity/Requirement Number of labor hours by labor class per year for activity/requirement

Total Cost ($)TechnicalManagerialAdminis-trativeOperators

QA plan (1 st year cost only) 32 2 4 0 3,045 TOC analysis costs/sample 60 Method 301/302 analysis costs/sample 250 Sample express shipping cost/event 30 Sample shipping & results review labor/event 0.5 0 0.5 0 60 Single sample collection labor/event 0 0 0 1 48 Triplicate in-out sample collection labor/event 0 0 0 1.5 72 Recordkeeping labor/event 0 0 0 0.25 12 Reporting labor/reporting event 2 0.2 0.4 0 205 Example costs for quarterly Method 301/302 sampling with semiannual reporting for single heat exchange system First year costs [QA plan + 4×(sampling+ship ping+analysis+recording)+2×reporting] 5,055 Subsequent year costs [4×(sampling+shippi ng+analysis+recording)+2×reporting] 2,010 Average annualized costs [CRF 1 ×QA plan + subsequent year costs] 2,750

1 CRF = capital recovery factor = 0.2439 based on 5 year life and 7 percent annual interest.



### Modified El Paso Monitoring Costs Stripping columns can be purchased for use by the facility personne l or the facility can hire a contractor to come to the f acility and perform the strippi ng column (modified El Paso) monitoring without the facility purchasing th e equipment. The decision to purchase the equipment will depend on the number of sampling ev ents required to be performed each year. Stripping column equipment costs and testing f ees were obtained from a testing contractor (Boudreaux, 2010). These costs as well as other costs associated with a periodic modified El Paso monitoring program are summarized in Table 4 . As with a water sampling program, the annual costs for a modified El Paso monito ring program are dependent on the number of sampling events per year (which is dependent on both the number of heat exchange systems that must be monitored and the monitoring frequency) . As such, many of the costs in Table 4 are provided per monitoring event so that the co sts can be scaled for different monitoring frequencies.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

13 Table 4. Summary Costs Associated with Modified El Paso Monitoring

Activity/Requirement Number of labor hours by labor class per year for activity/requirement

Total Cost ($)TechnicalManagerialAdminis-trativeOperators

QA plan (1 st year cost only) 32 2 4 0 3,045 Stripping column 3,850 FID analyzer 10,000 Contracted analysis, first or single event 680 Contracted analysis, 2nd or 3rd locations/event 1 195 In-house sampling/monitoring event 0 0 0 3 143 Recordkeeping/monitoring event 0 0 0 0.25 12 Technical review of results/monitoring event 0.5 0 0 0 42 Training/training event (annual) 2 0 0 6 450 Reporting/reporting event 2 0.2 0.4 0 205 Example costs for quarterly in-house El Paso monitoring with semiannual reporting for single heat exchange system First year costs [QA plan + stripping column+ FID analyzer + 4×(in-house sampling+recording+tech review)+ 2×reporting + training] 18,545 Subsequent year costs [4×(sampling+recor ding+review)+2×reporting+training] 1,650 Average annualized costs [CRF 2 ×(QA plan+column+analyzer) + su bsequent year costs] 5,770

1 Sampling of 4 or more heat exchange systems is not ex pected to be completed within 1 day, so additional lodging

expenses would be incurred, which are not included in the model. Purchasing an in-house system is comparable to contract sampling and is the assumed option when 4 locations or more are required to be monitored. 2 CRF = capital recovery factor = 0.2439 based on 5 year life and 7 percent annual interest.



### Like the surrogate and water sampling monitoring approach, a QA plan will need to be developed for modified El Paso monitoring. Th e costs of developing th e QA plan for using the modified El Paso method are expected to be similar to the costs of developing a QA plan for water sampling; the costs are “one-time” per facility, but are expected have a useful life of 5 years when annualizing these costs. Similarly, if a stripping column is purchased, it is assumed that one system will be purchased for the facility and the equipment is expected to have a useful life of 5 years. While costs are provided separately for the FID analyzer (because some facilities have available FID analyzers), all stripping colu mns are assumed to be purchased with a new FID analyzer. It is estimated to take 3 hours per sampling event to set-up, run, then clean the stripping column to prepare it fo r re-use. Additionally, annual tr aining is assumed to be needed to properly implement this monitoring method in- house; these costs are per facility rather than per heat exchange system. The modified El Paso method can be set up to run continuously for continuous monitoring of the heat exchange system. For th is option, the equipment costs for the stripping column and FID

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

14 analyzer would be incurred per heat exchange syst em rather than per facility. A shelter would be needed to house the stripping column system fo r a continuous application; the costs of such a shelter were estimated to be $10,000 per heat exch ange system. Daily checks of the continuous monitoring system would also be needed to ensure the system is opera ting correctly; 0.5 operator hours per day were estimated for these daily checks. Annualized Costs of Alternative Monitoring Programs The total annualized costs of water sampling a nd modified El Paso monitoring programs at different monitoring frequencies were estimated ba sed on the costs presented in Tables 3 and 4. As the cost to perform triplicate inlet-outlet TOC sampling is essentially identical to the cost of performing a single speciated orga nic analysis, only the cost for a water sampling program using a single sample for speciated organic analysis per sampling event are presented here. These same costs apply for the TOC sampling approach . For modified El Paso monitoring, it is assumed the facility would elect to purchase a stripping column and FI D analyzer and perform in-house monitoring when the total annualized costs for in-house monitoring was less than the costs for contracted services. For the annual monitoring frequency option, annual reporting was assumed. For all other monito ring frequencies, semi-annual reporting was assumed to be required. Table 5 presents the costs of key options a ssuming there is only one heat exchange system present at the facility. Table 6 presents similar costs pe r monitored heat exchange system when 2 monitored heat exchange rs are present at the facility. Table 5. Summary of Monitoring Costs as a F unction of Monitoring Frequencies with One Monitored Heat Exchange System at the Facility

Monitoring Method Capital and 1x Costs Annualized Capital

Cost Annual Operating

Costs Total Annualized Costs Sample Events

per Year Water sampling $ 3,045 $ 743 $ 604 $ 1,347 1 El Paso - contracted out $ 3,045 $ 743 $ 947 $ 1,690 1 El Paso - buying system $ 16,895 $ 4,120 $ 854 $ 4,974 1 Water sampling $ 3,045 $ 743 $ 2,007 $ 2,750 4 El Paso - contracted out $ 3,045 $ 743 $ 3,316 $ 4,059 4 El Paso - buying system $ 16,895 $ 4,120 $ 1,648 $ 5,769 4 Water sampling $ 3,045 $ 743 $ 5,202 $ 5,944 12 El Paso - contracted out $ 3,045 $ 743 $ 9,089 $ 9,831 12 El Paso - buying system $ 16,895 $ 4,120 $ 3,221 $ 7,341 12 Water sampling $ 3,045 $ 743 $ 21,174 $ 21,917 52 El Paso - contracted out $ 3,045 $ 743 $ 37,949 $ 38,691 52 El Paso - buying system $ 16,895 $ 4,120 $ 11,084 $ 15,204 52 El Paso - continuous $ 26,895 $ 6,559 $ 9,569 $ 16,129 8760

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

15 Table 6. Summary of Monitoring Costs per Heat Exchange System as a Function of Monitoring Frequencies when Two Monitored Heat Exchange System are Present at the Facility

