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OAR Box 1170 

Prepped by Ollie Stewart 

Document Number: 

183)IV-H-1 

Docket Number: 

A-88-24 

Printed 4/30/2008 1:48:38 PM Sheet 183 of 188 
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6560-50 

ENVIRONMENTAL PROTECTION AGENCY 

[40 CFR Part 60] 

STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

Amendments to Subpart J (Petroleum Refineries) 

and Addition of Performance Specification 7 to Apper 

[AD-FRL- ] 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: The purpose of this action is five-fold: (1) td^fequire (as 

opposed to being an option) the monitoring of sulfur dioxide (S02) in gases 

discharged into the atmosphere from the combustion of fuel gases or, as an 

alternative, the monitoring of hydrogen sulfide (H2S) in fuel gases; (2) to 

delete the mention of controlling S02 after combustion of fuel gases; (3) to 

delete the monitoring requirement of H2S in gases discharged into the 

atmosphere from Claus sulfur recovery plants, but require the monitoring of 

other reduced sulfur compounds using continuous emission monitoring systems 

(CEMS's) or S02 CEMS's after oxidizing the reduced sulfur compounds to S02; 

(4) to add Performance Specification (PS) 7 for H2S CEMS's to Appendix B of 

this part; and (5) to clarify ambiguities in the existing regulations. All 

affected fuel gas combustion devices and Claus plants in petroleum refineries, 

subject to Subpart J of 40 CFR Part 60, will be required to install and 

operate CEMS's within 1 year of the promulgation date. These monitoring 

requirements are not new, but previous H2S and reduced sulfur CEMS 

installations were contingent upon the Agency's promulgation of PS's. These 

amendments were published in the FEDERAL REGISTER on March 1, 1989 and 

April 28, 1989. 
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DATES: Effective Date: (date of publication in the 

FEDERAL REGISTER). 

Judicial Review: Under Section 307(b)(1) of the Clean Air Act, judicial 

review of the actions taken by this notice is available only by the filing of 

a petition for review in the U.S. Court of Appeals for the District of 

Columbia Circuit within 60 days of today's publication of this rule. Under 

Section 307(b)(2) of the Clean Air Act, the requirements that are the subject 

of today's notice may not be challenged later in civil or criminal proceedings 

brought by EPA to enforce these requirements. 

ADDRESSES: Docket. Docket No. A-88-24, containing materials relevant to 

this rulemaking, is available for public inspection and copying between 

8:30 a.m. and 3:30 p.m., Monday through Friday, at EPA's Air Docket Section, 

Room M-1500, 1st Floor, Waterside Mall, 401 M Street, S.W., Washington, D.C. 

20460. A reasonable fee may be charged for copying. 

FOR FURTHER INFORMATION CONTACT: Foston Curtis or Roger T. Shigehara, 

Emission Measurement Branch (MD-19), Technical Support Division, U.S. 

Environmental Protection Agency, Research Triangle Park, North Carolina 27711, 

telephone number (919) 541-1063. 

SUPPLEMENTARY INFORMATION: 

I. THE RULEMAKING 

The present monitoring requirements for fuel gas combustion devices under 

§ 60.105(a)(3) and (4) allow the options of monitoring S02 after fuel gases 

are combusted or monitoring H2S in the fuel gases. Since October 6, 1975 

(40 FR 46250), affected facilities choosing to monitor H2S in the fuel gases 

have been exempted from the monitoring requirements of § 60.105(a)(4) because 

PS's for H2S CEMS's had not been established. This rulemaking will amend the 
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emission monitoring requirements to end this exemption. The effect of this 

rulemaking will be to require affected facilities to monitor S02 after fuel 

gas combustion or, as an alternative, H2S in the fuel gas. 

When fuel gases are burned in a combustion device, the H2S is converted 

to S02. The resulting S02 concentration is substantially less than the 

corresponding H2S in the fuel gas due to dilution from added combustion air. 

The amount of dilution air required for complete fuel gas combustion hinges 

upon the makeup of fuel gas components (primarily hydrogen and hydrocarbons) 

and their stoichiometric need for oxygen. The EPA investigated a number of 

typical fuel gas compositions and their combustion products and determined 

that, at zero percent excess air, the concentration of S02 formed from 

combusting fuel gas containing H2S at the standard level (162 ppm) ranged from 

9 to 25 ppm with the majority of values between 15 and 20 ppm. This agrees 

with the 15- to 20-ppm S02 level noted in the background document to the 

proposed petroleum refineries standard. 

Realizing the complexity of establishing the S02/H2S equivalency on a 

case-by-case basis, EPA has selected 20 ppm to represent the compliance level 

for S02. In addition, rather than requiring monitoring of the effluent after 

each combustion device, EPA is allowing the monitoring of S02 after only one 

of the combustion devices as long as that one location accurately represents 

the fuel gas being burned by all of the combustion devices. 

During 1978 and 1982, EPA conducted evaluations of H2S CEMS's and 

concluded that acceptable H2S CEMS's were not available (see Section 4 of 

PS 7). However, a State agency and a local agency reported that H2S CEMS's 

have been installed under their jurisdiction that are operating 

satisfactorily. Certification test reports that have been submitted for 
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Agency review indicate that, at least in these cases, acceptable CEMS accuracy 

and calibration drift (CD) are attainable. Other data from regulatory 

agencies have shown varying degrees of success in certifying and auditing H2S 

CEMS's. Most of these data were taken from H2S CEMS's of the same type, and 

instrument performance appears to be linked to operator and maintenance 

proficiency. Thus, EPA has decided to allow the use of H2S CEMS's for fuel 

gases as an alternative to S02 CEMS's for combusted fuel gases. For this 

purpose, PS 7 was proposed. 

