p.1 

OAR Box 1170 

Prepped by Ollie Stewart 

Document Number: 

88) F. R. March 1, 1990 

Docket Number: 

A-88-24 

Printed 4/30/2008 10:49:06 AM Sheet 88 of 182 
P.2 

V 

0570 

&-Z2-2 + 

Federal Register / Vol. 54, No. 39 / Wednesday, March 1, 19B9 / Proposed Rules 

apply to sources that: (1) Remove C02 or 02 

through processes other than combustion, (2) 

add Oj (e.g., oxygen enrichment) and N2 in 

proportions different from that of air, (3) add 

C02 (e.g., cement or lime kilns), or (4) have on 

fuel factor, F0, values obtainable (e.g., 

extremely variable waste mixtures). This 

method validates the measured proportions 

of C02 and 02 for fuel type, but the method 

does not detect sample dilution resulting from 

leaks during or after sample collection. The 

method is applicable for samples collected 

downstream of most lime or limestone fluegas desulfurization units as the C02 added or 

removed from the gas stream is not 

significant in relation to the total C02 

concentration. The C02 concentrations from 

• other types of scrubbers using only water or 

basic slurry can be significantly affected and 

would render the F0 check minimally useful. 

3.4.1.1 Calculate a fuel factor. F„ using 

the following equation: 

F.= 

20.9 — %Q*, 

%COa 

Eq. 3B-1 

where: 

%02 = Percent 0 2 by volume, dry basis. 

%C02=Percent C02 by volume, dry basis. 

20.9 = Percent 0 2 by volume in ambient air. 

If CO is present in quantities measurable by 

this method, adjust the 0 2 and CO* values 

before performing the calculation for F„ as 

follows: 

%C02 = (adj) = %C02 + %CO 

%O, = (adj)=%O.-0.5 %CO 

where: 

SCO = Percent CO by volume, dry basis. 

3.4.1.2 Compare the calculated F„ factor 

with the expected F„ values. The following 

table may be used in establishing acceptable 

ranges for the expected F0 if the fuel being 

burned is known. When fuels are burned in 

combinations, calculate the combined fuel Fd 

and Fc factors (as defined in Method 19) 

according to the procedure in Method 19, 

Section 5.2.3. Then calcuate the F0 factor as 

follows: 

F„= 

0.209F,, 

Eq. 3B-2 

Fuel type 

Coal: 

Oil: 

Distillate 

Gas: 

Wood : 

F„range 

1.016-1.130 

1.083-1.230 

1.260-1.413 

1.210-1.370 

1,600-1.836 

1.434-1586 

1.405-1.553 

1 000-1.120 

1.003-1.130 

3.4.1 Calculated F„ values, beyond the 

acceptable ranges shown in this tabie. should 

be investigated before accepting the test 

results. For example, the strength of the 

solutions in the gas analyzer and the 

analyzing technique should be checked by 

sampling and analyzing a known 

concentration, such as air; the fuel factor 

should be reviewed and verified. An 

acceptability range of ±12 percent is 

appropriate for the F0 factor of mixed fuels 

with variable fuel ratios. The level of the 

emission rate relative to the compliance level 

should be considered in determining if a 

retest is appropriate, i.e.; if the measured 

emissions are much lower or much greater 

than the compliance limit, repetition of the 

test would not significantly change the 

compliance status of the source and would be 

unnecessarily time consuming and costly. 

4. Calculations 

4.1 Nomenclature. Same as Section 5 of 

Method 3 with the addition of the following: 

%EA = Percent excess air. 

0.264=Ratio of O* to N2 in air, v/v. 

4.2 Percent Excess Air. Calculate the 

present excess air (if applicable) by 

substituting the appropriate values of percent 

Oa, CO, and N» (obtained from Section 3.1.3 

or 3.2.4) into Equation 3B-3. 