Monitoring Method Capital and 1x Costs Annualized Capital

Cost Annual Operating

Costs Total Annualized Costs Sample Events

per Year Water sampling $ 1,522 $ 371 $ 604 $ 975 1 El Paso - contracted out $ 1,522 $ 371 $ 705 $ 1,076 1 El Paso - buying system $ 8,447 $ 2,060 $ 628 $ 2,688 1 Water sampling $ 1,522 $ 371 $ 2,007 $ 2,378 4 El Paso - contracted out $ 1,522 $ 371 $ 2,346 $ 2,718 4 El Paso - buying system $ 8,447 $ 2,060 $ 1,422 $ 3,482 4 Water sampling $ 1,522 $ 371 $ 5,202 $ 5,573 12 El Paso - contracted out $ 1,522 $ 371 $ 6,179 $ 6,550 12 El Paso - buying system $ 8,447 $ 2,060 $ 2,995 $ 5,055 12 Water sampling $ 1,522 $ 371 $ 21,174 $ 21,546 52 El Paso - contracted out $ 1,522 $ 371 $ 25,339 $ 25,710 52 El Paso - buying system $ 8,447 $ 2,060 $ 10,857 $ 12,918 52 El Paso - continuous $ 25,372 $ 6,188 $ 9,343 $ 15,531 8760



### Similar cost tables to Tables 5 and 6 can be deve loped for facilities with three or more monitored heat exchange systems. Note that the monito ring cost per monitored heat exchange system decreases as the number of monitore d heat exchange systems at the facility increases. Also note that in-house modified El Paso monitoring becomes the most economical alternative as the monitoring frequency increases to monthly. Wh en there are three or more monitored heat exchange systems present at th e facility, the cost of quarterly in-house modified El Paso monitoring is comparable to the cost of quart erly water sampling or contracted El Paso monitoring services. 7. Costs of Implementing Repairs The cost of implementing repairs includes the cost of pinpointing the precis e heat exchanger that is leaking and repairing or isolating the leak. A detailed chemical analysis of the cooling water (or the purge gas when using the modified El Pa so method) can be used to pinpoint the leak when different processes may be serviced by the same heat exchange system. Although this may not always be needed ( e.g. , if only one process is serviced by the heat exchange system), a flat analytical cost of $400 was assumed to be incurred each time a leak was detected. Most of the repairs are expected to be perfor med by plugging a specific heat exchanger tube. No attempt was made to develop costs of replacing th e heat exchanger. It is assumed that a heat exchanger that is leaking to the extent that it need s to be replaced is eff ectively at the end of its useful life, so the cost of replacing the heat exchanger is an operational cost that would be

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

16 incurred by the facility as a result of routin e maintenance and equipment replacement and it is not attributable to the work pr actice standard. However, all ot her corrective acti ons taken by the facility to repair or isolate the leak are included in the costs of implementing repairs. Table 7 presents the costs estimated for the average leak requiring repair. Table 7. Summary Costs Associated with Leak Repair

Activity/Requirement Number of labor hours by labor class per year for activity/requirement Total Cost ($) Operator Maintenance Labor for finding and repairing leak 20 40 2,809 “Fingerprint” speciated sample analysis 400 Material costs for repair (assumed to equal costs for labor) 2,809 Total Repair Costs (per event) 6,018



### 8. Impact Estimates for Heat Exchange Systems Impact Model for Heat Exchange Systems The emission reductions achieved by a monito ring and repair program will depend on the monitoring frequency (how quickly a leak is identified), the size threshold of the leaks that must be repaired, and the water usage ra te (for once-through systems) or recirculation rate (for closedloop systems). To evaluate different monitoring and repair program requirements, a spreadsheet impact model was developed to estimate the cost and emission reductions achieved from the implementation of a monitoring and repair progr am. The impact model assesses the cost and emission reductions for four different sizes of heat exchange systems based on the water use or recirculation rates as follows: 5,000 gall ons per minute (gpm); 15,000 gpm; 40,000 gpm; and 110,000 gpm. An important, but uncertain, factor that affects the baseline emi ssion estimates (and therefore the potential emission reductions that can be achieved) is the distribu tion of heat exchange system leaks prior to the implementation of the monitori ng and repair program. For each model heat exchanger, six different model l eak concentrations were used to assess the impacts of a given monitoring and repair pr ogram as presented in Table 8 . Except for the lowest model leak, each model leak interval was designed to cover a factor of 5 difference in concentration ranges. Each of these leak concentration was assigned an ini tial leak frequency, which is also provided in Table 8. From these initial assumptions, the ba seline emissions for each model heat exchanger can be calculated.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

17 Table 8. Model Leak Concentration Va lues and Initial Leak Distribution

Description of Representative Leak Interval Model Leak Concentration in Cooling Water (ppbw) Initial Leak Frequency Distribution No detectable leaks (0 to 5 ppbw) 1 0.45 Leaks from >5 to 25 ppbw 10 0.25 Leaks from >25 to 125 ppbw 50 0.15 Leaks from >125 to 600 ppbw 250 0.10 Leaks from >625 to 3,000 ppbw 1,200 0.04 Leaks greater than 3,000 ppbw 6,000 0.01



### Implementation of a leak monitori ng and repair program is expected to alter the distribution of leaks in subsequent years. This pattern has been observed in the implementation of leak detection and repair (LDAR) pr ograms for equipment leaks (Parri sh et al., 2007). The leak frequency after implementation of the monitori ng and repair program was estimated from the initial leak frequency distribu tion, the leak threshold for the monitoring program, and a “leak reduction factor.” The original frequency of l eaks larger than the leak repair threshold is multiplied by this leak reduction factor to calcula te the subsequent leak frequency in Year 2 and later years. For example, using a leak reduction factor of 0.10 and an initial leak frequency of 0.04 ( i.e. , for 1,200 ppbw model leak concentration), th e subsequent leak frequency would be 0.004 (0.1×0.04). If a leak reduction factor of 0.3 is used, then th e subsequent leak frequency would be 0.012 (0.3×0.04). The cumulative leak fr equency distribution must add up to 1, so the leak frequency of leaks less than the leak repair threshold must be increased when the frequency of leaks greater than th e leak repair threshold is reduced. It was assumed that the relative distribution of leaks less than th e leak repair threshold remained the same as in the initial leak frequency distribution, but the magnitude of each leak frequency less than the repair threshold was scaled-up so that the sum of all leak freque ncies (including those above the repair threshold) equals 1. Note that the subsequent leak fr equency is applied per annual period and not per monitoring period. For example, a subsequent leak frequency of 0.012 for a model leak concentration would imply that 1.2 percent of heat exchange systems would develop a leak represented by that model leak concentration at some point during the year. Thus, the subsequent year (annual) leak fr equency distribution is independe nt of the monitoring frequency, and only varies based on the leak threshold. The sensitivity of the impact estimates on the le ak reduction factor select ed was evaluated using leak reduction factors of 0.10 and 0.30 (see Annex A – Sensitivity Analysis ). The lower (0.10) leak reduction factor resulted in only a 5 percent increase in the projected emissions reductions; however, the lower (0.10) leak reduction factor also resulted in lower implementation costs (because fewer repairs are required in subsequent years and more recovery credits are earned). Therefore, while the emission re ductions estimated by the impact s model do not appear to be highly sensitive to this parameter, this parame ter can be significant wh en evaluating the overall cost-effectiveness of a given monitoring option. A leak reduction factor of 0.3 is recommended for most analyses, and should provide a rela tively conservative estimate of the emission reductions and costs associated with a monitoring and repair option.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

