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***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** 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 – it 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. 

EO_12866_Refinery_MACT_2060-0146_Interagencycomments and EPA response.docx
***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 NAICS1

 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 already 

in the docket as items EPAHQ-OAR-2003-0146-0229 (the 

general technology review) 

and -0230 (as applied to 

refineries). These items 

were 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 the 

emission 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 of 

existing 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 substantive 

provisions 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 interval 

and 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
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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. 
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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 legal 

basis 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
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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*** 

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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 
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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. Because 

the 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*** 

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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 
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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 number 

of 

Comment [A20]: What does 

this mean? Can we go with 

“majority” or just provide 

the number? 
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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 per 

refinery 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 
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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 
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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-
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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 
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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 
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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*** 

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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 does 

provide 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*** 

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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 
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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 
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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. 
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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 
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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. 
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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 
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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 strippable 

hydrocarbons 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 
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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 
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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 
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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 Exchange 

Systems 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 
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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 
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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 
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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 
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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 
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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
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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. 
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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 

implementing 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. 
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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. 
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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 
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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 
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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? 
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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. 
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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 the 

lower 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 October 

2009 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 
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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]: Is this true? 

Please confirm? 

Comment [BBC38]: Yes this is 

true. 
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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 less 

than 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 
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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 
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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. 
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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 
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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. 
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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]. 
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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. 

 
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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). 
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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 
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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
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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. 

* * * * * 
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(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 
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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 
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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 
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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 
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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 in 

paragraphs (e) and (f) of this section. Repair includes remonitoring at the monitoring location where the leak was 
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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 system 

is 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. 
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(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 
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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 
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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 
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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 
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delay of repair monitoring interval is the time period starting 

at 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: 
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(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 total 

strippable 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 
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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 
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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. 
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(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 and 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 national emissions standards for hazardous air 

pollutants (NESHAP) reflect advances in emissions reduction technology. Specifically, Section 

112(d)(6) of the Clean Air Act (CAA) states that “[t]he Administrator shall review, and revise as 

necessary (taking into account developments in practices, processes, and control technologies), 

emission standards promulgated under this section no less often than 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 reviews, EPA is evaluating 

key emission sources that exist across several 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 technology review for heat exchange systems. 

3. Introduction

Heat exchangers are devices or collections of devices used to transfer heat from process fluids to 

another fluid (typically air or water) without intentional direct contact 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 systems: 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 leaving the heat exchanger and then return the newly 

cooled water to the heat exchanger for reuse. For closed-loop recirculation 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 

EPA-HQ-OAR-2003-0146-0229.pdf
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

2 

river or pond water as the influent cooling fluid to the heat exchangers, 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 from 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 cooling water into the atmosphere when the water 

is exposed to air (e.g., in a cooling tower for closed-loop systems or trenches/ponds in a oncethrough system). This technology memorandum specifically considers methods to reduce 

emissions from cooling water that has unintentionally contacted a process fluid within in a heat 

exchanger. Note that intentional 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 systems generally transport the cooling 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 pollutants from the water may occur along the transport 

lines and from the surface of the holding pond or receiving water body. Some 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 for 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 interface within the transport 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 cooling 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-through cooling water sources to prevent air releases. 

Furthermore, covering these units would only serve 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 actually need treatment except for the small period 

of time a leak at the heat exchanger might exist. That is, it is not generally 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, which would require such a conveyance to be 

installed, is not generally feasible in light of the technological and economic limitations. 

Closed-loop heat exchange systems typically use closed 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 generally 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 structures (often associated with nuclear power 

plants) that use natural convection of warmed air to create air flow across the water, thereby 

cooling the water. Mechanical draft cooling towers use large fans to force air through or across 
Technical Memorandum – Technology Review 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 water. 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 exhausted 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. Emissions occur primarily 

due to volatilization of light organics from the water. A small fraction of the recirculating water 

may become entrained in the exhausted air and leave the cooling tower as a water mist. This 

water mist is commonly referred to as “drift” or “drift losses.” All pollutants 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 generally 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, which would require such 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 the volume of gas that would be required to be 

handled within the enclosure system and considering the heat transfer requirements of the 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

4 

cooling tower. While it may be technically feasible to install ducts on each exhaust fan to 

capture and route the primary exhaust gas to a single stack for potential treatment and/or release, 

such an installation still suffers from technical 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 (otherwise, the stack itself will reduce the cooling 

efficiency of the cooling tower, leading to process 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 the 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 from heat exchange systems (both once-through and 

closed-loop systems as described above), it is generally 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 system to be installed, is not feasible in light of 

the technological and economic limitations associated with atmospheric releases from heat 

exchange systems. 