%EA = 

SSOa-0.5 CO 

0.264 %N2-{%02-0.5 %CO) 

X100 Eq. 3&-3 

Note.—The equation above assumes that 

ambient air is used as the source of 0 2 and 

that the fuel does not contain appreciable 

amounts of N2 (as do coke oven or blast 

furance gases). For those cases when 

appreciable amounts of N2 are present (coal, 

oil, and natural gas do not contain 

appreciable amounts of N2) or when oxygen 

enrichment is used, alternative methods, 

subject to approval of the Administrator, are 

required. 

4. Bibliography 

Same as Method 3. 

(FR Doc. 89-5722 Filed 2-28-89; 8:45 am) 

BILLING COOE 6560-50-M 

40 CFR Part 60 

[AD-FRL-3530-5] 

Standards of Performance for New 

Stationary Sources 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule and notice of 

public hearing. 

SUMMARY: The purpose of this proposed 

rule is five-fold: (1) Require (as opposed 

to being an option) the monitoring of 

sulfur dioxide (SO2) 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) delete the 

mention of controlling SO2 after 

combustion of fuel gases; (3) delete the 

monitoring requirement of H2S in gases 

discharged into the atmosphere from 

Claus sulfur recovery plants, but require 

the monitoring of total reduced sulfur 

(TRS) compounds using TRS continuous 

emission monitoring systems (CEM's) or 

S02 CEMS's after oxidizing the TRS 

compounds to SO2; (4) add Performance 

Specification (PS) 7 for H2S CEMS's to 

Appendix B of this part; and (5) 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 TRS CEMS installations were 

contingent upon the Agency's 

promulgation of PS's. 

A public hearing will be held, if 

requested, to provide interested persons 

an opportunity for oral presentation of 

dsta, views, or arguments concerning 

the proposed rule. 

DATES: Comments. Comments must be 

received on or before May 15,1989. 

Public Hearing. If anyone contacts 

EPA requesting to speak at a public 

hearing by March 22,1989, a public 

hearing will be held on April 17,1989. 

beginning at 10:00 a.m. Persons 

interested in attending the hearing 

should call Foston Curtis at (919) 541-

1063 to verify that a hearing will be held. 

Request to Speak at Hearing. Persons 

wishing to present oral testimony must 

contact EPA by March 22,1989. 

ADDRESSES: Comments. Comments 

should be submitted fin duplicate if 

possible) to: Central Docket Section 

(LE-131), Attention: Docket Number A88-24, U.S. Enviionmental Protection 

Agency, South Conference Center, Room 
P.3 

"Federal •-•Refflster;/-3 Vd^ .:.r'.X-r?°S-' 

4,401M Street, SW., Washington, DC 

20460. 

Public Hearing. If anyone contacts 

EPA requesting a public hearing, it will 

be held at EPA's Emission Measurement 

Laboratory, Research Triangle Park, 

North Carolina. Persons interested in 

attending the hearing or wishing to 

present oral testimony should notify 

Foston Curtis, Emission Measurement 

Branch (MD-19), Technical Support 

Division, U.S. Environmental Protection 

Agency, Research Triangle Park, North 

Carolina 27711, telephone number (919) 

541-1083.. ~ M 

Docket Docket No. A-88r-24. 

containing materials relevant to this 

rulemaking, is available for public 

, inspection and copying between 8:00 

a.m. and 3:30 p.m., Monday through 

Friday, at EPA's Central Docket Section. 

South Conference Center, Room 4,401M 

Street, SW.. Washington, DC 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: 

L The Rulemaking 

The present monitoring requirements 

for. fuel gas combustion devices under 

§ 60.105(a) (3) and (4) allow the options 

of monitoring SCfe 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 proposes 

to amend the emission monitoring 

requirements to end this exemption. The 

effect of this rulemaking will be to 

require affected facilities to monitor SO2 

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 SOj. The resulting SO2 concentration 

is substantially less than the • 

corresponding HsS 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 stochiometric 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 SO2 formed from

 ; 

combusting fuel gas containing HiS 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 SO2 level 

rioted in ihe Background Document to 

the proposed petroleum refineries 

standard. 