18 Although each model concentration was envisioned to represent a range of concentrations, the model logic only evaluates the actual value of the model leak concentr ation with the repair threshold of the monitoring program. Therefor e, the 50 ppbw model l eak concentration may include a 100 ppbw leak concentration based on th e representative concentration range (from 25 ppbw to 125 ppbw as shown in Table 8), but since 50 ppbw is less than the 100 ppbw leak repair threshold, the 50 ppbw model leak would not trigger a required repa ir based on the logic used in the impact model. A repair of the model leak occurs when that model leak concentration equals or exceeds the repair threshold. Although the monitoring frequency does not impact the annual leak frequency distribution, it does determine how quickly a l eak will be discovered. After the implementation of the monitoring and repair program, a new leak is assu med to exist for half the monitoring frequency plus the time it takes to effect repair. For most leaks, repairs are completed 45 days after the leak monitoring event that identified th e leak (the maximum time period allowed for leak repair when criteria for delay of repair are not met). For re pairs that can be delaye d, repairs are assumed to be completed 120 days after the leak monitoring event that identified th e leak. While some repairs may be delayed for more than 120 days, this value represents the maximum delay period for repairs delayed due constraint s on the availability of parts, equipment, or personnel. The exact proportion of repairs that will be delayed is difficult to assess. Model analyses were performed at delay of repair factors of 20 and 50 percent ( i.e. , 20 percent or 50 percent of all leaks below the delay of repair threshold were delayed; see Annex A – Sensitivity Analysis ). Since all leaks are eventually repaired, the repa ir costs are not affected by the number of leaks for which repair is delayed. The emissions re ductions dropped by only 1 percent when using a 50 percent delay of repair factor . While this also causes a 1 percent change in the recovery credits, the overall model is not ve ry sensitive to this parameter. A delay of repair factor of 0.5 (50 percent) is recommended for most he at exchange system model analyses. The monitoring costs as presented in Section 6 appl y to each heat exchange system regardless of the model leak concentration or assumed leak fr equency. As noted in Section 6, the monitoring cost per heat exchange system of implementi ng a monitoring program becomes less when more than one heat exchange system is present at the facility. Most of the costs presented in this section are based on the costs determined for a si ngle heat exchange system at the facility; costs per heat exchanger would be lower if multiple he at exchange systems are present at a typical facility. For heat exchangers with model leak concentrations exceeding the repair threshold, the repair costs (presented previously in Table 7) are also added to the monitoring costs to get a total program cost for that model heat exchange syst em/leak concentration combination. The impacts of all model leak concentrations for a given mode l heat exchange system are weighted by their distribution frequency to determine an average cost per model heat exchange system for the monitoring and repair program. Process fluid that leaks into the cooling water is product lost from the industrial process. Repairing the leak results in a ne t product recovery credit because produ ct not lost as a result of a repaired leak can be sold; therefore, the mon itoring costs are offset, to some extent, by the increased product sales. The product recovery cr edit is a function of th e value of the process fluid. For this analysis, a product recovery cred it of $500 per ton of orga nic pollutant emissions reduced was used to account for the recovery of lost product fluid when the repair is fixed. For

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

19 most chemical applications, it is expected that the recovery credit will be approximately in this range. For example, organics recovered in a petroleum refinery are expected to be approximately $1.75/gallon, based on average crud e and gasoline spot prices (based on September 7, 2007 OGJ crack spread spot prices of $74.96/bbl ($1.78/gal) for brent crude and $87.04/bbl ($2.08/gal) for product value per barrel; re ported in Oil and Gas Journal, September 17, 2007, p. 90). Assuming an average petroleum refi nery process stream specific gravity of 0.75, the recovery credit is $560 per ton organic emissions reduced. Impact Model Results for Alternativ e Monitoring and Repair Programs It is anticipated that the primary variables of a monitoring and repair program would be the monitoring frequency and the leak repair threshold. While some monitoring methods may not be capable of identifying leaks at a certain leak threshold, any monito ring method can be used in the program if the method can reliably identify leaks at the repair threshold. As the cost of water sampling is similar to the cost of modified El Pa so monitoring (using the lower of contracted or in-house monitoring), the model evaluations develope d for this section assumed that modified El Paso monitoring would be used. This assumption is not intended to suggest that modified El Paso monitoring is preferred over water sampling; this assumption is used to provide a common data set with which to evaluate the affects of monitoring frequency and re pair thresholds. For each model heat exchanger, program costs we re developed for an array of monitoring frequencies ranging from annua l to continuous for four di fferent leak thresholds. Table 9 summarizes the parameters used in the analysis.

Table 9. Model Input Parameters used to A ssess Relative Importance of Leak Threshold Concentrations and Monitoring Frequency Model Input Parameter Value and Units Number of heat exchange systems at the facility 1 Monitoring frequency Varies, options are: annually; quarterly; monthly; weekly; and continuously (hourly) Leak repair threshold /delay of repair threshold Varies, option combinations are: 1,000/5,000 ppbw; 80/800 ppbw; 40/800 ppbw; and 10/800 ppbw Leak reduction factor 0.3 Repair time for normal leak events 45 days Repair time for delayed repairs 120 days Fraction of detected leaks less than the delay of repair threshold that are delayed 0.50 Organic recovery credit $500/ton



### Figures 2, 3, 4, and 5 provide the results of the model impacts for 5,000 gallon per minute (gpm), 15,000 gpm, 40,000 gpm, and 110,000 gpm model heat exchan ge systems, respectively.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

20 $

‐ $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 $18,000

‐ 0.50 1.00 1.50 2.00 Emission Reductions (tpy per model HE system)



# 5,000 GPM HE System

Annual Quarterly Monthly Weekly Continuous



### Figure 2. Impact results for 5,000 gpm model he at exchange (HE) system using the model parameters in Table 9.

$

‐ $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 $18,000

‐ 1.00 2.00 3.00 4.00 5.00 Emission Reductions (tpy per model HE system) 

# 15,000 GPM HE System

Annual Quarterly Monthly Weekly Continuous



### Figure 3. Impact results for 15,000 gpm model he at exchange (HE) system using the model parameters in Table 9.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

21 $(4,000) $(2,000) $

‐ $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000

‐ 2.00 4.00 6.00 8.00 10.00 12.00 14.00

Emission Reductions (tpy per model HE system) 

# 40,000 GPM HE System

Annual Quarterly Monthly Weekly Continuous



### Figure 4. Impact results for 40,000 gpm model he at exchange (HE) system using the model parameters in Table 9.

$(12,000) $(10,000)

$(8,000) $(6,000) $(4,000) $(2,000) $

‐ $2,000 $4,000 $6,000

‐ 5.00 10.00 15.00 20.00 25.00 30.00 35.00

Emission Reductions (tpy per model HE system) 

# 110,000 GPM HE System

Annual Quarterly Monthly Weekly Continuous



### Figure 5. Impact results for 110,000 gpm model heat exchange (HE) system using the model parameters in Table 9.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

22 The most cost-effective monitoring programs are represented by those at the bottom and right side of the graphs in Figures 1 through 4. Opti ons in the middle of the graphs are inefficient because they have higher costs but achieve less emission reductions than other monitoring programs. It is evident from the graphs presen ted in Figures 1 through 4 that lowering the leak definition (moving to the right fo r programs marked by the same-c olored symbol) is generally more cost-efficient than increasing the monitori ng frequency (shifts acro ss different-colored symbols). Based on the model inputs in Table 9, quarterly sampling with a leak definition of 40 ppbw in the water (or 3.1 ppmv in the El Paso stripping column air steam) provides essentially identical emission reduc tions (within the uncertainty of the model) at lower cost than monthly sampling with a leak defi nition of 80 ppbw in the water (o r 6.2 ppmv in stripping air). Although even lower leak definition repair thre sholds may prove cost-effective for certain applications, it is important that the leak threshol d be a factor of 2 or 3 times greater than the analytical detection limit. Otherwise, it could be difficult or impossible to conclude that a leak does not exist because the repair threshold is at or below the analytical detection limit. For typical FID gas analyzers, detecti on limits of 1 ppmv in the air ar e typical. As such, a stripping air concentration of 3.1 ppmv or ganics (as methane), which corresponds with 40 ppbw organics as methane in the cooling water, would be consid ered the lowest repair threshold level that can be routinely assessed using the modified El Pa so method. The 40 ppbw also appears to be a reasonable minimum leak defini tion repair threshold based on typical speciated organic analytical test methods. For select process str eams or pollutants, it may be possible to achieve lower detection limits on a routine basis. In this case, a 10 ppbw or lower repair threshold should be considered (in addition to a 40 ppbw repair threshold) as one of the control options. It is also clear from Figures 1 through 4 that a given mon itoring and repair program option is more cost-effective for larger heat exchange sy stems. For example, the 40,000 gpm model heat exchanger shows a net savings for annual monitori ng options and a small savings or break even costs for the quarterly monitoring options, wh ile the 110,000 gpm model h eat exchanger shows a net savings for annual, quarterly, and monthly monitoring options. Therefore, it may be appropriate to have different m onitoring frequencies for different-s ized heat exchange systems. The size-range selected for the different thre sholds will depend predominately on the typical number of heat exchange systems present at a facility within a give n source category and the recovery credit (value of the product stream). Based on Figures 1 through 4, and assuming 40 ppbw is the minimal quantifiable leak concentration, “optimal” monitoring options appe ar to include: annual at 80/800 ppbw; annual at 40/800 ppbw; quarterly at 40/800 ppbw; and monthly at 40/800 ppbw. The weekly or continuous monitoring frequency op tions greatly increase the co st of the monitoring program without significantly reducing th e emissions compared to monthl y monitoring for the model heat exchange systems evaluated in this analysis. For the single heat exchange system scenario (upper-end cost scenario), Table 10 provides detailed cost information for these “optimal” monitoring options.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