In reviewing the regulations, EPA determined that the option of 

controlling S02 after combusting the fuel gases was not being used. Also, 

this option does not appear to be an economically feasible alternative for 

future consideration. Therefore, mention of this control option is being 

deleted from the regulation. This action, however, does not prohibit the use 

of such control devices. In the future, sources that desire to burn fuel 

gases containing H2S in excess of 230 mg/dscm and control the resulting S02 

emissions may petition the Administrator for an alternative compliance 

demonstration. 

Hydrogen sulfide and reduced sulfur emitted from Claus plants are 

regulated by standards set at 10 and 300 ppm, respectively. Reduced sulfur 

compounds, though determined separately from H2S, are also inclusive of H2S by 

definition. The Agency has determined that it is difficult to monitor the 

disproportionate concentrations of H2S and other reduced sulfur compounds on a 

continual basis, especially at levels near the standards. Therefore, a 

separate determination of H2S apart from other reduced sulfur compounds will 
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not be required, but only the continuous monitoring of reduced sulfur 

compounds. Performance Specification 5 and Method 15 or 15A will be used to 

evaluate the reduced sulfur CEMS performance. 

For greater flexibility, CEMS that oxidizes the reduced sulfur to S02 and 

analyzes the concentration of the resulting S02 will be allowed. Rather than 

trying to determine the concentration of S02 equivalent to the reduced sulfur 

concentration, EPA will use the level of 250 ppm S02 (dry basis, zero percent 

excess air) to represent the S02 compliance level. This concentration is 

consistent with the control option of combusting the effluent gases under 

§ 60.102(a)(2)(i). 

In addition to the above changes, ambiguities in the existing regulations 

are being clarified by correcting inconsistencies and by specifying pertinent 

testing procedures that originally were only implied. 

This rulemaking does not impose emission measurement requirements beyond 

those specified in the current regulations, neither does it change any 

emission standard nor make it more stringent. Rather, the rulemaking will 

facilitate the use of acceptable CEMS's and allow affected facilities to 

comply with monitoring requirements to which they are already subject. 

II. PUBLIC PARTICIPATION 

The opportunity to hold public hearings at 10:00 a.m. on March 22, 1989 

for the proposed Subpart J revisions and May 19, 1989 for proposed PS 7 was 

presented but no one desired to make an oral presentation. The public comment 

periods were from March 1 to July 12, 1989 for the Subpart J revisions and 

from April 28 to July 12, 1989 for PS 7. 
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III. SIGNIFICANT COMMENTS AND CHANGES TO THE PROPOSED RULEMAKING 

Seven comment letters were received from the proposal of the rulemakings. 

The major comments and responses are summarized in this preamble. Most of the 

comment letters contained multiple comments. The significant comments and 

subsequent method changes are listed here. 

1. One commenter requested that permeation tube calibration systems and 

scrubbers be allowed as alternatives to Methods 3, 6, and 11 for span 

calibration and zero checks of CEMS's. The commenter noted that commercially 

available systems have been found to be extremely accurate and reliable for 

fuel gas and Claus plant units and are far superior to older, labor-intensive, 

wet-chemical procedures. 

Approving alternatives for specific calibration systems beyond the EPA 

reference methods is not within the scope of the rulemaking. Written requests 

for approval should be submitted to the Director of EPA's Technical Support 

Division. The request must include a clearly defined procedure that can be 

uniformly followed, supporting data showing the alternative's comparability to 

the reference method, and procedures addressing the appropriate quality 

assurance (QA) measures. 

2. Another commenter strongly urged EPA to take a "more reasonable" 

approach to the exemption from the CO CEMS requirement provided in 

60.105(a)(2)(ii). The following reasons were offered to support this stand: 

a. A demonstration that CO emissions are less than 50 ppm was 

thought to be excessively restrictive. Instead, a limit of 30 percent of the 

standard should be ample to show that a unit is designed for high-efficiency 

regeneration and that a CEMS is not warranted. 
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b. Requiring 30 days of continuous monitoring data to demonstrate a 

CEMS would not be necessary. Although this may be desirable in some 

instances, it was recommended that performance test data be allowed in lieu of 

continuous monitoring data. 

c. The language in § 60.105(a)(2)(ii) needs clarifying to require 

that EPA issue an exemption when the required information is submitted with 

the written request. As proposed, a lack of response from EPA would leave the 

owner or operator in an unclear compliance status. 

d. It was not clear to the commenter if any additional requirements 

with the revisions [i.e., CEMS relative accuracy (RA) demonstrations] affect 

owners or operators who submitted requests for exemption under the existing 

requirements. 

The Method 6 flow rate of 2 liters/min in § 60.105(a)(3)(iii) was 

questioned. With the Method 6 detection limit at 3.4 mg S02 when sampling at 

1 liter/min for 20 minutes, it was not understood why a larger sample was 

needed, since this is approximately 6 percent of the 20 ppm standard. This 

change was considered an added complication, and it was recommended that it be 

reconsidered. If this change could be truly justified, some flexibility in 

the sampling flow rate was requested, such as "approximately 2 liters/min." 

Finally, the commenter objected to what was thought to be a change to 

rolling 3-hour averaging periods for determining compliance with 

§ 60.105(a)(3) and (4). It was noted that no rationale for this change was 

discussed in the supplementary information, and that this was clearly an added 

recordkeeping requirement, not a clarification. Current rules were thought to 

require that monitoring records be kept for 3-hour block periods, of which 

there are eight per day. A 1986 EPA memorandum to directors of EPA Regional 
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air divisions was cited as evidence of the EPA policy of using block averages. 