Differences in emissions from once-through heat exchange systems and closed-loop heat 

exchange systems were evaluated using emission models. This evaluation was completed 

because direct emission measurements are not available for these sources (due to the 

measurement method limitations just discussed). Wastewater emission models (e.g., using mass 

transfer correlations) can be used 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 collection and holding units in once-through systems, 

highly volatile compounds are projected to be nearly 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 the 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 the uncertainty and variability of emissions from 

these sources, the emissions potential for both 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 enforce a standard of performance for heat exchange 

systems, design, equipment, work practice, and 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 unintentionally leak. Certain design or operational 
Technical Memorandum – Technology Review 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 pressure significantly exceeds 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 across the heat exchanger for both the water and 

process fluid, and most heat exchangers operate 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 pressure within the heat exchanger). It is 

conceivable that a leak into the cooling water can still occur even though the inlet water 

pressure exceeds the inlet fluid pressure. Therefore, it is necessary to specify that the 

minimum cooling water pressure at any point within the heat exchanger exceeds the 

maximum process fluid pressure within the heat exchanger. Typical language used in 

previous rules for heat exchangers describe these heat exchangers as those that “operate 

with the minimum pressure on the cooling 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 volatile) intervening cooling fluid between the 

process and the cooling water and isolates the cooling water from the process fluid. The 

intervening fluid must remain enclosed and cannot be sent through a cooling tower or 

otherwise allowed routine contact with the atmosphere; otherwise, emissions would 

simply be transferred from the cooling water release points to the intervening fluid 

release points. Provisions would be needed for draining the intervening 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 fluid pressure exceeds the water 

pressure, the intervening process fluid chamber would become filled with process fluid 

and the process fluid would leak into the cooling 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 does 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 alternatives be required for all new or 

modified sources? As process fluid pressures are dictated by process operational conditions, and 

many chemical processes operate at elevated pressure, it is impractical to require the cooling 

water supply to operate at a pressure exceeding the process fluid pressures 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, commonly available water supply systems could not supply cooling 

water at these same high pressures. Additionally, the heat exchanger housing would have to be 

designed to handle these high pressures. It would be cost-prohibitive and energy intensive to 

require heat exchanger water pressures to exceed process fluid pressures in all applications. 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

6 

The use of an intervening process fluid requires a specially designed process 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 designed to use an intervening fluid; however, the 

use of an intervening fluid generally reduces the heat transfer efficiency of the heat exchanger, so 

there are additional costs associated with using an intervening fluid because the heat exchangers 

would be larger when using an intervening fluid. It is beyond the scope of this evaluation to 

determine the precise costs associated with requiring the use of an intervening fluid, as this can 

vary significantly by size and operational 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 into the cooling water would suggest that monitoring 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 with an intervening fluid, and still incur ongoing 

costs to monitor for leaks. As described presently, 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-effectiveness 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 limited 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 implement 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 process fluids that are highly toxic or corrosive (e.g., 

hydrogen fluoride), it appears that, for typical heat exchanger systems, the use of an intervening 

fluid in new or existing heat exchangers is not practical, taking into consideration the cost of 

achieving limited emission reductions (beyond those achieved through a monitoring and repair 

program) and considering the environmental and energy impacts of such a requirement. 

Potential Monitoring Alternatives 

A variety of different work practices 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 analysis, 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 collect 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 operator can visually inspect the holding pond for a 

visible organic sheen. The presence 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 rates), monitoring of free chlorine in the cooling water, and 

monitoring of the oxidation/reduction potential of the cooling water. When a leak of a 

degradable organic pollutant occurs, the added organic matter in the cooling water causes 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

7 

increased microbial growth. The oxidation/reduction potential or free chlorine 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 growth. Microbial growth 

in the heat exchanger will reduce the heat transfer efficiency and may cause plugging of the 

water tubes. Consequently, essentially every closed-loop heat exchange system is monitored for 

microbial growth. Several consecutive days of increased biological growth or increased 

disinfectant chemical use rates would indicate a leak has occurred. Since surrogate monitoring is 

commonly performed on a daily or per shift frequency, 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 systems 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 water 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 monitoring 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 leaks 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). Consequently, 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 specific pollutants can be used to identify a leak. For example, for 

an ethylene unit, monitoring for ethylene in the cooling water leaving 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 detection 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 emissions 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-volatile 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 sampling of the cooling water leaving the heat 

exchanger may be able to identify very small leaks, but this concentration may not correlate with 

the actual emissions from the system (when assuming 100 percent emissions). Sampling can be 

performed before and after the cooling 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 reduce 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 detection limit for cresol may be less than 20 ppbw. 