23 Table 10. Detailed Results from Op tion Cost-Effectiveness Evaluation 1

Leak Repair /Delay Threshold

(ppbw) Monitoring Frequency Model HE System

Size (gpm) Capital and 1x Costs

($) Annualized Cost w/o Recovery

Credits ($/yr) Annualized Cost w/ recovery credits ($/yr) VOC Emission Reduction (tons/yr) CostEffect ($/tons) Incremental Cost-Effect

($/tons) 5,000 gpm model heat exchange (HE) system

80/800 annual 5,000 $3,045 $2,087 $1,569 1.03 $1,517 40/800 annual 5,000 $3,045 $2,484 $1,937 1.09 $1,770 $6,172 40/800 quarterly 5,000 $3,045 $4,853 $4,179 1.35 $3,099 $8,820 40/800 monthly 5,000 $16,895 $8,136 $7,433 1.41 $5,290 $57,599 15,000 gpm model heat exchange (HE) system

80/800 annual 15,000 $3,045 $2,087 $535 3.10 $172 40/800 annual 15,000 $3,045 $2,484 $843 3.28 $257 $1,724 40/800 quarterly 15,000 $3,045 $4,853 $2,831 4.05 $700 $2,607 40/800 monthly 15,000 $16,895 $8,136 $6,028 4.22 $1,430 $18,866 40,000 gpm model heat exchange (HE) system

80/800 annual 40,000 $3,045 $2,087 $(2,052) 8.28 $(248) 40/800 annual 40,000 $3,045 $2,484 $(1,893) 8.75 $(216) $334 40/800 quarterly 40,000 $3,045 $4,853 $(541) 10.79 $(50) $665 40/800 monthly 40,000 $16,895 $8,136 $2,515 11.24 $224 $6,762 110,000 gpm model heat exchange (HE) system

80/800 annual 110,000 $3,045 $2,087 $ (9,296) 22.77 $(408) 40/800 annual 110,000 $3,045 $2,484 $ (9,554) 24.08 $(397) $ (197) 40/800 quarterly 110,000 $3,045 $4,853 $ (9,981) 29.67 $(336) $(76) 40/800 monthly 110,000 $16,895 $8,136 $ (7,320) 30.91 $(237) $2,146 1 Impacts based on single heat exchange system and model input parameters summarized in Table 9.



### Considerations of Very Small Heat Exchange Systems (“Sample Coolers”) As seen in Figures 1 through 4 and Table 10, the larger the heat ex change system, the more costeffective it is to monitor and repair leaks. C onversely, as the cooling water flow rates become smaller, it becomes less cost-effective to monitor a nd repair leaks. Logic dictates that, at some flow level, the potential emissi on reductions achieved do not jus tify the costs of the monitoring program. While this lower flow limit is unlik ely to apply to conven tional industrial heat exchange systems, small water cooling systems used to collect process samples or used in conjunction with monitoring equipment (“sample cool ers”) are expected to meet the definition of a once-through heat exchange system, and these may have very low flow rates. The impacts model was used to evaluate a potential applicabil ity flow limit for a given heat exchange system monitoring program. Model heat exchange syst em flow rates of 1, 10, 100, and 1,000 gpm were assessed in this analysis. The monitoring cost s developed for the impacts model are directly applicable to any heat exchange system; the re pair costs developed for the impacts model are potentially different. For these sample coolers, direct replacement of th e leaking cooler is the expected repair scenario. It was assumed that the repair costs for a leaking heat exchanger provided a reasonable estimate of the sample cooler replacement cost. As new equipment is expected to have a lower likelihood of leaking, a leak reduction factor of 0.1 was used for this analysis. The baseline leak distribution was also adjusted upward because these “sample

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

24 coolers” are not expected to be monitored for bi ologicals (or other potentia l leak indicators) as regularly as conventional industrial heat exchan ge systems are monitored. The high model leak concentrations (model leaks of 1.2 and 6 ppmw) were each assumed to represent 10 percent of the sample coolers. The moderate model leak concentrations (model leaks of 250 and 50 ppbw) were each assumed to represent 15 percent of the sample coolers. Even with a relatively high frequency of leaks, the cost-effectiveness of a nnual or quarterly monitoring generally exceeded $10,000 per ton VOC reduced for heat exchange syst ems with cooling water flow rates at or under 100 gpm. While there are uncertainties as sociated with applying the heat exchange impacts model for “sample coolers,” this analysis suggests that routine he at exchange monitoring programs should not apply to very small heat exchange systems or “sample coolers.” Furthermore, the analysis suggests that a reasona ble flow rate threshold for excluding “sample coolers” would be a heat exchange system with cooling water flow rate of 100 gpm or less. 9. Application of Impact Model for a Specific Source Category This section provides an exampl e of how to use the heat exch ange system impacts model to determine impacts for a specific source category. The heat exchange system impacts model is provided in a Microsoft ExcelTM workbook. This section contains numerous references to specific sheets or cells within the workbook; it may be useful to have the workbook (or “impacts model”) open for easy reference as you read this section. Step 1 . Revise the labor rates for the specific indu stry, if desired. The heat exchange system impacts model includes labor rates (in May 2009 dollars) for general ma nufacturing industry sector (2-digit NAICS code 31 to 33) in the “l abor rates” sheet within the impacts model. Industry-specific labor rates are available from the Bureau of Labor Stat istics (BLS) (U.S. DOL, 2010) for specific NAICS codes. For the NAICS code associated with the specific source category, the mean hourly labor rates for the specified SOC C ode Numbers specified in the model can be found and entered into the spread sheet. The new values should be entered in shaded cells (Cells I3 to I7 of sheet “labor rates”). If desired, the fringe be nefits loading factor and overhead and profit rate can be adjusted in the corresponding cells in columns C and D. Step 2 . Determine the number of heat exchange systems per facility for which to estimate facility costs (per heat exchange system). Th e monitoring costs are calculated in the “Cost by monitoring method” sheet. As discussed previous ly, the cost per heat exchange system is a function of the number of heat exchange systems that will need to be monitored at a specific facility. The number of heat exchange systems should be ente red in the yellow-highlighted Cell I9 in the “Cost by monito ring method” sheet. There are five monitoring frequencies evaluated in the macro: four pe riodic frequencies specified in th e green highlighted cells (Cells R9 to R12) in the “Cost by monitoring method” sheet and a continuous monitoring option. If desired, the periodic monitoring fr equencies in Cells R9 to R12 can be adjusted to evaluate different monitoring frequencies than those pre-loaded in the spread sheet. In general, no other edits should be made to this sheet. 1 

### Run the macro provided by pushing the “Generate Control_Options Costs” button to automatically calculate an array of costs for different monitoring frequencies and store the results for further use in the “Control_Options” sheet.