Realizing the complexity of 

establishing the SO2/H2S equivalency 

;

 on a case-by-case basis, EPA has 

selected 20 ppm to represent the . 

compliance level for SO2; In addition, 

rather than requiring monitoring ofthe . 

effluent after each combustion device, 

EPA is allowing the monitoring of SCv 

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 Agency review indicate 

that, at least in these cases, acceptable 

CEMS accuracy and calibration drift 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 HaS CEMS's of the same type; and 

instrument performance appears to be 

linked to operator and maintenance 

proficiency. Thus, EPA had decided to 

allow the use of H,S CEMS's for fuel 

gases as an alternative to SOi CEMS's 

for combusted fuel gases. For this 

purpose, PS 7 is being 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 SO2 emissions may petition 

the Administration for an alternative 

compliance demonstration. 

Hydrogen sulfide and TRS emitted 

from Claus plants are regulated by 

standards set at 10 and 300 ppm, 

respectively. Total reduced suflur 

compounds, though determined 

separately from TRS, are also inclusive 

of H2S by definition. The Agency has 

determined that it is difficult to monitor 

the disproportionate concentrations pf M:i* 

*H2S and TRS on a continual ba'sis','A' M''M'-'' 

especially at levels near the standards. 

A separate determination of H»S apart , 

from TRS will therefore riot be required, 

but only the continuous moriitoririg of'' '•'•'•: 

TRS. Performance Specification 5 and " 

Method 15 of 15A are being proposed as 

the means to evaluate the TRS CEMS M 

performance;- •••

 ;

---. •••••:• •;.:•':MMsv'-'''';'"-":' 

For greater flexibility, .EPA is also j; \fjA'\r_ 

proposing to allow theuse 6f a^CEMS^-fM 

that oxidizes the TRS compounds to SOJ'' ; 5 

and analyzes the concentration of.the'' A 

re^{dting:SOt.:Rather'than^ti^ing'1d''^^.^'.^'^ 

determine the concentration of SOi^^MM M 

equivalent to the TRS concentration;:?; :?M •.-:.-

EPA is proposing to use the level df250 

ppm SOa (dry basis, zero percent excess M !.'; 

air) to represent the SOs compliance ;;i;jf;-M^ 

level. This concentration is consistentMl,: M 

with the control option of combusting •'"'•• 

the effluent gases under § 60;i02(a)(2)(i). 

In addition to the above changes, EPA 

is proposing to clarify ambiguities in the 

existing regulations by correcting 

inconsistencies and by specifying : 

pertinent testing procedures that 

originally were only implied; 

This rulemaking does not impose , M 

emission measurement requirements ' 

beyond those specified in the current -

regulations, nor does it change any. ' 

emission standard or rhake it riiore"" 

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. | 

HI. Administrative Requirements 

A. Public Hearing 

A public hearing will be held, if 

requested, to discuss the proposed 

revisions in accordance with section 

307(d)(5) of the Clean Air Act. Persons 

wishing to make oral presentations, .;:„ 

should contract EPA at the address.; :•..'.:. •:.-. 

given in the ADDRESSES section'of this 

preamble. Oral presentations will be •; 

limited to 15 minutes each. Any member 

of the public may file a written A:"-.-

statement with EPA before, during, or 

within 30 days after the hearing. Written 

statements should be addressed to the 

Central Docket Section address given in 

the ADDRESSES section of this preamble. 

A verbatim transcript of the hearing • 

and written statements will be available 

for public inspection and copying during 

normal working hours at EPA's Central 

Docket Section in Washington, DC (see 

ADDRESSES section of this preamble). 

B. Docket 

The docket is an organized and 

complete file of all the information 
P.4 

,8572 *-.-.— * Federal Register/Vol. 54, No. 39 / Wednesday, March 1, 1989 /Proposed Rides 

submitted to or otherwise considered by 

EPA in the development of this proposed 

rulemaking. The principal purposes of 

the docket are to: (1) allow interested 

parties to identify and locate documents 

so that they can effectively participate 

in the rulemaking process, and (2) serve 

as the record in case of judicial review 

(except for interagency review 

materials) (Section 307(d)(7)(A)). 