Nevertheless, the elevated concentrations of cresol provide reasonable evidence that a leak 

exists. It may be reasonable to compare the concentrations 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 Review 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 highly 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 water concentration of approximately 15 ppbw. Therefore, the 

modified El Paso method provides similar detection 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 easily stripped from the cooling water in the cooling tower are 

also not fully stripped in the stripping column. While the stripping column may not exactly 

simulate the stripping efficiency of the specific cooling tower being monitored 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 leak is identified, it must be repaired or 

isolated to prevent the process fluid from contaminating 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 that is leaking can be identified, that tube can be 

plugged, thereby preventing the process 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 from service, and replaced without interruption of the process 

served by the heat exchanger. However, there can be installations where a heat exchange system 

may not have excess capacity to allow one bundle to be removed without shutting down the 

process unit. 

It takes time to identify the precise location of a leak and affect its repair. Some heat exchange 

systems may include multiple heat exchanger bundles from different processes. Speciated 

chemical analysis is typically used as a fingerprint to identify which process fluid is leaking, 

thereby identifying the likely process unit associated with the leak. 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 fairly 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 circumstance, it may be 
Technical Memorandum – Technology Review 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 days of an order, so a total repair time of 120 days should be 

sufficient to locate the leak, order the parts, and complete the repair. Delay of repairs may also 

be reasonable for small leaks that can only be repaired if the process unit is shut down. 

Requiring the unit to shut down specifically for the repair may generate more emissions than 

would occur by delaying repair. Also, requiring the unit to shut down could 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 design or operational alternatives because these 

costs can vary widely by application and are expected to be very high in most applications. 

While these equipment design or operational alternatives can be very expensive, there may be 

instances where they can be considered. For example, if a certain source category has units that 

only operate at low pressures, it may be reasonable, at least for new sources, to require that the 

water-side pressure exceed the process fluid pressure at all points in the heat exchanger. The 

equipment or design alternatives identified 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 process fluids, these alternatives are economically 

viable or needed to reduce risks associated with potential pollutant releases. 

General manufacturing industry sector 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 (technical, managerial, administrative, maintenance, and operating 

labor classes). The hourly labor rates were burdened with fringe benefits and overhead to 

calculate the loaded hourly labor rate for each labor class. The labor classes used in the analysis 

and the loaded hourly labor rate calculated for each labor class are summarized in Table 1. 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

10 

Table 1. Summary of 2009 Hourly Labor Rates 

Labor Class 

(A) 

Mean 

hourly 

labor rate1

($/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, Bureau 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 inspections and/or surrogate monitoring is already widely used in nearly 

all industrial cooling water applications. As such, there are limited 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 additional 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 and surrogate monitoring 

program. The cost of developing a QA plan is expected 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 those routinely required by the facility). 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

11 

Table 2. Summary of Costs Associated with Surrogate Monitoring 

Activity/Requirement 

Number of labor hours by labor class 

per year for activity/requirement 

Total Cost 

Technical 

Managerial 

($) 

Administrative 

Operators 

QA plan (1st 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 particular analytical method used and, for speciated 

organic analysis, the number of compounds that must be analytically determined. TOC analysis 

costs range from $50-75 per sample, and speciated 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 inlet 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 sampling 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 concentration were needed 

from the speciated organic monitoring, speciated organic monitoring would cost more than TOC 

monitoring, but if the speciated organic 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 samples 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 developing a QA plan is expected 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. Labor time is also required to collect the samples for each sampling 

event and for recordkeeping 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 Table 3 are provided per sample or sampling event 

(except for the QA plan as discussed previously and reporting costs, which are per periodic 

reporting event) so that the costs can be scaled for different monitoring frequencies. 
Technical Memorandum – Technology Review 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 

Technical 

Managerial 

Adminis-

($) 

trative 

Operators 

QA plan (1st 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+shipping+analysis+recording)+2×reporting] 5,055 

Subsequent year costs [4×(sampling+shipping+analysis+recording)+2×reporting] 2,010 

Average annualized costs [CRF1×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 personnel or the facility can hire a 

contractor to come to the facility and perform the stripping column (modified El Paso) 

monitoring without the facility purchasing the equipment. The decision to purchase the 

equipment will depend on the number of sampling events required to be performed each year. 