1 If additional edits to the costing assumptions are deemed necessary ( i.e. , hours required for training, reporting, or other elements), these should be made prior to running the “Generate Control_Option Costs” macro.

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

25 Step 3 (Optional) . Review the table starting at Cell B9 in the “Control_Options” sheet. After running the “Generate Control_Options Costs” macro, costs for the various control options (monitoring frequencies) will be generated and stor ed in this table. The “Control_Options” sheet also houses the repair cost estimates. The t op 30 rows of the “Control_Options” sheet are used in the “Cost by HEsize” sheet for projecting the impacts per model h eat exchange system. If you choose to do so, you can use subsequent rows in the “Control_Options” sh eet to store costs for previously evaluated sets of runs. One advantage of using the general manufacturing labor rates is that several cost tables are already developed and stored in this sheet; however, with the macro, these costs can be easily and quickly updated, so most users will find this step unnecessary. Step 4 . The next step in the process is to evalua te the specific options in the “Cost by HEsize” sheet. There is a drop down selection for the monitoring method and frequency in Row 10, and yellow-highlighted input selections for the leak definition (in terms of water concentration), delay of leak threshold concentration, leak redu ction factor (“Reduct_Fact or”), fraction of leaks that below the delay-of-repair threshold that ar e delayed (“Fr_Delayed”), and the VOC credit. The results of the model analysis are summarized on a per heat exchange system level for four different model heat exchange system wa ter circulation sizes: 5,000 gpm; 15,000 gpm; 40,000 gpm; and 110,000 gpm. The macro “Generate Imp act Results Summary” allows the evaluation of using modified El Paso monitoring at all frequencies included in the current “Control_Options” table. These results will be in the placed in the “Results_temp” sheet. The macro will automatically highlight the results range which can then be copied into one of the three “Results_#” sheets (where # = 1, 2, or 3) . The “Results_#” sheets are used to save the specific model run results for further analysis. Th e selected range from the “Results_temp” sheet would be copied to Cell B1, I1, P1, or W1 in one of the “Results_#” sheets as appropriate. Step 5 . Repeat Step 4 as needed for different mo del run evaluations for a given model plant ( i.e. , a given number of heat exchange systems at a fac ility). Each “Results_# ” sheet is designed to hold results for 4 different model runs. The model runs in a given sheet can be used to evaluate the effect of different leak definitions or the impact of different model assumptions ( e.g. , different leak reduction factors or differences in fraction of leaks for whic h delay of repair is used). Graphs are provided to illustrate the re sults of the different mode l runs for each of the four model heat exchange system s (see Rows 77-98). It is anticip ated that the results for any given sheet will only alter the yellow highlighted in Cells D11:G13 of the “Cost by HEsize” sheet. The results output by the macro will incl ude these inputs (along with the number of heat exchange systems per facility) for documentati on of the run results. The results summary does not store the initial leak distribution ( i.e. , the yellow highlighted in Cells M11:M16 of the “Cost by HEsize” sheet). If the initial leak distribution is varied ac ross these runs, the leak distribution should also be saved to docum ent these inputs as well. Step 6 . Repeat Steps 2 through 5 as need ed for different model plants ( i.e. , to develop impacts for different numbers of heat exchange systems per facility). It is likely that the impacts for a specific industry may entail developing costs for a variety of model plant sizes or complexities, which may require costs to be eval uated for several different number s of heat exchange systems. For example, evaluation of three different model facilities may be desired for different facility complexities: a simple model facility with one heat exchange system to be monitored; a

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

26 moderately complex facility with two heat exchange systems to be monitored; a complex facility with four heat exchange systems to be monitore d. Steps 2 through 5 would have to be repeated of each of these model plants. The three “Res ults_#” sheets were originally designed to house impact results for three different model plants , with each sheet repres enting the results for a given model plant. However, you could alternat ively use one results sh eet to house the results for a specific set of model inputs (leak definition and repair threshold), and use the four columns to house the results for different mo del plants. If this second option is used, the graphs included in the “Results_#” sheets at Row 80 will be meaningless, but it may be easier to quickly copy the selected results to the “NW_Impacts” sh eet for calculation of nationwide impacts. Step 7 . Assign a nationwide number of heat excha nge systems that can be represented by each model heat exchange system / model plant co mbination. The costs and emission reductions presented are per heat exchange system. By multiplying the costs and emission reductions by the number of heat exchange systems, nationwide impacts are developed for the source category. The “NW_Impacts” sheet provides a means to ca lculate the number of heat exchange systems represented by each model heat exchange system / model plant combination for up to four model plants. The inputs needed for these calculations ar e the total number of heat exchange systems in the source category and the rela tive distribution of heat exch ange systems by size and model plant. Note: the number of the number of h eat exchange systems used for each model plant combination is rounded to whole numbers for the impact calculations, so there may be a slight difference in the number of heat exchangers calcul ated in Cell F32 and the total number of heat exchange system input in Cell G5 due to rounding. Step 8 . Identify the specific control options for evaluation to calculate the nationwide impacts and enter those results in the “NW_Impacts” sh eet (see Cell J32). As noted previously, if a single sheet contains output for th e different model plants, it may expedite the manual process of transferring selected results to the “NW_Impacts” sheet (but the graphs in the “Results_#” sheets will be of little value). Once the impacts for th e selected control options are entered (or copied) into the “NW_Impacts” sheet, the sheet will au tomatically calculate the nationwide impacts in the final results table. 10. References Boudreaux, W. 2010. E-mail with attachment from Wayne Boudreaux, En RUD Resources, Inc., to Cindy Wang Hancy, RTI International. “CWT Estimate.” November 2, 2010. Corsi, R, et.al. 2004. Assessment of Selected Leak Detect ion, Sampling, Testing, Measurement and Monitoring Methods for Estimating Emi ssions of Highly Reactive Volatile Organic Compounds from Industrial Cooling Waters . University of Texas at Austin for TCEQ. September 2004. Docket Item No. EPA-HQ-OAR-2003-0146-0004. Lucas, B. 2008. Memorandum from B. Lucas, EPA/ SPPD, to Project Docket File (EPA Docket No. EPA-HQ-OAR-2003-0146). Cooling Towers: Contro l Alternatives and Impact Estimates . October 30, 2008. Parrish, K., D. Randall, and J. Coburn. 2007. Memorandum from Kristin Parrish, David Randall, and Jeff Coburn, RTI International, to Karen Rackley, EPA/SPPD. Final Impacts

### Technical Memorandum – Technology Re view for Heat Exchange Systems July 12, 2011

27 Analysis for Regulatory Options for Equipm ent Leaks of VOC in Petroleum Refineries

. October 30, 2007. Docket It em No. EPA-HQ-OAR-2006-0699-0089. Texas Commission on Environmen tal Quality (TCEQ). 2003. Sampling Procedures Manual, Appendix P: Air Stripping Method (Modified El Paso Method) fo r Determination of Volatile Organic Compound Emissions from Water Sources

. Suslow, Trevor V. 2004. Oxidation-Reduction Potential (ORP) for Water Disinfection Monitoring, Control, and Documentation . University of California, Davis; Division of Agriculture and Natural Resources; P ublication 8149. ISBN 978-1-60107-319-8. U.S. Department of Labor (DOL), Bureau of Labor Statistics. 2010. Occupational Employment Statistics: May 2009 Employment and Wage Estimates

. http://stats.bls.gov/oes/current/oessrci.htm ; Last accessed in December 2010.