By increasing the requirement to rolling 3-hour periods, the Agency would 

cause a threefold increase to the recordkeeping burden and a triple counting 

of any extended periods of excess emissions. 

The proposed rule does not change the CEMS exemption requirements nor the 

averaging period of the existing regulation. Therefore, comments to these 

points and any subsequent changes based on the comments are beyond the scope 

of this rulemaking. 

Concerning the issuance of an exemption, the intent of the wording in 

60.105(a)(2)(ii) is to note that the exemption is contingent upon the Agency's 

decision after reviewing the submitted demonstration data and exemption 

request, not upon its submission. Mentioning that an exempted source is not 

required to perform additional CEMS testing requirements is not necessary 

since an exemption from monitoring implies that no CEMS will be installed to 

further test. Under normal situations, a source that has submitted an 

exemption request is not required to perform additional testing until the 

Agency makes a decision. In some cases though, the Agency may need to request 

interim tests. However, if the decision is such that a CEMS must be 

installed, this CEMS may be subjected to an RA test. 

The requirement in 60.105(a)(3)(iii) to operate Method 6 at 2 liters/min 

for at least 30 minutes was made to minimize the analytical error that results 

from measuring small titration volumes. For routine Method 6 analyses, sample 

titration volumes of at least 2 ml are desired to minimize the error 

contributed by buret inaccuracy and the averaging of duplicate measurements. 

To add flexibility and conform with the guidelines given in Method 6, an 

approximate sampling flow rate of 2 liters/min will be required. 

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Finally, the requirement for 3-hour rolling S02 averages is not a change 

from current practice. The block averaging period mentioned in the March 1986 

memorandum is applicable specifically to determinations of compliance with 

applicable national air quality standards. Current policy permits emission 

limits established to comply with such standards to be expressed either as 

block or rolling averages. The same holds true for compliance with emission 

control requirements under applicable Part 60 standards. In the case in 

question, the rolling average was the original intent. Thus today's action is 

not a change from the present requirements. 

3. One commenter thought that PS 7 left much to be desired. Basic 

measures of analyzer performance, such as calibration error, response time, 

and operational test period were thought to be needed. Having to meet the CD 

specification on only 6 out of 7 test days would not encourage adjustment of 

the analyzer when drift exceeds the specification. Compliance with the CD 

specification without exceptions was preferred, with short-term and zero drift 

specifications also included. At the very least, language indicating that 

States may impose additional or more stringent specifications was desired. 

The commenter thought that the requirement to report only excess 

emissions would not allow an agency to take into account performance during 

compliance periods when determining enforcement action. Requiring sources to 

report data for all time periods was favored since a different enforcement 

action may be appropriate for a source that operates most of the time near the 

standard than for a source that usually operates well below the standard. 

Continual CEMS compliance and Appendix F procedures were not mandated for 

Subpart J sources. The PS test procedures are not designed for long-term 

evaluation nor for continual compliance but to provide the initial check of 
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the instrument's capabilities at the time of installation. The Agency feels 

that CEMS data accuracy and representativeness can be demonstrated 

sufficiently by RA and CD tests. A more in-depth evaluation of the CEMS at 

the discretion of the operator is encouraged, but this additional testing need 

not be required since the overall quality of monitor data can be determined by 

the RA and CD tests. 

The RA and CD specifications are determined from studies of CEMS 

performance over extended periods of time. In an Agency study of H2S CEMS's, 

the most reliable instruments were only capable of meeting CD's of 5 percent 

or less on 6 of 7 test days. 

The changing of reporting requirements is beyond the scope of this 

rulemaking. The purpose of the rulemaking is to revise the Subpart J 

monitoring and testing requirements to add clarity and additional information 

that were originally left out. This does not include revising the reporting 

criteria that have become a standard procedure for many source categories. 

Regulations governing State's authority are neither addressed nor regulated in 

Subpart J but in other sections of the regulations. 

4. A commenter noted that the wording change to § 60.104 might be 

construed to limit the exemption of flare gas associated with emergency 

malfunction situations. This should be clarified by revising the wording to 

recognize the fact that process upset gases, even when not the direct result 

of an "emergency malfunction" (e.g., process unit upsets due to changing 

feedstock, etc.), must be handled by a flare system for safety considerations. 

The proposed wording has been clarified to reflect this. 

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5. Another commenter saw no technical reason why the S02 CEMS's should 

not be used for direct compliance with S02 emission limitations at Subpart J 

sources. The proposed revisions were thought to be inconsistent with the 

Subpart Db ruling which uses the same CEMS's as Subpart J for direct 

compliance. The proposed rule also appeared to conflict with current EPA 

policy (as suggested in an EPA internal memorandum) of using CEMS data in the 

enforcement process. Because of the quantity of S02 emissions from 

refineries, and due to past experience with several refineries under the 

commenter's jurisdiction, the enforcement of continuous compliance with S02 

emission limitations was thought to be imperative. 

The commenter also felt that incinerators following Claus plants be 

monitored for temperature and oxygen to ensure total sulfur oxidation to S02. 

It was noted that in § 60.153(b)(3), the operators of incinerators located at 

sewage treatment plants are required to install, calibrate, maintain, and 

operate temperature devices. Similar language was desired for Subpart J 

incinerators. 

The same commenter questioned the flexibility of spans allowed in 

§ 60.105(a)(1) for opacity CEMS's. The commenter argued that the benefits of 

additional accuracy refinements do not justify the costs as long as Method 9 

remains the sole compliance method. The commenter felt that the arguments for 

allowing the use of CEMS data in lieu of Method 9 observations for 

compliance determinations were still valid when the CEMS is properly 

installed, certified, and maintained in accordance with PS 1 of Appendix B. 