Stripping column equipment costs and testing fees 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 monitoring 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 costs can be scaled for different monitoring 

frequencies. 
Technical Memorandum – Technology Review 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 

Technical 

Managerial 

Adminis-

($) 

trative 

Operators 

QA plan (1st 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/event1 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+recording+review)+2×reporting+training] 1,650 

Average annualized costs [CRF2×(QA plan+column+analyzer) + subsequent year costs] 5,770 

1

 Sampling of 4 or more heat exchange systems is not expected 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. The costs of developing the 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 columns 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 for re-use. Additionally, annual training 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 this option, the equipment costs for the stripping column and FID 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

14 

analyzer would be incurred per heat exchange system rather than per facility. A shelter would be 

needed to house the stripping column system for a continuous application; the costs of such a 

shelter were estimated to be $10,000 per heat exchange system. Daily checks of the continuous 

monitoring system would also be needed to ensure the system is operating 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 and modified El Paso monitoring programs at 

different monitoring frequencies were estimated based 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 organic 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 FID 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 monitoring frequencies, semi-annual reporting was assumed to be 

required. Table 5 presents the costs of key options assuming there is only one heat exchange 

system present at the facility. Table 6 presents similar costs per monitored heat exchange 

system when 2 monitored heat exchangers are present at the facility. 

Table 5. Summary of Monitoring Costs as a Function 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 Review 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 developed for facilities with three or more monitored 

heat exchange systems. Note that the monitoring cost per monitored heat exchange system 

decreases as the number of monitored 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. When there are three or more monitored heat 

exchange systems present at the facility, the cost of quarterly in-house modified El Paso 

monitoring is comparable to the cost of quarterly water sampling or contracted El Paso 

monitoring services. 

7. Costs of Implementing Repairs

The cost of implementing repairs includes the cost of pinpointing the precise 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 Paso 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 performed by plugging a specific heat exchanger tube. No 

attempt was made to develop costs of replacing the heat exchanger. It is assumed that a heat 

exchanger that is leaking to the extent that it needs to be replaced is effectively 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 Review for Heat Exchange Systems 

July 12, 2011 

16 

incurred by the facility as a result of routine maintenance and equipment replacement and it is 

not attributable to the work practice standard. However, all other corrective actions 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 monitoring 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 rate (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 program. 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 gallons per minute (gpm); 15,000 gpm; 40,000 gpm; and 

110,000 gpm. 

An important, but uncertain, factor that affects the baseline emission estimates (and therefore the 

potential emission reductions that can be achieved) is the distribution of heat exchange system 

leaks prior to the implementation of the monitoring and repair program. For each model heat 

exchanger, six different model leak concentrations were used to assess the impacts of a given 

monitoring and repair program 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 initial leak frequency, which is also provided in 

Table 8. From these initial assumptions, the baseline emissions for each model heat exchanger 

can be calculated. 
Technical Memorandum – Technology Review for Heat Exchange Systems 

July 12, 2011 

17 

Table 8. Model Leak Concentration Values 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 monitoring 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) programs for equipment leaks (Parrish et al., 2007). The leak 

frequency after implementation of the monitoring and repair program was estimated from the 

initial leak frequency distribution, the leak threshold for the monitoring program, and a “leak 

reduction factor.” The original frequency of leaks larger than the leak repair threshold is 

multiplied by this leak reduction factor to calculate 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), the subsequent leak frequency would be 

0.004 (0.1×0.04). If a leak reduction factor of 0.3 is used, then the subsequent leak frequency 

would be 0.012 (0.3×0.04). The cumulative leak frequency 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 the leak repair threshold is reduced. It was assumed that the relative 

distribution of leaks less than the 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 frequencies (including those above the repair threshold) 

equals 1. Note that the subsequent leak frequency 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 frequency distribution is independent of the monitoring frequency, 

and only varies based on the leak threshold. 