# Technology Review for Heat Exchange Systems Annex A – Sensitivity Analysis

An impacts model was developed to estimate th e emission reductions achieved and the costs incurred for different monitoring options for heat exchange system. Th e output of the model depends, to some extent, on some of the assumptions used in the model. This Annex presents the results of various impact model runs for a heat exchange system with a cooling water flow rate of 40,000 gallon per minute (gpm) for four different monitoring options: 1. Quarterly monitoring with a leak definiti on of 80 parts per billion by weight (ppbw) strippable organics in the cooling water. 2. Quarterly monitoring with a leak definition of 40 ppbw strippable organics. 3. Monthly monitoring with a leak definiti on of 80 ppbw strippable organics. 4. Monthly monitoring with a leak definiti on of 40 ppbw strippable organics. The model itself helps to account fo r different sized heat exchange systems, different number of heat exchange systems at a given facility that require monitoring, and different monitoring frequencies and different action thresholds. There ar e other underlying assu mptions within the model that are generally fixed, and the purpose of this analysis is to assess the sensitivity of the model to these fixed assumptions. Table A-1 summarizes some of the basic default parameters for the impacts model. The time allowed for repair or for delayed repair is generally specified as part of the monitoring requirements, and these are, for the most part, li mited by the time required to identify the specific tube or heat exchanger bundle th at is leaking, order necessary pa rts (if needed), and isolate and repair the leak. Similarly, the organic recovery credit can generally be determined for a given source category based on the product value of the process fluid lost as a result of the leak. Consequently, this sensitivity analysis focuse s on the “leak reduction factor” and on the fraction of leaks for which repair can be delayed. Table A-1. Heat Exchange System Impact Model Input Parameters

Model Input Parameter Value and Units Leak reduction factor 0.3 Repair time for normal leak events 45 days Repair time for delayed repairs 120 days Fraction of detected leaks less than the delay of repair threshold that are delayed 0.50 Organic recovery credit $500/ton

### Technology Review for Heat Exchange Syst ems: Annex A – Sensitivity Analysis

A-2 Typically, when a facility implements a leak detection a nd repair program ( e.g. , for equipment leaks), the number of leaks a bove the repair threshold is reduced in subsequent monitoring events, which causes a shift in the leak distribu tion for subsequent monitoring events. A “leak reduction factor” is applied to the portion of the initial leak distribution for l eaks above the repair threshold to account for this phenomenon. A leak reduction factor of 0.3 is suggested for use in the heat exchange impacts model based on engineering judgment; th is would reduce the probability of a leak at levels above the leak repair threshold in subsequent years to 30 percent of the leaks in the baseline year. For the sensitivity analysis, the results of using this default leak reduction factor are compared to alternative le ak reduction factors of 0.1 and 0.5 for the model heat exchange system and for different monitoring options. Table A-2 summarizes the results of this analysis in terms of em issions reductions and costs. The fraction of leaks for which delay can be repair ed is another uncertain input parameter. For units that operate contin uously with minimal downtime, the fraction of leaks that may be delayed may be higher than for batch systems or pr ocesses that run conti nuously but for shorter durations. The fraction of leaks that may be dela yed may be dependent on the age of the process equipment as well. Older equipment may be more likely to need significant repair or replacement, whereas newer equipment may only need to plug a single tube in the heat exchanger. The suggested default value for the fr action of leaks that can be delayed is 0.5; for this sensitivity analysis, delay fractions of 0.2 and 0.8 were also investigated. Table A-3 summarizes the results of these impact model runs. Table A-2. Sensitivity Analys is for Leak Reduction Factor 1

Leak Reduction

Factor Capital and 1x Costs ($) Annualized Cost w/o Recovery Credits ($/yr) Annualized Cost w/ recovery credits ($/yr) VOC Emission Reduction

(tons/yr) CostEffectiveness ($/ton) Quarterly Monitoring with a Leak Action Level of 80 ppbw 0.1 $3,045 $4,312 $(1,027) 10.68 $(96) 0.3 $3,045 $4,456 $ (646) 10.20 $(63) 0.5 $3,045 $4,601 $(264) 9.73 $(27) Quarterly Monitoring with a Leak Action Level of 40 ppbw 0.1 $3,045 $4,565 $(1,089) 11.31 $(96) 0.3 $3,045 $4,853 $ (541) 10.79 $(50) 0.5 $3,045 $5,142 $7 10.27 $1 Monthly Monitoring with a Leak Action Level of 80 ppbw 0.1 $16,895 $7,594 $2,119 10.95 $194 0.3 $16,895 $7,738 $2,423 10.63 $228 0.5 $16,895 $7,883 $2,726 10.31 $264 Monthly Monitoring with a Leak Action Level of 40 ppbw 0.1 $16,895 $7,847 $2,049 11.59 $177 0.3 $16,895 $8,136 $2,515 11.24 $224 0.5 $16,895 $8,424 $2,981 10.89 $274

1 Impacts based on single 40,000 gpm heat exchange syst em with a delay of repair threshold of 800 ppbw.

### Technology Review for Heat Exchange Syst ems: Annex A – Sensitivity Analysis

A-3 Table A-3. Sensitivity Analysis for Fracti on of Leak for Which Repair is Delayed 1

Fraction Delayed Repair Capital and 1x Costs ($) Annualized Cost w/o Recovery Credits ($/yr) Annualized Cost w/ recovery credits ($/yr) VOC Emission Reduction

(tons/yr) CostEffectiveness ($/ton) Quarterly Monitoring with a Leak Action Level of 80 ppbw 0.2 $3,045 $4,456 $ (675) 10.26 $ (66) 0.5 $3,045 $4,456 $ (646) 10.20 $ (63) 0.8 $3,045 $4,456 $ (616) 10.14 $ (61) Quarterly Monitoring with a Leak Action Level of 40 ppbw 0.2 $3,045 $4,853 $ (580) 10.87 $ (53) 0.5 $3,045 $4,853 $ (541) 10.79 $ (50) 0.8 $3,045 $4,853 $ (502) 10.71 $ (47) Monthly Monitoring with a Leak Action Level of 80 ppbw 0.2 $ 16,895 $7,738 $2,393 10.69 $ 224 0.5 $ 16,895 $7,738 $2,423 10.63 $ 228 0.8 $ 16,895 $7,738 $2,452 10.57 $ 232 Monthly Monitoring with a Leak Action Level of 40 ppbw 0.2 $ 16,895 $8,136 $2,477 11.32 $ 219 0.5 $ 16,895 $8,136 $2,515 11.24 $ 224 0.8 $ 16,895 $8,136 $2,554 11.16 $ 229

1 Impacts based on single 40,000 gpm heat exchange syst em with a delay of repair threshold of 800 ppbw.



### Reviewing the results presented in Tables A-2 an d A-3, a few factors are not eworthy. First, it is clear that the model is not very sensitive to the assumed fraction of leaks for which delay of repair is allowed. Using 0.5 as the base case fo r the “fraction of delaye d repair,” altering the fraction of delayed repair causes less than a 0.1 percent change in th e emission results. For example, for quarterly sampling at a leak acti on level of 40 ppbw, the change in emissions is 0.08 tons/yr, or 0.08/10.79 = 0.7 percent. The lack of sensitivity to the fraction of delayed repair is due, in part, to the assumption in the impacts model that the delay will be for 120 days. This time period is based on a delay associated with ordering necessary equipment or scheduling specialists. Longer delays may be allowed for re pairs that require a pr ocess shutdown, but these should be a limited number of cases, and they will also be limited to leaks that do not get significantly larger over time. Long delay of repairs are not likely because a leak is likely to get worse with time and trigger the delay of repair threshold, so that the re pair can no longer be delayed. The model is more sensitive to the “leak reduction factor.” Using 0.3 as the base case for the leak reduction factor, altering th e leak reduction factor causes a 3 to 5 percent change in the emission results, with the 5 percent change associ ated with the quarterly monitoring alternatives and the 3 percent change associ ated with the monthly monitori ng alternatives. It is also interesting to note that these different degrees of sensitivity could impact what monitoring provisions achieve the greatest emission reducti on. For most options considered, quarterly monitoring at a leak action le vel of 40 ppbw provides more emission reduction than monthly