It was argued that the Agency either allow the CEMS data for direct compliance 

or eliminate the allowance for span flexibility. 

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It was initially determined when the Subpart J regulations were developed 

that the monitoring data would be used to document excess emissions. This 

requirement cannot be changed in this rulemaking since such a change 

would constitute a major action instead of a clarification and would require 

a separate assessment and proposal with accompanying CEMS QA specifications. 

The oxidation efficiency of the control device will be documented through 

Method 15 testing for reduced sulfur compounds, and the added requirements for 

oxygen and temperature CEMS's will not be necessary. 

The use of noncompliance CEMS's in the proposed revisions is not 

inconsistent with EPA policy mentioned in the memorandum. As noted 

in the memorandum, data from CEMS's that are not the compliance method 

"should be used to monitor the continuous compliance of sources and to 

initiate follow-up action including on-site inspections, requesting further 

information, and issuing a notice of violation." 

6. A commenter from industry inquired about a situation in which some of 

their refinery's facilities were required by the EPA Regional Office and the 

State agency to install CEMS's under applicable Prevention of Significant 

Deterioration (PSD) and construction permit requirements even though fuel gas 

combustion devices have been exempted from H2S monitoring requirements since 

1975. Thirteen analyzers were installed at a significant cost. Twelve of 

these analyzers were installed between 1977 and 1983 during EPA's performance 

evaluation of H2S CEMS's. Although EPA concluded that acceptable H2S CEMS's 

were not available, the refinery was still required to install whatever 

analyzers were available at that time. In view of this, the commenter made 

the following recommendations. 

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a. The CEMS's that were required to be installed by State or 

Federal permits prior to the proposal date of the subject rule should be 

exempt from performance specification test (PST) requirements. 

b. The regulations should allow bench testing and certification of 

the CEMS's by the manufacturer. 

c. If a facility has installed more than one CEMS of the same make 

and manufacturer, only one PST need be conducted to certify the remaining 

CEMS's. The cost of certifying several identical analyzers is significant and 

an unnecessary expense. 

For CEMS's that have already been installed under Regional Office PSD 

requirements, exemptions or "grandfathering" of new monitoring requirements 

must be requested on a case-by-case basis through the Regional Office that 

required the initial CEMS installation. 

The Agency does not feel that CEMS bench testing and certification by 

the manufacturer represents a fail-safe means of verifying instrument 

performance. Manufacturers have a vested interest in the outcome of such 

evaluations. Bench testing may be routinely done to initially demonstrate 

the reliability of the instrument to the purchaser. However, this should 

not be substituted for a complete and observed PST after the CEMS has been 

installed and is functioning under actual conditions. 

All CEMS's that are not monitoring the same process stream will need 

to be evaluated by PST, regardless of make or manufacturer. Experience has 

shown that, even with identical CEMS's, performance can vary from unit to 

unit. Factors that affect the performance of CEMS's include internal 

malfunctions that may be specific to individual units as well as operational 

variables that reflect operator technique. The initial performance of each 

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CEMS can only be verified by testing each unit under actual installed 

conditions. 

7. A commenter recommended that an exemption should be allowed when it 

is demonstrated that the reduced sulfur and H2S emissions from subject Claus 

units are well below the respective 300 and 10 ppm standard levels during 

routine and normal operation. With Sulften tail gas treating units, 

continuous H2S CEMS's are already utilized and the reduced sulfur was reported 

to be barely detectable. Unit upsets and upstream operational problems will 

reflect loss of optimum operating conditions long before any resultant 

increased emissions exceed the reduced sulfur regulatory limit. Therefore, an 

exemption from the continuous monitoring of reduced sulfur and oxygen from 

these sources should be allowed. 

In addition, the commenter recommended that the time period for CEMS 

installation at affected refineries be extended to at least 18 months to allow 

sufficient time for procurement, installation, and calibration of the 

instrument. Where H2S analyzers are employed as standard equipment for Claus 

recovery plants, the analyzer may serve as the CEMS, provided it passes the 

PST and reflects representative measurement of emissions. Monitoring 

exemptions may be considered in those cases where emissions are routinely much 

lower than the standard and where there is an economic incentive to operate 

the device to minimize operational problems and upset conditions. Exemptions 

for devices that meet these conditions are best considered on case-by-case 

requests since such devices represent a minority of the total in operation. 

The Agency does not think an extension of the CEMS installation period 

is warranted. Affected sources are notified by the proposed rulemaking of 

the intended monitoring needs. An approximate period of 1 year between 

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regulation proposal and promulgation affords time to survey the CEMS market. 

In conjunction with the 1-year installation period, this has proven to be 

adequate. 

IV. ADMINISTRATIVE 

The docket is an organized and complete file of all the information 

considered by EPA in the development of this rulemaking. The docket is a 

dynamic file, since material is added throughout the rulemaking development. 

The docketing system is intended to allow members of the public and industries 

involved to identify readily and locate documents so that they can effectively 

participate in the rulemaking process. Along with the statement of basis and 

purpose of the proposed and promulgated revisions and EPA responses to 

significant comments, the contents of the docket, except for interagency 

review materials, will serve as the record in case of judicial review 

[Section 307(d)(7)(A)]. 

Under Executive Order 12291, EPA must judge whether a regulation is 

"major" and, therefore, subject to the requirement of a regulatory impact 

analysis. The Agency has determined that this rulemaking would not result in 

any of the adverse economic effects set forth in Section 1 of the Order as 

grounds for finding a "major rule." The Agency has, therefore, concluded that 

this regulation is not a "major rule" under Executive Order 12291. 