The sensitivity of the impact estimates on the leak reduction factor selected 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 reductions estimated by the impacts model do not appear to be 

highly sensitive to this parameter, this parameter can be significant when 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 relatively conservative estimate of the emission 

reductions and costs associated with a monitoring and repair option. 
Technical Memorandum – Technology Review 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 concentration with the repair 

threshold of the monitoring program. Therefore, the 50 ppbw model leak concentration may 

include a 100 ppbw leak concentration based on the 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 repair 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 leak will be discovered. After the implementation of the 

monitoring and repair program, a new leak is assumed 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 the leak (the maximum time period allowed for leak repair when 

criteria for delay of repair are not met). For repairs that can be delayed, repairs are assumed to 

be completed 120 days after the leak monitoring event that identified the leak. While some 

repairs may be delayed for more than 120 days, this value represents the maximum delay period 

for repairs delayed due constraints 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 repair costs are not affected by the number of leaks 

for which repair is delayed. The emissions reductions 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 very sensitive to this parameter. A delay of repair factor of 0.5 

(50 percent) is recommended for most heat exchange system model analyses. 

The monitoring costs as presented in Section 6 apply to each heat exchange system regardless of 

the model leak concentration or assumed leak frequency. As noted in Section 6, the monitoring 

cost per heat exchange system of implementing 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 single heat exchange system at the facility; costs 

per heat exchanger would be lower if multiple heat 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 system/leak concentration combination. The impacts 

of all model leak concentrations for a given model 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 net product recovery credit because product not lost as a result of a 

repaired leak can be sold; therefore, the monitoring costs are offset, to some extent, by the 

increased product sales. The product recovery credit is a function of the value of the process 

fluid. For this analysis, a product recovery credit of $500 per ton of organic pollutant emissions 

reduced was used to account for the recovery of lost product fluid when the repair is fixed. For 
Technical Memorandum – Technology Review 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 crude 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; reported in Oil and Gas Journal, September 

17, 2007, p. 90). Assuming an average petroleum refinery process stream specific gravity of 

0.75, the recovery credit is $560 per ton organic emissions reduced. 

Impact Model Results for Alternative 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 monitoring 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 Paso monitoring (using the lower of contracted or 

in-house monitoring), the model evaluations developed 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 repair thresholds. For 

each model heat exchanger, program costs were developed for an array of monitoring 

frequencies ranging from annual to continuous for four different leak thresholds. Table 9 

summarizes the parameters used in the analysis. 

Table 9. Model Input Parameters used to Assess 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 exchange systems, respectively. 
Technical Memorandum – Technology Review 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 heat 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 heat exchange (HE) system using the model 

parameters in Table 9. 
Technical Memorandum – Technology Review 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 heat 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 Review 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. Options 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 presented in Figures 1 through 4 that lowering the leak 

definition (moving to the right for programs marked by the same-colored symbol) is generally 

more cost-efficient than increasing the monitoring frequency (shifts across 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 reductions (within the uncertainty of the model) at lower cost than 

monthly sampling with a leak definition of 80 ppbw in the water (or 6.2 ppmv in stripping air). 

Although even lower leak definition repair thresholds may prove cost-effective for certain 

applications, it is important that the leak threshold 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, detection limits of 1 ppmv in the air are typical. As such, a stripping 

air concentration of 3.1 ppmv organics (as methane), which corresponds with 40 ppbw organics 

as methane in the cooling water, would be considered the lowest repair threshold level that can 

be routinely assessed using the modified El Paso method. The 40 ppbw also appears to be a 

reasonable minimum leak definition repair threshold based on typical speciated organic 

analytical test methods. For select process streams 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 monitoring and repair program option is 

more cost-effective for larger heat exchange systems. For example, the 40,000 gpm model heat 

exchanger shows a net savings for annual monitoring options and a small savings or break even 

costs for the quarterly monitoring options, while the 110,000 gpm model heat exchanger shows a 

net savings for annual, quarterly, and monthly monitoring options. Therefore, it may be 

appropriate to have different monitoring frequencies for different-sized heat exchange systems. 