### Technology Review for Heat Exchange Syst ems: Annex A – Sensitivity Analysis

A-4 monitoring at a leak action leve l of 80 ppbw; however, at a leak reduction factor of 0.5, monthly monitoring at a leak action level of 80 ppbw is projected to achi eve slightly greater emissions reductions than quarterly monitoring at a leak ac tion level of 40 ppbw. Thes e results suggest that these two monitoring options ac hieve essentially equivalent emission reductions within the uncertainty of the analysis. Th e leak reduction factor also imp acts the costs of the monitoring program (more than just the magnitude of the recove ry credit), with higher costs (associated with more repairs) at higher leak re duction factors, so the cost-effec tiveness of an overall monitoring option is much more significantly impacted by the se lected leak reduction factor than the fraction of delayed repair. The total emission reductions achieved by a monitoring program will be very sensitive to the leak initial leak distribu tion, particularly the propor tion of larger leaks. However, most decisions are made based on incremental differences be tween monitoring options rather than total reductions achieved by any given option. For the incremental costs between control options, the initial distribution is less important than how that distribution is affected by the monitoring program itself. Thus, it is anticipated that the leak reduction factor will be as important as (or more important than) the initial distribution when evaluating the incremental cost-effectiveness of an option, and it is this incremental assessment that is most important when selecting a monitoring option. Table A-4 provides some of the same data as Table A-2, but shows the incremental costeffectiveness for two similar options (in this case , quarterly monitoring at leak action levels of 40 and 80 ppbw). The incremental emission reduc tions varied from 0.54 to 0.63 tons per year (tons/yr) and exhibited an uncertainty of approximately ± 8 pe rcent. Altering the leak reduction factor also altered th e incremental cost-effectiveness of these options by approximately ± $300/ton. Table A-4. Effect of Leak Reduction Factor on Incremental Impacts 1

Monitoring Frequency and Leak Action Level Capital and 1x Costs ($) Annualized Cost w/o Recovery Credits ($/yr) Annualized Cost w/ recovery credits ($/yr) VOC Emission Reduction

(tons/yr) CostEffectiveness ($/ton) Leak Reduction Factor of 0.1 Quarterly, 80 ppbw $3,045 $4,312 $(1,027) 10.68 $(96) Quarterly, 40 ppbw $3,045 $4,565 $(1,089) 11.31 $(96) Difference $0 $253 $(62) 0.63 $(98) Leak Reduction Factor of 0.3 Quarterly, 80 ppbw $3,045 $4,456 $ (646) 10.20 $(63) Quarterly, 40 ppbw $3,045 $4,853 $ (541) 10.79 $(50) Difference $0 $397 $105 0.59 $178 Leak Reduction Factor of 0.5 Quarterly, 80 ppbw $3,045 $4,601 $(264) 9.73 $(27) Quarterly, 40 ppbw $3,045 $5,142 $7 10.27 $1 Difference $0 $541 $271 0.54 $502

1 Impacts based on single 40,000 gpm heat exchange syst em with a delay of repair threshold of 800 ppbw.

### FROM: Jeff Coburn, RTI International TO: Brenda Shine, EPA/OAQPS FOR: EPA Docket No. EPA-HQ-OAR-2003-0146 DATE: July 13, 2011 SUBJECT: Revised Impacts for Heat Exchange Systems at Petroleum Refineries

1. Purpose This memorandum documents the costs and environmental impacts for regulatory alternatives considered for heat exchange systems at petroleum refineries. 2. Background On October 28, 2009, EPA promulgated national emissions standards for hazardous air pollutants (NESHAP) for heat exchange systems at petroleum refineries as part of EPA’s review of promulgated NESHAP. These standards requ ired monthly monitoring of heat exchange systems using the modified El Paso method (T CEQ, 2003), which is a dynamic or flow-through system for air stripping a sample of the wate r and analyzing the resultant off-gases for VOCs using a common flame ionization detector (FID) analyzer. For existing source heat exchange systems, the leak threshold that required repa ir was defined as an air concentration in the stripping column of 6.2 parts per million by volum e (ppmv) as methane or greater. For new source heat exchange systems, the leak threshol d that required repair was defined as an air concentration in the stripping column of 3.1 ppmv as methane or greater. The monthly monitoring frequency and these leak threshold levels were determined to be the maximum achievable control technology (MACT) “floor” ba sed on a review of state permit requirements (see Lucas, 2008). In reviewing these heat exchange system m onitoring requirements and considering their applicability to a wider range of industrial source categories, EPA evaluated a wider range of monitoring alternatives (Coburn, 2011) . An unexpected result of this analysis was that quarterly monitoring with a leak threshol d of 3.1 ppmv as methane in th e stripping air (equivalent to 40 parts per billion by weight (ppbw ) volatile hydrocarbons in the water) achieved equivalent emission reductions to monthly monitoring at a leak threshold of 6.2 ppmv as methane in the stripping air (or 80 ppbw volatile hydrocarbons in the water). Additionally, new information was obtained from vendors regarding co st of purchasing a modified El Paso stripping column as well as costs for outsourcing this monitoring activity. EPA is, therefore, reassessing the cost and environmental impacts of the heat exchange mon itoring requirements for petroleum refineries in light of this new information.

### Technical Memorandum – Revised Impacts for Heat Exchange Systems at Petroleum Refineries July 13, 2011

2 3. Approach The impacts model developed for heat exchange system during the technology review was used to estimate the cost and environmental impacts fo r petroleum refineries. The model was tailored to the petroleum refinery industry by updating the labor costs used in the model to labor costs specific to the petroleum industry (May 2009 do llars for NAICS code 324100) as presented in Table 1

. Table 1. Summary of 2009 Hourly Labor Rates for Petroleum Industry

Labor Class (A) Mean hourly labor rate 1 ($/hr) (B) Fringe benefit loading

rate I

Overhead and profit rate (D = A x B x C)

Loaded wage rate ($/hr) 1. Environmental Engineering (SOC Code: 17-2081) 40.45 1.5 1.4 84.95 2. Executive, administrative and managerial (SOC Code: 11-9041) 62.03 1.5 1.4 130.26 3. Administrative support, including clerical (SOC Code: 43-0000) 19.61 1.5 1.4 41.18 4. Installation, Maintenance, and Repair (SOC Code: 49-0000) 26.48 1.5 1.4 55.61 5. Refinery Operators (SOC Code: 51-8093) 28.96 1.5 1.4 60.82

1 Labor rates as reported by U.S. Department of Labor, Bu reau of Labor Statistics (U.S . DOL, 2010). Labor rates for May 2009 for petroleum industry sector: 4-digit NAICS code 324100 ( http://stats.bls.gov/oes /current/oessrci.htm accessed in March 2011).