C. Office of Management and Budget 

Review •' , ' 

Executive Order 12291 Review. Under 

Executive Order 12291, EPA must judge 

whether a regulation is "major" and, 

therefore, subject to the requirement of a 

regulatory impact analysis. 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." It will not have 

an annual effect on the economy of $100 

million or more, nor will it result in a 

major increase in costs or prices. There 

will be no significant adverse effects on 

competition, employment, investment, 

productivity, innovation, or on the 

ability of U.S.-based enterprises to 

compete with foreign-based enterprises 

in domestic or export markets. This 

regulation was submitted to the Office 

of Management and Budget (OMB) for 

review as required by Executive Order 

12291. 

D. Regulatory Flexibility Act 

Compliance 

Pursuant to the provisions of 5 U.S.C. 

605(b), I hereby certify that this attached 

rule, if promulgated, will not have any 

economic 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 seg. Information 

requirements contained in"40 CFR Part 

60, Subpart J 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: February 19,1989. 

Don R. Clay, 

Acting Assistant Administrator for Air and 

Radiation. 

It is proposed that 40 CFR Part 60 be 

amended as follows: 

PART 60—[AMENDED] 

1. The authority for 40 CFR Part 60 

continues to read: 

Authority: Sections 101, 111, 114,116, and 

301 of the Clean Air Act, as amended (42 

IIS.C. 7401, 7411, 7414, 7416, 7601). 

§ 60.103 [Amended] 

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 S 60.104. paragraphs (a)(1), (2)(i), 

and (2)(ii) are revised to read as follows: 

§ 60.104 Standard for sulfur dioxide. 

(a) * * * 

(1) Bum in any fuel gas combustion 

device any fuel gas that contains : 

hydrogen sulfide (HbS) in excess of 230 

mg/dscm (0.10 gr/dscf). Under 

emergency malfunction situations, 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 is 

exempt from this paragraph. 

(2J * * * 

(ly^oj an oxidation control system or 

a reoaarJon control.system followed by 

melioration, 250 ppm by volume (dry 

basis) of sulfur dioxide (SO2) at zero 

percent excess air. 

(ii) For a reduction control system not 

followed by incineration, 300 ppm by 

volume of total reduced sulfur (TRS) 

compounds and 10 ppm by volume of 

hydrogen sulfide (H2S), each calculated 

as ppm SO2 by volume (dry basis) at 

zero percent excess air. 

4. In § 60.105, paragraphs (a), (d), and 

(e) are revised to read as follows: 

§60.105 Emission monitoring. 

(aj 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 t>".[ 

1.000 ppm co. \Jrrj • 

(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 "v. 

exemption. The demonstration shall 

consist of continuously monitoring CO 

emissions for 30 days using an' . 

instrument that shall meet the V A••'..• 

requirements of Performance M - v'^-yy: '••-. 

• Specification 4 of Appendix B of this '-•••• 

part. The span value shall be 100 ppm "'•• 

CO instead pf 1,000 ppm, and the M> 

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 conditioning - • 

system of Method 10A, 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 SOz 

emissions into the atmosphere (except 

where an HsS 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 SO2 and 10 percent oxygen (Oj). 

(ii) The SO2 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 SO2 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 

2 liters/min for at least 30 minutes. The 

relative accuracy limit shall be 20 

percent or 4 ppm, whichever is greater, 

and tlie 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 SOa emissions into the 

atmosphere from each of the combustion 

devices. 

(4)Tn place of the SOa 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. 
P.5 

~«rij .•:federal; Register / ¥61/54, NoJdd )NWednesday\;M^^ 

(i) The span value for this CEMS is 

425 mg/dscm HaS. 

(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 HaS 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 folio wed 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 SO2 

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 SO2 and 10 percent O2. 