The size-range selected for the different thresholds will depend predominately on the typical 

number of heat exchange systems present at a facility within a given 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 appear 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 options greatly increase the cost of the monitoring program 

without significantly reducing the emissions compared to monthly 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 Review for Heat Exchange Systems 

July 12, 2011 

23 

Table 10. Detailed Results from Option Cost-Effectiveness Evaluation1

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 exchange system, the more costeffective it is to monitor and repair leaks. Conversely, as the cooling water flow rates become 

smaller, it becomes less cost-effective to monitor and repair leaks. Logic dictates that, at some 

flow level, the potential emission reductions achieved do not justify the costs of the monitoring 

program. While this lower flow limit is unlikely to apply to conventional industrial heat 

exchange systems, small water cooling systems used to collect process samples or used in 

conjunction with monitoring equipment (“sample coolers”) 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 applicability flow limit for a given heat exchange system 

monitoring program. Model heat exchange system flow rates of 1, 10, 100, and 1,000 gpm were 

assessed in this analysis. The monitoring costs developed for the impacts model are directly 

applicable to any heat exchange system; the repair costs developed for the impacts model are 

potentially different. For these sample coolers, direct replacement of the 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 Review for Heat Exchange Systems 

July 12, 2011 

24 

coolers” are not expected to be monitored for biologicals (or other potential leak indicators) as 

regularly as conventional industrial heat exchange 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 annual or quarterly monitoring generally exceeded 

$10,000 per ton VOC reduced for heat exchange systems with cooling water flow rates at or 

under 100 gpm. While there are uncertainties associated with applying the heat exchange 

impacts model for “sample coolers,” this analysis suggests that routine heat exchange monitoring 

programs should not apply to very small heat exchange systems or “sample coolers.” 

Furthermore, the analysis suggests that a reasonable 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 example of how to use the heat exchange 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 industry, if desired. The heat exchange system 

impacts model includes labor rates (in May 2009 dollars) for general manufacturing industry 

sector (2-digit NAICS code 31 to 33) in the “labor rates” sheet within the impacts model. 

Industry-specific labor rates are available from the Bureau of Labor Statistics (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 Code Numbers specified in the 

model can be found and entered into the spreadsheet. The new values should be entered in 

shaded cells (Cells I3 to I7 of sheet “labor rates”). If desired, the fringe benefits 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). The monitoring costs are calculated in the “Cost by 

monitoring method” sheet. As discussed previously, 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 entered in the yellow-highlighted 

Cell I9 in the “Cost by monitoring method” sheet. There are five monitoring frequencies 

evaluated in the macro: four periodic frequencies specified in the green highlighted cells (Cells 

R9 to R12) in the “Cost by monitoring method” sheet and a continuous monitoring option. If 

desired, the periodic monitoring frequencies in Cells R9 to R12 can be adjusted to evaluate 

different monitoring frequencies than those pre-loaded in the spreadsheet. 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 Review 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 stored in this table. The “Control_Options” sheet 

also houses the repair cost estimates. The top 30 rows of the “Control_Options” sheet are used 

in the “Cost by HEsize” sheet for projecting the impacts per model heat exchange system. If you 

choose to do so, you can use subsequent rows in the “Control_Options” sheet 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 evaluate 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 reduction factor (“Reduct_Factor”), fraction of leaks 

that below the delay-of-repair threshold that are 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 water circulation sizes: 5,000 gpm; 15,000 gpm; 40,000 

gpm; and 110,000 gpm. The macro “Generate Impact 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. The 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 model run evaluations for a given model plant (i.e., 

a given number of heat exchange systems at a facility). 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 which delay of repair is 

used). Graphs are provided to illustrate the results of the different model runs for each of the 

four model heat exchange systems (see Rows 77-98). It is anticipated 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 include these inputs (along with the number of heat 

exchange systems per facility) for documentation 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 across these runs, the leak distribution 

should also be saved to document these inputs as well. 

Step 6. Repeat Steps 2 through 5 as needed 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 evaluated for several different numbers 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 Review 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 monitored. Steps 2 through 5 would have to be repeated 

of each of these model plants. The three “Results_#” sheets were originally designed to house 

impact results for three different model plants, with each sheet representing the results for a 

given model plant. However, you could alternatively use one results sheet 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 model 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” sheet for calculation of nationwide impacts. 

Step 7. Assign a nationwide number of heat exchange systems that can be represented by each 

model heat exchange system / model plant combination. 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 calculate 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 are the total number of heat exchange systems in 

the source category and the relative distribution of heat exchange systems by size and model 

plant. Note: the number of the number of heat 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 calculated 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” sheet (see Cell J32). As noted previously, if a 

single sheet contains output for the 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 the selected control options are entered (or copied) 

into the “NW_Impacts” sheet, the sheet will automatically calculate the nationwide impacts in 

the final results table. 

10. References

Boudreaux, W. 2010. E-mail with attachment from Wayne Boudreaux, EnRUD Resources, Inc., 

to Cindy Wang Hancy, RTI International. “CWT Estimate.” November 2, 2010. 