The Regulatory Flexibility Act (RFA) of 1980 requires the identification 

of potentially adverse impacts of Federal regulations upon small business 

entities. The Act specifically requires the completion of an RFA analysis in 

those instances where small business impacts are possible. Because this 

rulemaking imposes no adverse economic impacts, an analysis has not been 

conducted. 

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Pursuant to the provisions of 5 U.S.C. 605(b), I hereby certify that the 

promulgated rule will not have an impact on small entities because no 

additional costs will be incurred. 

This rule does not change any information collection requirements 

currently approved by OMB under the Paperwork Reduction Act of 1980, 44 U.S.C. 

3501 et seq. Information requirements contained in 40 CFR Part 60, Appendix A 

are cleared under OMB Control Number 2060-0022. 

List of Subjects in 40 CFR Part 60 

Air pollution control, Intergovernmental relations, Reporting and 

recordkeeping requirements, Incorporation by reference, and Petroleum 

refineries. 

Date William K. Reilly 

Administrator 

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40 CFR Part 60 is amended as follows: 

1. The authority for Part 60 continues to read: 

Authority: 42 U.S.C. 7401, 7411, 7414, 7416, 7601. 

2. In § 60.103(a), the phrase "gases which contain carbon monoxide in 

excess of 0.050 percent by volume." is revised to read "gases that contain 

carbon monoxide (CO) in excess of 500 ppm by volume (dry basis)." 

3. In § 60.104, paragraphs (a)(1), (2)(i), and (2)(ii) are revised to 

read as follows: 

§ 60.104 Standard for sulfur dioxide, 

(a) * * * 

(1) Burn in any fuel gas combustion device any fuel gas that contains 

hydrogen sulfide (H2S) in excess of 230 mg/dscm (0.10 gr/dscf). The 

combustion in a flare of process upset gases or fuel gas that is released to 

the flare as a result of relief valve leakage or other emergency malfunctions 

is exempt from this paragraph. 

(2) * * * 

(i) For an oxidation control system or a reduction control system 

followed by incineration, 250 ppm by volume (dry basis) of sulfur dioxide 

(S02) at zero percent excess air. 

(ii) For a reduction control system not followed by incineration, 

300 ppm by volume of reduced sulfur compounds and 10 ppm by volume of hydrogen 

sulfide (H2S), each calculated as ppm S02 by volume (dry basis) at zero 

percent excess air. 

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4. In § 60.105, paragraphs (a), (d), and (e) are revised to read as 

foi1ows: 

§ 60.105 Emission monitoring. 

(a) The owner or operator of the affected facility subject to the 

provisions of this subpart shall install, calibrate, maintain, and operate 

continuous emission monitoring systems (CEMS's) and continuous opacity 

monitoring systems (COMS's) as follows: 

(1) For fluid catalytic cracking unit catalyst regenerators subject to 

§ 60.102(a)(2), a COMS for continuously measuring and recording the opacity of 

emissions into the atmosphere. The COMS shall be spanned at 60, 70, or 80 

percent opacity. 

(2) For fluid catalytic cracking unit catalyst regenerators subject to 

§ 60.103(a), a CEMS for continuously measuring and recording the concentration 

by volume (dry basis) of CO emissions into the atmosphere, except as provided 

in paragraph (ii) below. 

(i) The span value for this CEMS is 1,000 ppm CO. 

(ii) A CO CEMS need not be installed if the owner or operator 

demonstrates that the average CO emissions are less than 50 ppm (dry basis) 

and also files a written request for exemption to the Administrator and 

receives such an exemption. The demonstration shall consist of continuously 

monitoring CO emissions for 30 days using an instrument that shall meet the 

requirements of Performance Specification 4 of Appendix B of this part. The 

span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy 

limit shall be 10 percent of the average CO emissions or 5 ppm CO, whichever 

is greater. For CEMS's that are identical to Method 10 and employ the sample 

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conditioning system of Method IOA, the alternative relative accuracy test 

procedure in Section 10.1 of Performance Specification 2 may be used in place 

of the relative accuracy test. 

(3) For fuel gas combustion devices subject to § 60.104(a)(1), a CEMS 

for continuously measuring and recording the concentration by volume (dry 

basis, zero percent excess air) of S02 emissions into the atmosphere (except 

where an H2S CEMS is installed under paragraph (a)(4) of this section). The 

CEMS shall include an oxygen monitor for correcting the data for excess air. 

(i) The span values for this CEMS are 50 ppm S02 and 10 percent 

oxygen (02). 

(ii) The S02 monitoring level equivalent to the H2S standard under 

§ 60.104(a)(1) shall be 20 ppm (dry basis, zero percent excess air). 

(iii) The performance evaluations for this S02 CEMS under § 60.13(c) 

shall use Performance Specification 2. Methods 6 and 3 shall be used for 

conducting the relative accuracy evaluations. Method 6 samples shall be taken 

at a flow rate of approximately 2 liters/min for at least 30 minutes. The 

relative accuracy limit shall be 20 percent or 4 ppm, whichever is greater, 

and the calibration drift limit shall be 5 percent of the established span 

value. 

(iv) Fuel gas combustion devices having a common source of fuel gas may 

be monitored at only one location (i.e., after one of the combustion devices), 

if monitoring at this location accurately represents the S02 emissions into 

the atmosphere from each of the combustion devices. 

(4) In place of the S02 CEMS in paragraph (a)(3) of this section, a CEMS 

for continuously measuring and recording the concentration (dry basis) of H2S 

in fuel gases before being burned in any fuel gas combustion device. 