### Based on previous analyses (Lucas, 2008), there ar e approximately 520 heat exchange systems at the roughly 150 U.S. petroleum refineries. Ba sed on the size distributi on of heat exchange systems presented by Lucas (2008) and the estimate of 520 heat exchange systems, there would be:

• 202 (38.85 percent) heat exchange system s represented by the 5,000 gpm model unit;

• 150 (28.85 percent) heat exchange system s represented by the 15,000 gpm model unit;

• 150 (28.85 percent) heat exchange system s represented by the 40,000 gpm model unit; and

• 18 (3.45 percent) heat exchange systems represented by the 100,000 gpm model unit. In the previous refinery analysis , two heat exchange systems were assumed to be in HAP service at refineries with crude capaci ty less than 75,000 barrels per ca lendar day (bbl/cd); four heat exchange systems were assumed to be in HAP se rvice at refineries with crude capacity of 75,000 to 200,000 bbl/cd; and six heat exchange system s were assumed to be in HAP service at refineries with crude capacity greater th an 200,000 bbl/cd. Based on these assumptions,

### Technical Memorandum – Revised Impacts for Heat Exchange Systems at Petroleum Refineries July 13, 2011

3 48 percent of the refineries are expected to have two affected heat exchange systems, 30.7 percent of the refineries will have four affect ed heat exchange systems, and 21.3 percent of the refineries will have six affected heat exchange systems. Therefore, costs were developed separately for these three different model facilities ( i.e. , facilities with two, four, or six affected heat exchange systems). As in the previous re finery analysis, we used $560/ton of VOC reduced as the VOC recovery credit. The baseline leak distribution was adjusted within the heat exchange impacts model so that the model’s projected emission reductions for the mo nthly monitoring alternatives matched those projected previously for petroleum refineries. The baseline leak distribution used for the estimating impacts for petroleum refineries is provided in Table 2

. Table 2. Model Leak Concentration Va lues and Initial Leak Distribution

Description of Representative Leak Interval Model Leak Concentration in Cooling Water (ppbw) Initial Leak Frequency Distribution No detectable leaks (0 to 5 ppbw) 1 0.45 Leaks from >5 to 25 ppbw 10 0.24 Leaks from >25 to 125 ppbw 50 0.15 Leaks from >125 to 600 ppbw 250 0.10 Leaks from >625 to 3,000 ppbw 1,200 0.042 Leaks greater than 3,000 ppbw 6,000 0.018



### Table 3 summarizes the other key modeling para meters used in the analysis.

Table 3. Model Input Parameters used to Es timate Impacts for Petroleum Refinery Heat Exchange System Model Input Parameter Value and Units Number of heat exc hange systems at the fa cility 2, 4, or 6 Monitoring frequency / Leak repair threshold Option 1: Monthly / 80 ppbw Option 2: Quarterly / 40 ppbw Option 3: Monthly / 40 ppbw Option 4: Continuously / 40 ppbw Delay of repair threshold 800 ppbw Leak reduction factor 0.3 Repair time for normal leak events 45 days Repair time for delayed repairs 120 days Fraction of detected leaks less than the delay of repair threshold that are delayed 0.50 Organic recovery credit $560/ton

### Technical Memorandum – Revised Impacts for Heat Exchange Systems at Petroleum Refineries July 13, 2011

4 4. Results The heat exchange impact model evaluates costs and environmental impacts on a per heat exchange system basis. The environmental impa cts per heat exchanger ar e dependent on the size of the heat exchange system, while the costs are a function of the num ber of affected heat exchange systems per facility (referred to as cost scenarios). The projected costs and environmental impacts for each model heat excha nge system in terms of system size and cost scenario were multiplied by the number of heat exchange systems expected for that size/cost scenario combination, and these results were su mmed to get a total esti mate of the costs and emissions reduction for the 520 heat exchange sy stems at the 150 petroleum refineries. The cumulative nationwide costs and emission reduc tions calculated for the petroleum refining industry for each of the control options are summarized in Table 4 . Based on the parameters used in the impacts model, a monitoring program using monthly monitoring at a leak threshold of 6.2 ppmv (as methane) in the stripping air (or 80 ppbw in the water) is expected to yield identical emission reductions to a monitoring pr ogram using quarterly monitoring at a leak threshold of 3.1 ppmv (as methane) in the strippi ng air (or 40 ppbw in the water). Most existing source petroleum refineries are expected to el ect the quarterly monito ring option, but existing source petroleum refineries that are already re quired to monitor monthly (or more frequently) due to state permit requirements are likely to us e the monthly monitoring alternative for existing sources. As seen in Table 4, the overall cost-effectiven ess of any of the mon itoring options appears reasonable. However, the incremental cost-eff ectiveness is the key indicator for comparing between similar options. Since Options 1 a nd 2 yield the same emission reductions, the incremental cost-effectiveness is undefined be tween these options. The incremental cost effectiveness for Option 3, which can be consid ered a “beyond-the-floor” option for existing sources, is approximately $6,000 per ton volatile hydrocarbon reduced. The incremental cost effectiveness for Option 4, which is the “beyond-the-floor” option for new sources, is approximately $78,000 per ton volatile hydrocarbon reduced.Technical Memorandum – Revised Impacts for HeatExchange Systems at Petroleum RefineriesJuly 13, 20115Table 4. Impacts for Petroleum Refinery Heat Exchange System Monitoring Options1Control OptionDescriptionTotal CapitalCosts($)TotalAnnualizedCosts withRecoveryCredits($/yr)NationwideEmissionsReductions(tons volatilehydrocarbons/yr)CostEffectiveness($/ton volatilehydrocarbonsreduced)IncrementalCostEffectiveness($/ton volatilehydrocarbonsreduced)NationwideEmissionsReductions(tons HAP/yr)CostEffectiveness ($/tonHAPreduced)IncrementalCostEffectiveness ($/tonHAPreduced)Option 1.Monthlymonitoring; leak at6.2 ppmv in stripping gas[Existing source MACTfloor]$ 2,550,000 $ 96,900 4,140 $ 23 $ 23 621 $ 160 $ 160Option 2.Quarterlymonitoring; leak at3.1 ppmv in stripping gas[Equivalent option tothe existing sourceMACT floor]$ 1,550,000 ($ 518,000) 4,140 ($ 125) Undefined 621 ($ 830) UndefinedOption 3.Monthlymonitoring; leak at3.1 ppmv in stripping gas[New source MACT floor]$ 2,550,000 $ 525,000 4,310 $ 120 $ 6,050 647 $ 810 $ 40,000Option 4.Continuousmonitoring; leak at3.1 ppmv in stripping gas[“Beyond-the-floor” optionfor new sources]$ 12,900,000 $ 7,270,000 4,400 $ 1,650 $ 78,200 660 $ 11,000 $ 500,000Note:6.2 ppmv (as methane) in El Paso stripping gas is equal to 80ppbw volatile hydrocarbons in the water; 3.1 ppmv (as methane)in El Paso stripping gas isequal to 40 ppbw volatile hydrocarbons in the water.All estimates based on 520 heat exchange systems nationwide;delay of repair allowed for limited cases for leaks under 62 ppmv(800 ppbw); assumes 50 percentof leaks under delay limit qualify for delay of repair; used VOCrecovery credit of $560/ton VOC; HAP emission estimates uses 15 weight percent HAP for volatilehydrocarbons based on light hydrocarbonrefinery process stream data (API, 2002).

### Technical Memorandum – Revised Impacts for Heat Exchange Systems at Petroleum Refineries July 13, 2011

6 5. References API (American Petroleum Institute). 2002. Refinery Stream Speciation . API Publication No. 4723. November 1, 2002. Coburn, J. 2011. Memorandum from J. Coburn, RT I International, to B. Shine, EPA/OAQPS, for Project Docket File (EPA Docket No. EPA-HQ-OAR-2011-0002). Technology Review for Heat Exchange Systems . July 12, 2011. Lucas, B. 2008. Memorandum from B. Lucas, EPA/ SPPD, to Project Docket File (EPA Docket No. EPA-HQ-OAR-2003-0146). Cooling Towers: Contro l Alternatives and Impact Estimates . October 30, 2008. Texas Commission on Environmen tal Quality (TCEQ). 2003. Sampling Procedures Manual, Appendix P: Air Stripping Method (Modified El Paso Method) fo r Determination of Volatile Organic Compound Emissions from Water Sources

. U.S. Department of Labor (DOL), Bureau of Labor Statistics. 2010. Occupational Employment Statistics: May 2009 Employment and Wage Estimates

. http://stats.bls.gov/oes/current/oessrci.htm ; Last accessed in March 2011.