Corsi, R, et.al. 2004. Assessment of Selected Leak Detection, Sampling, Testing, Measurement 

and Monitoring Methods for Estimating Emissions 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: Control 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 Review for Heat Exchange Systems 

July 12, 2011 

27 

Analysis for Regulatory Options for Equipment Leaks of VOC in Petroleum Refineries. 

October 30, 2007. Docket Item No. EPA-HQ-OAR-2006-0699-0089. 

Texas Commission on Environmental Quality (TCEQ). 2003. Sampling Procedures Manual, 

Appendix P: Air Stripping Method (Modified El Paso Method) for 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; Publication 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 the emission reductions achieved and the costs 

incurred for different monitoring options for heat exchange system. The 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 definition 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 definition of 80 ppbw strippable organics. 

4. Monthly monitoring with a leak definition of 40 ppbw strippable organics. 

The model itself helps to account for 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 are other underlying assumptions 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, limited by the time required to identify the specific 

tube or heat exchanger bundle that is leaking, order necessary parts (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 focuses 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 Systems: Annex A – Sensitivity Analysis 

A-2 

Typically, when a facility implements a leak detection and repair program (e.g., for equipment 

leaks), the number of leaks above the repair threshold is reduced in subsequent monitoring 

events, which causes a shift in the leak distribution for subsequent monitoring events. A “leak 

reduction factor” is applied to the portion of the initial leak distribution for leaks 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; this 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 leak 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 emissions reductions and costs. 

The fraction of leaks for which delay can be repaired is another uncertain input parameter. For 

units that operate continuously with minimal downtime, the fraction of leaks that may be delayed 

may be higher than for batch systems or processes that run continuously but for shorter 

durations. The fraction of leaks that may be delayed 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 fraction 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 Analysis for Leak Reduction Factor1

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 system with a delay of repair threshold of 800 ppbw. 
Technology Review for Heat Exchange Systems: Annex A – Sensitivity Analysis 

A-3 

Table A-3. Sensitivity Analysis for Fraction of Leak for Which Repair is Delayed1

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 system with a delay of repair threshold of 800 ppbw. 

Reviewing the results presented in Tables A-2 and A-3, a few factors are noteworthy. 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 for the “fraction of delayed repair,” altering the 

fraction of delayed repair causes less than a 0.1 percent change in the emission results. For 

example, for quarterly sampling at a leak action 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 repairs that require a process 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 repair 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 the leak reduction factor causes a 3 to 5 percent change in the 

emission results, with the 5 percent change associated with the quarterly monitoring alternatives 

and the 3 percent change associated with the monthly monitoring alternatives. It is also 

interesting to note that these different degrees of sensitivity could impact what monitoring 

provisions achieve the greatest emission reduction. For most options considered, quarterly 

monitoring at a leak action level of 40 ppbw provides more emission reduction than monthly 
Technology Review for Heat Exchange Systems: Annex A – Sensitivity Analysis 

A-4 

monitoring at a leak action level 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 achieve slightly greater emissions 

reductions than quarterly monitoring at a leak action level of 40 ppbw. These results suggest that 

these two monitoring options achieve essentially equivalent emission reductions within the 

uncertainty of the analysis. The leak reduction factor also impacts the costs of the monitoring 

program (more than just the magnitude of the recovery credit), with higher costs (associated with 

more repairs) at higher leak reduction factors, so the cost-effectiveness of an overall monitoring 

option is much more significantly impacted by the selected 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 distribution, particularly the proportion of larger leaks. However, most decisions 

are made based on incremental differences between 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 reductions varied from 0.54 to 0.63 tons per year 

(tons/yr) and exhibited an uncertainty of approximately ± 8 percent. Altering the leak reduction 

factor also altered the incremental cost-effectiveness of these options by approximately 

± $300/ton. 

Table A-4. Effect of Leak Reduction Factor on Incremental Impacts1

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 system 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 required monthly monitoring of heat exchange 

systems using the modified El Paso method (TCEQ, 2003), which is a dynamic or flow-through 

system for air stripping a sample of the water 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 repair was defined as an air concentration in the 

stripping column of 6.2 parts per million by volume (ppmv) as methane or greater. For new 

source heat exchange systems, the leak threshold 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” based on a review of state permit requirements 

(see Lucas, 2008). 