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(i) The span value for this CEMS is 425 mg/dscm H2S. 

(ii) Fuel gas combustion devices having a common source of fuel gas may 

be monitored at only one location, if monitoring at this location accurately 

represents the concentration of H2S in the fuel gas being burned. 

(iii) The performance evaluations for this H2S CEMS under § 60.13(c) 

shall use Performance Specification 7. Method 11 shall be used for conducting 

the relative accuracy evaluations. 

(5) For Claus sulfur recovery plants with oxidation control systems or 

reduction control systems followed by incineration subject to 

§ 60.104(a)(2)(i), a CEMS for continuously measuring and recording the 

concentration (dry basis, zero percent excess air) of S02 emissions into the 

atmosphere. The CEMS shall include an oxygen monitor for correcting the data 

for excess air. 

(i) The span values for this CEMS are 500 ppm S02 and 10 percent 02. 

(ii) The performance evaluations for this S02 CEMS under § 60.13(c) 

shall use Performance Specification 2. Methods 6 and 3 shall be used for 

conducting the relative accuracy evaluations. 

(6) For Claus sulfur recovery plants with reduction control systems not 

followed by incineration subject to § 60.104(a)(2)(ii), a CEMS for 

continuously measuring and recording the concentration of reduced sulfur and 

02 emissions into the atmosphere. The reduced sulfur emissions shall be 

calculated as S02 (dry basis, zero percent excess air). 

(i) The span values for this CEMS are 450 ppm reduced sulfur and 

10 percent 02. 

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(ii) The performance evaluations for this reduced sulfur (and 02) CEMS 

under § 60.13(c) shall use Performance Specification 5, except the calibration 

drift specification is 2.5 percent of the span value rather than 5 percent. 

Methods 15 or 15A and Method 3 shall be used for conducting the relative 

accuracy evaluations. If Method 3 yields 02 concentrations below 0.25 percent 

during the performance specification test, the 02 concentration may be assumed 

to be zero and the reduced sulfur CEMS need not include an 02 monitor. 

(7) In place of the reduced sulfur CEMS under paragraph (a)(6) of this 

section, a CEMS using an air or 02 dilution and oxidation system to convert 

the reduced sulfur to S02 for continuously measuring and recording the 

concentration (dry basis, zero percent excess air) of the resultant S02. The 

CEMS shall include an oxygen monitor for correcting the data for excess 

oxygen. 

(i) The span values for this CEMS are 375 ppm S02 and 10 percent 02. 

(ii) For reporting purposes, the S02 exceedance level for this CEMS 

is 250 ppm (dry basis, zero percent excess air). 

(iii) The performance evaluations for this S02 (and 02) CEMS under 

§ 60.13(c) shall use Performance Specification 5. Methods 15 or 15A and 

Method 3 shall be used for conducting the relative accuracy evaluations. 

**** * 

(d) For any fluid catalytic cracking unit catalyst regenerator under 

§ 60.102 that uses an incinerator-waste heat boiler to combust the exhaust 

gases from the catalyst regenerator, the owner or operator shall record daily 

the rate of combustion of liquid or solid fossil-fuels (liters/hr or kg/hr) 

and the hours of operation during which liquid or solid fossil-fuels are 

combusted in the incinerator-waste heat boiler. 

21 
(e) For the purpose of reports under § 60.7(c), periods of excess 

emissions that shall be determined and reported are defined as follows (NOTE: 

All averages, except for opacity, shall be determined as the arithmetic 

average of the applicable 1-hour averages, e.g., the rolling 3-hour average 

shall be determined as the arithmetic average of three contiguous 1-hour 

averages): 

(1) Opacity. All 1-hour periods that contain two or more 6-minute 

periods during which the average opacity as measured by the COMS under 

§ 60.105(a)(1) exceeds 30 percent. 

(2) Carbon monoxide. All 1-hour periods during which the average CO 

concentration as measured by the CO CEMS under § 60.105(a)(2) exceeds 500 ppm. 

(3) Sulfur dioxide from fuel qas combustion. 

(i) All rolling 3-hour periods during which the average concentration of 

S02 as measured by the S02 CEMS under § 60.105(a)(3) exceeds 20 ppm (dry 

basis, zero percent excess air); or 

(ii) All rolling 3-hour periods during which the average concentration 

of H2S as measured by the H2S CEMS under § 60.105(a)(4) exceeds 230 mg/dscm 

(0.10 gr/dscf). 

(4) Sulfur dioxide from Claus sulfur recovery plants. 

(i) All 12-hour periods during which the average concentration of S02 as 

measured by the S02 CEMS under § 60.105(a)(5) exceeds 250 ppm (dry basis, zero 

percent excess air); or 

(ii) All 12-hour periods during which the average concentration of 

reduced sulfur (as S02) as measured by the reduced sulfur CEMS under 

§ 60.105(a)(6) exceeds 300 ppm; or 

22 
(iii) All 12-hour periods during which the average concentration of S02 

as measured by the S02 CEMS under § 60.105(a)(7) exceeds 250 ppm (dry basis, 

zero percent excess air). 

* * * * * 

5. Section 60.106 is revised to read as follows: 

§ 60.106 Test methods and procedures. 

(a) In conducting the performance tests required in § 60.8, the owner or 

operator shall use as reference methods and procedures the test methods in 

Appendix A of this part or other methods and procedures as specified in this 

section, except as provided in § 60.8(b). 

(b) The owner or operator shall determine compliance with the 

particulate matter (PM) standards in § 60.102(a) as follows: 

(1) The emission rate (E) of PM shall be computed for each run using the 

following equation: 

K cs Qsd 

E = 

where: 

Rc 

E = Emission rate of PM, kg/1000 kg (lb/1000 lb) of coke burn-off. 

cs = Concentration of PM, g/dscm (lb/dscf). 

Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/hr). 

Rc = Coke burn-off rate, kg coke/hr (lb coke/hr). 

K = Conversion factor, 1.0 (kg2/g)/(1000 kg) [IO3 lb/(1000 lb)]. 

(2) Method 5 shall be used to determine the concentration (cs) of 

PM and volumetric flow rate (Qsd) of the effluent gas. The sampling time and 

sample volume for each run shall be at least 60 minutes and 0.90 dscm 

(31.8 dscf). 

23 
P.25 

(3) The coke burn-off rate (Rc) shall be computed for each run using the 

following equation: 

Rc = Kx Qr (%C02 + %C0) + K2 Qa - K3 Qr [(%C0/2) + %C02 + %02] 

where: 

Rc = Coke burn-off rate, kg/hr (lb/hr). 

Qr = Volumetric flow rate of exhaust gas from catalyst regenerator 

before entering the emission control system, dscm/min (dscf/min). 

Qa = Volumetric flow rate of air to FCCU regenerator, as determined 

from the fluid catalytic cracking unit control room 

instrumentation, dscm/min (dscf/min). 

%C02 = Carbon dioxide concentration, percent by volume (dry basis). 

%C0 = Carbon monoxide concentration, percent by volume (dry basis). 

% 02 = Oxygen concentration, percent by volume (dry basis). 

Kj = Material balance and conversion factor, 

0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)]. 

K2 = Material balance and conversion factor, 

2.088 (kg-min)/(hr-dscm-%)[0.1303 (lb-min)/(hr-dscf-%)]. 

K3 = Material balance and conversion factor, 

0.0994 (kg-min)/(hr-dscm-%) 

[0.0062 (lb-min)/(hr-dscf-%)]. 

(i) Method 2 shall be used to determine the volumetric flow rate (Qr). 

(ii) The emission correction factor, integrated sampling and analysis 

procedure of Method 3 shall be used to determine C02, CO, and 02 

concentrations. 

24 
(4) Method 9 and the procedures of § 60.11 shall be used to determine 

opacity. 

(c) If auxiliary liquid or solid fossil-fuels are burned in an 

incinerator-waste heat boiler, the owner or operator shall determine the 

emission rate of PM permitted in § 60.102(b) as follows: 

(1) The allowable emission rate (Es) of PM shall be computed for each 

run using the following equation: 

Es = 1.0 + A (H/Rc) K' 

where: 

Es = Emission rate of PM allowed, kg/1000 kg (lb/1000 lb) of coke 

burn-off in catalyst regenerator. 

1.0 = Emission standard, kg coke/1000 kg (lb coke/1000 lb). 

A = Allowable incremental rate of PM emissions, 0.18 g/million cal 

(0.10 lb/million Btu). 

H = Heat input rate from solid or liquid fossil fuel, million cal/hr 

(million Btu/hr). 

Rc = Coke burn-off rate, kg coke/hr (lb coke/hr). 

K' = Conversion factor to units of standard, 1.0 (kg2/g)/(1000 kg) 

[IO3 lb/(1000 lb)]. 

(2) Procedures subject to the approval of the Administrator shall be 

used to determine the heat input rate. 

(3) The procedure in paragraph (b)(3) of this section shall be used to 

determine the coke burn-off rate (Rc). 

(d) The owner or operator shall determine compliance with the CO 

standard in § 60.103(a) by using the integrated sampling technique of 

25 
Method 10 to determine the CO concentration (dry basis). The sampling time 

for each run shall be 60 minutes. 

(e) The owner or operator shall determine compliance with the H2S 

standard in § 60.104(a)(1) as follows: Method 11 shall be used to determine 

the H2S concentration. The gases entering the sampling train should be at 

about atmospheric pressure. If the pressure in the refinery fuel gas lines is 

relatively high, a flow control valve may be used to reduce the pressure. If 

the line pressure is high enough to operate the sampling train without a 

vacuum pump, the pump may be eliminated from the sampling train. The sample 

shall be drawn from a point near the centroid of the fuel gas line. The 

sampling time and sample volume shall be at least 10 minutes and 0.010 dscm 

(0.35 dscf). Two samples of equal sampling times shall be taken at about 

1-hour intervals. The arithmetic average of these two samples shall 

constitute a run. For most fuel gases, sampling times exceeding 20 minutes 

may result in depletion of the collection solution, although fuel gases 

containing low concentrations of H2S may necessitate sampling for longer 

periods of time. 

(f) The owner or operator shall determine compliance with the S02 and 

the H2S and reduced sulfur standards in § 60.104(a)(2) as follows: 

(1) Method 6 shall be used to determine the S02 concentration. The 

concentration in mg/dscm (lb/dscf) obtained by Method 6 is multiplied by 

0.3754 to obtain the concentration in ppm. The sampling point in the duct 

shall be the centroid of the cross section if the cross-sectional area is less 

than 5.00 m2 (54 ft2) or at a point no closer to the walls than 1.00 m 

(39 in.) if the cross-sectional area is 5.00 m2 or more and the centroid is 

more than 1 m from the wall. The sampling time and sample volume shall be at 

26 
least 10 minutes and 0.010 dscm (0.35 dscf) for each sample. Eight samples of 

equal sampling times shall be taken at about 30-minute intervals. The 

arithmetic average of these eight samples shall constitute a run. Method 4 

shall be used to determine the moisture content of the gases. The sampling 

point for Method 4 shall be adjacent to the sampling point for Method 6. The 

sampling time for each sample shall be equal to the time it takes for two 

Method 6 samples. The moisture content from this sample shall be used to 

correct the corresponding Method 6 samples for moisture. For documenting the 

oxidation efficiency of the control device for reduced sulfur compounds, 

Method 15 shall be used following the procedures of paragraph (f)(2) of this 

section. 