' (ii) The performance evaluations for 

this SOa 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 systeins hot 

followed by incineration subject to . 

§ 60404(a)(2)(ii), a GEMS.for 

continuously measuring and recording 

the concentration of TRS and Oa 

' emissions into the atmosphere. The TRS 

emissions shall be calculated as SOa M 

(dry basis, zero percent excess air). 

(i) The span values for this CEMS are 

450 ppin TRS and 10 percent O2; 

(ii) The performance evaluations for 

this TRS (and Oa) 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 Oa concentrations 

below 0.25 percent during the 

performance specification test, the Cv 

concentration may be assumed to be 

zero and the TRS CEMS need not 

include an Oa monitor. 

(7) In place of the TRS CEMS under 

paragraph (a)(6) of this section, a CEMS 

using an air or Oa dilution and oxidation 

system to convert the TRS to SOa for 

continuously measuring and recording 

the concentration (dry basis, zero 

percent excess air) of the resultant SOa. 

The CEMS shall include an oxygen 

monitor for correcting the data for 

excess oxygen. 

(i) The span values for this CEMS are 

375 ppm SO2 and 10 percent Oa. 

(ii) For reporting purposes, tthe'SOa 

exceedance level for this CEMS is 250 

ppm (dry basis, zero percent excess air). 

(iii) Trie performance evaluations for 

this SOa (and Oa) 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. _f 

(d) For ariy fluid catalytic cracking 

unit catalyst regenerator under § 60.102 

that uses an incinerator-waste heat; '*: ' 

boiler to combust the exhaust gases >;M 

from the catalyst regenerator]: the owner 

or operator shall record daily the rateof 

combustion of liquid or solid fossil-fuels 

(litere/hr or kg/hr) and me hours of M-M 

operation during which liquid or solid r > 

- fossil-fuels are combusted mtheM.; -

incinerator-waste heat boiler. 'M M 

(e) For the purposes 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 . 

3 contiguous 1-hour averages): "'.";" AJ"' 

(1)Opacity: All 1-hourperiods that 

coritaintwo or more 6-itiinutfeperibds y; 

during which the average opacity as ; 

measured by the COMS urider" M M -'4;''-' 

§ 60.105(a)(1) exceeds 30 percent. J' 

(2) CarbonmonbJdde. All l-houiM;'M" 

periods during whic^juie"ayerage!lb0! 

concentrationasmeasured jbyitheCO 

CEMS under § 60.105(a)(2) exceeds 500 

ppm . '•• '••;.;_, 

(3) Sulfur dioxide from fuel gas 

combustion. 

(i) All rolling 3-hour periods during 

which the average concentration of SOa 

as measured by the SO2 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 HaS 

as measured by the HaS CEMS under 

§ 60.105(a)(4) exceeds 230 mg/dscm (0.10 

gr/dscf). •': M : ; .••:. , 

(4) Sulfur dioxide from Claus sulfur, 

recovery plants. 

(i) All 12-hour periods dining which 

the average concentration, of SO2 as . 

measured by the SOa 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 TRS (as 

SOa) as measured by the TRS CEMS 

under § 60.105(a)(6) exceeds 300 ppm; or 

(iii) All 12-hour periods during which 

the average concentration of SOa as 

measured by the SOa CEMS under 

§ 60.105(a)(7) exceeds250 j#fo;$jrj^vj/ 

basis, zero percent excess air);:6r>l;;;Vr 

§60.106 Test methods and procedures..-

(a) In conducting the performance*") -

tests required in % 60.8, the owner orMM 

operator shall use as reference methods," v 

and procedures the test methods ins^MM";-:• 

Appendix A'of this par tor 6ther-M##r£ M' 

methods and procedures asi specifiedin •: 0, 

this section, except as provided*in;VbVfei;>-

'. § 60.8(b). . .-.; >•MM.M «• .?:MM5#:^M:MM -.' 

(b) The dWner or operat<&Miyi^fif?&?M \'• 

determinecompliance withtihe ^|f/|^M,: ' 

particulate mattef(PM) stahllardsHnv).?'^r:.. 