In reviewing these heat exchange system monitoring 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 threshold of 3.1 ppmv as methane in the 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 cost 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 monitoring requirements for petroleum refineries in 

light of this new information. 

EPA-HQ-OAR-2003-0146-0230.pdf
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 for 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 dollars 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 

rate1

($/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, Bureau 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 are approximately 520 heat exchange systems at 

the roughly 150 U.S. petroleum refineries. Based on the size distribution 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 systems represented by the 5,000 gpm model unit; 

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

• 150 (28.85 percent) heat exchange systems 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 capacity less than 75,000 barrels per calendar day (bbl/cd); four heat 

exchange systems were assumed to be in HAP service at refineries with crude capacity of 75,000 

to 200,000 bbl/cd; and six heat exchange systems were assumed to be in HAP service at 

refineries with crude capacity greater than 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 affected 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 refinery 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 monthly 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 Values 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 parameters used in the analysis. 

Table 3. Model Input Parameters used to Estimate Impacts for Petroleum Refinery Heat 

Exchange System 

Model Input Parameter Value and Units 

Number of heat exchange systems at the facility 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 impacts per heat exchanger are dependent on the size 

of the heat exchange system, while the costs are a function of the number of affected heat 

exchange systems per facility (referred to as cost scenarios). The projected costs and 

environmental impacts for each model heat exchange 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 summed to get a total estimate of the costs and 

emissions reduction for the 520 heat exchange systems at the 150 petroleum refineries. The 

cumulative nationwide costs and emission reductions 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 program using quarterly monitoring at a leak 

threshold of 3.1 ppmv (as methane) in the stripping air (or 40 ppbw in the water). Most existing 

source petroleum refineries are expected to elect the quarterly monitoring option, but existing 

source petroleum refineries that are already required to monitor monthly (or more frequently) 

due to state permit requirements are likely to use the monthly monitoring alternative for existing 

sources. 

As seen in Table 4, the overall cost-effectiveness of any of the monitoring options appears 

reasonable. However, the incremental cost-effectiveness is the key indicator for comparing 

between similar options. Since Options 1 and 2 yield the same emission reductions, the 

incremental cost-effectiveness is undefined between these options. The incremental cost 

effectiveness for Option 3, which can be considered 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 Heat Exchange Systems at Petroleum Refineries 

July 13, 2011 

5 

Table 4. Impacts for Petroleum Refinery Heat Exchange System Monitoring Options

Control Option 

Description 

Total Capital 

Costs 

($) 

Total 

Annualized 

Costs with 

Recovery 

Credits 

($/yr) 

Nationwide 

Emissions 

Reductions 

(tons volatile 

hydrocarbons 

/yr) 

CostEffectiveness 

($/ton volatile 

hydrocarbons 

reduced) 

Incremental 

CostEffectiveness 

($/ton volatile 

hydrocarbons 

reduced) 

Nationwide 

Emissions 

Reductions 

(tons HAP 

/yr) 

Ef

nes

re

Option 1. Monthly monitoring; leak at 6.2 ppmv in stripping gas [Existing source MACT floor] 

$ 2,550,000 $ 96,900 4,140 $ 23 $ 23 621 $ 

Option 2. Quarterly monitoring; leak at 3.1 ppmv in stripping gas [Equivalent option to the existing source MACT floor] 

$ 1,550,000 ($ 518,000) 4,140 ($ 125) Undefined 621 ($ 

Option 3. Monthly monitoring; leak at 3.1 ppmv in stripping gas [New source MACT floor] 

$ 2,550,000 $ 525,000 4,310 $ 120 $ 6,050 647 $ 

Option 4. Continuous monitoring; leak at 3.1 ppmv in stripping gas [“Beyond-the-floor” option for new sources] 

$ 12,900,000 $ 7,270,000 4,400 $ 1,650 $ 78,200 660 $ 

Note: 6.2 ppmv (as methane) in El Paso stripping gas is equal to 80 ppbw volatile hydrocarbons in the water; 3.1 ppmv (as methane) in equal 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 pof leaks under delay limit qualify for delay of repair; used VOC recovery credit of $560/ton VOC; HAP emission estimates uses 15 weighhydrocarbons based on light hydrocarbon refinery 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, RTI 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: Control Alternatives and Impact 

Estimates. October 30, 2008. 

Texas Commission on Environmental Quality (TCEQ). 2003. Sampling Procedures Manual, 

Appendix P: Air Stripping Method (Modified El Paso Method) for 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.