(2) Method 15 shall be used to determine the reduced sulfur and H2S 

concentrations. Each run shall consist of 16 samples taken over a minimum of 

3 hours. The sampling point shall be the same as that described for Method 6 

in paragraph (f)(1) of this section. To ensure minimum residence time for the 

sample inside the sample lines, the sampling rate shall be at least 3.0 lpm 

(0.10 cfm). The S02 equivalent for each run shall be calculated after being 

corrected for moisture and oxygen as the arithmetic average of the S02 

equivalent for each sample during the run. Method 4 shall be used to 

determine the moisture content of the gases as in paragraph (f)(1) of this 

section. The sampling time for each sample shall be equal to the time it 

takes for four Method 15 samples. 

(3) The oxygen concentration used to correct the emission rate for 

excess air shall be obtained by the integrated sampling and analysis procedure 

of Method 3. The samples shall be taken simultaneously with the S02, reduced 

27 
P.29 

sulfur and H2S, or moisture samples. The S02, reduced sulfur, and H2S samples 

shall be corrected to zero percent excess air using the following equation: 

20.9 

CC = C 

20.9 - %02 

where: 

Cc = Corrected concentration of pollutant, ppm by volume (dry basis) 

C = Measured concentration of pollutant, ppm by volume (dry basis). 

% 02 = Oxygen concentration, percent by volume (dry basis). 

**** * 

28 
P.30 

9. In Appendix B, by adding Performance Specification 7 as follows: 

APPENDIX B - PERFORMANCE SPECIFICATIONS 

**** * 

PERFORMANCE SPECIFICATION 7 - SPECIFICATIONS 

AND TEST PROCEDURES FOR HYDROGEN SULFIDE CONTINUOUS EMISSION 

MONITORING SYSTEMS IN STATIONARY SOURCES 

1. Applicability and Principle 

1.1 Applicability. 

1.1.1 This specification is to be used for evaluating the acceptability 

of hydrogen sulfide (H2S) continuous emission monitoring systems (CEMS's) at the 

time of or soon after installation and whenever specified in an applicable 

subpart of the regulations. 

1.1.2 This specification is not designed to evaluate the installed CEMS 

performance over an extended period of time nor does it identify specific 

calibration techniques and other auxiliary procedures to assess CEMS performance. 

The source owner or operator, however, is responsible to calibrate, maintain, 

and operate the CEMS. To evaluate CEMS performance, the Administrator may 

require, under Section 114 of the Act, the source owner or operator to conduct 

CEMS performance evaluations at other times besides the initial test. See 

Section 60.13(c). 

1.1.3 The definitions, installation specifications, test procedures, data 

reduction procedures for determining calibration drifts (CD) and relative 

accuracy (RA), and reporting of Performance Specification 2 (PS 2), Sections 2, 

3, 5, 6, 8, and 9 apply to this specification. 

29 
P.31 

1.2 Principle. Reference method (RM), CD, and RA tests are conducted to 

determine that the CEMS conforms to the specification. 

2. Performance and Equipment Specifications 

2.1 Instrument Zero and Span. This specification is the same as Section 

4.1 of PS 2. 

2.2 Calibration Drift. The CEMS calibration must not drift or deviate from 

the reference value of the calibration gas or reference source by more than 5 

percent of the established span value for 6 out of 7 test days (e.g., the 

established span value is 300 ppm for Subpart J fuel gas combustion devices). 

2.3 Relative Accuracy. The RA of the CEMS shall be no greater than 20 

percent of the mean value of the RM test data in terms of the units of the 

emission standard or 10 percent of the applicable standard, whichever is greater. 

3. Relative Accuracy Test Procedure 

3.1 Sampling Strategy for RM Tests, Correlation of RM and CEMS Data, Number 

of RM Tests, and Calculations. These are the same as that in PS 2, Sections 7.1, 

7.2, 7.3, and 7.5, respectively. 

3.2 Reference Methods. Unless otherwise specified in an applicable subpart 

of the regulation, Method 11 is the RM for this PS. 

4. Bibliography 

1. U.S. Environmental Protection Agency. Standards of Performance for New 

Stationary Sources; Appendix B; Performance Specifications 2 and 3 for S02, N0X, 

C02, and 02 Continuous Emission Monitoring Systems; Final Rule. 48 CFR 23608. 

Washington, D.C. U.S. Government Printing Office. May 25, 1983. 

2. U.S. Government Printing Office. Gaseous Continuous Emission Monitoring 

Systems - Performance Specification Guidelines for S02, N0X, C02, 02, and TRS. 

30 
U.S. Environmental Protection Agency. Washington, D.C. EPA-450/3-82-026. 

October 1982. 26 p. 

3. Maines, G.D., W.C. Kelly (Scott Environmental Technology, Inc.), and 

J.B. Homolya. Evaluation of Monitors for Measuring H2S in Refinery Gas. 

Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, 

N.C. Contract No. 68-02-2707. 1978. 60 p. 

4. Ferguson, B.B., R.E. Lester (Harmon Engineering and Testing), and W.J. 

Mitchell. Field Evaluation of Carbon Monoxide and Hydrogen Sulfide Continuous 

Emission Monitors at an Oil Refinery. Prepared for the U.S. Environmental 

Protection Agency. Research Triangle Park, N.C. Publication No. EPA-600/4-82-

054. August 1982. 100 p. 

31