§60;102(aj as follows:-:M^^rf^^lM M 

-(1) The eiriissibri rate'^ofM'1ih^| A A 

<becomputed.for 'Saih-i^-w^'ttie^*^;''- 1 

followirig equiatidri:" VM?^AJfrh:'ijTiAA-:; 

K-(cs'QJ^.: •'"•':?••: 

R« 

where:',; '•' . M. M':'."""?:.' 

E=Emission rate of PM, kg/lOOO kg 

(lb/1000 lb) of coke burn-oft ,4 ^ ; £ 

. C„=Concentration of PM, g/dscm;(lb/ 

•dscf).'••••:.'., ;'•:; 'A.J\,: J,J\\ A.yy -A.y 

G^^ VPlifinetric flow rate of effluent.• 

gas, dscm/hr (dscf/hrJM'M 'M' M *M " 

[.•'. Rc^Goke bito-off,"fate,' kg cpke/hr (lb 

cpke/hr).;^ ^v:;;••••>-.-'.'•Jyvv.irrAAJA "'• •' 

'•• iC=Gottversi6h factor]1;0 kg Vg)/(1000 

. kgj.llO^lb/flOM^lM^^ii^i^ ^ :• 

: (2)Method5shallbe;used:tp^MMM 

determine the concentation/(cs) of PM;1 

and voluinetric flow rate (Q„i) of the j 

effluent gas. The sampling time and 

sample volume for each run shall be at 

least 60 minutes and 0.90 dscm (31.8 

. dscf). MMM ;. • .-.-. • .„.,. ;.--,. 

(3) The coke burn-off rate (RJ shall be 

computed for each run using the ^M"•• 

following equation: MvM:,- V-M^-MMM / 

Rc=ki Or (*cc%+%c6a)+ka QD-ki Q,' 

[(%qo/2j+^cpa+%o,j;: ;; \yy.;y-r 

where:.-- ' .^: '••••a-••--;•;• <•'•-•• • • ->-•..-£ y-j^ , 

R,=Coke bunwiff rate,kg/hr (lb/hr);';M.:; 

Q, ^Volumetric flow rate of exhaust gas -* 

from catalyst regenerator before entering the1 

emission control system; dscm/min (dscf/M-; 

' min).:. '•'..'..'.. • •' ;./;.-•• a:.;.';v.;:*'-»i -• A'• -rA••:-."'> 

Q.=Volumetric flow faite of air tp'FCCU: 

;

 regenerator, as determined from the fluid 

catalytic cracking unit control room • • 

instrumentation, dscm/min (dscf/min). ' 

%COt=Carbon dioxide concentration, 

percent by volume (dry basis). 

%CO=Carbon monoxide concentration, 

percent by volume.(dry basis). 

%Oa=Oxygen concentration, percent by 

volume (dry basis). 

Ki=Material balance and conversion 

factor, 0.2982 (kg-min)/(hr-dscm-%) (0.0186 

(lb-min)/(hr-dscf-%)]. 
P,6 

.-•.Federal,.Register; / Mo\.)-4yN6.>39,7.Wedjiesdayir Marchy^,il9S9r/i^pppsedJ^ales . ..;MM:"'MMJ£M 

K2=Material balance and conversion • 

factor, 2.088 (kg-min)/fhr-dscm-%), (0.1303 (lbmin)/(hr-dscf-%)]. 

K3=Material balance and conversion 

factor, 0.0994 (kg-min)/(hr-dscm-%) [0.0062 

(lb-min)/(h«tscMS)]. ''••••_ yr-...'•••• 

(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 

determineCOi,;CO?andC£^M M-'''' 

concentrations. -M M•*.£•>"•.-'••>-A-•• 

(4) Method 9 and the procedures of ': 

§ eo.ll.shall be used to determine:';.r, 

-opacity, ^y 'srwMf^MiK/M^-^M^ aA. 

(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 (Eo) of 

PM shall be computed for each run using 

the following equation: 

E„=1.0+A(H/RJK' 

where: 

E„=Emission rate of PM allowed, kg/100 kg 

(lb/1000 lb) of coke burn-off in catalyst 

regenerator. . 

1.0=Emi88ion standard, kg coke/1000 kg 

fib coke/1080 lb). ... ..'• 

A=Allowable incremental rate of PM 

emissions, 0.18 g/million cal (6.10 lb/million 

Btu). 

H=Heat input rate from solid or liquid 

fossil fuel, million cal/hr (million Btu/hr). 

Re=Coke burn-off rate, kg coke/hr (lb 

coke/hr). '•' 

K'=Conversion factor to units of standard, 

•IJO fkgE/g)/(10t}0 kg) (10s 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 (RJ. 

(d) The owner or operator shall 

determine compliance with the CO 

standard in § 60.103(a) by using the 

integrated sampling technique of 

Method 10 to determine the GO 

concentration (dry basis). The sampling 

time for each run shall be 60 minutes. 

(e) The owner or operator shall . 

determine compUance with the HaS 

standard in § 60.104(a)(1) as follows: 

Method 11 shall be used fo determine 

the HaS 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 .Aminutes niay result in depletion of thie 

collection solution; although fuel gases 

containing low concentrations of.HaS 

may necessitate s_ampling for longer 

periods of time. *. ; 

(fj Theowneror operator shall 'AA 

determine compliance with the SOa and 

the HaSl.^ndTRS standards m *-J&yX-: 

§ 60.104(a)(2) as follows: M; -rxM • Oij 

K (1) Method ® shall be used to AvA 

determine theiSCV concentration/The

 : 

concentration is mg/dscm (lb/dscf) v 

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 (54ft2) or at a point no closer to 

the walls than 1.00 m (39 in.) if the crosssectional 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 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 8 

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 total 

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 TRS and HaS 

concentrations. Each run shall consists 

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. The 

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 SOa equivalent for each 

run shall be calculated after being 

corrected for moisture and oxygen as 

the arithmetic average of the SOa 

equivalent for each sample during the 

run. Method 4 shall be used to determine 

the mositure 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 aiid analysis procedure of -, .•*; 

Method 3. The samples shall be taken •/: 

simultaneously with the SCvTRS and ; 

HaS, of moisture samples/TheJJOiiv, „;-, 

TRS, and HaS samples shall be corrected 

to zero percent excess air using the ,M 

foUoiwng equation:'"AAA-- MMMMV^M '-

!-...'.. .J<-iTV° . ./ * >.*,<•-».;• :•,.-'-. ..... . •:.-? ?....'•:£•?•{•''"<••*:, 

cc=c 

M

:M20.9'^i%OaJ, Wl-.'. 

where:., . .,/•. .-..;• ?. r,-, ...- •-'' ',.,.-•• ;..•.-.: '•;.- • M 

Ct=Cprrecte'd concentration of poUutant; ,. 

ppm by-volume (dry basis).:. .;' . 'AAyyJr. 

C"<= MeasuKfdconcientration'bf pbliutanifM?. 

ppm byvolume (dry IwRlsJ-^r-'^-^'-^-^r^V;^;-

%Os=Oxygen concentration, percent by:».- >' 

volume (dry basis). .--'-,-M 

[FR Doc. 89-4721 Filed Z-28T89; 8:45 am] 

BILLING CODE 6S8ft-50-(3 

DEPARTMENT OF TOE INTERIOR... 

Fish and Wildlife Service '' " . 

50 CFR Part H? •*.-• ••••'•( • • • 

Endangered and IThiirsaSened Wildlife -

and Plants; Proposed Emudamgeredl. ' 

Status tor Queen Alexandra's Btirdwlng 

AGEMCV: Fish and Wildife Service, 

Interior. ,:.. ..; -.«•>. - i 

flCimOM: Proposed rule... - :•.. ' 

SUMMARY: The Service proposes to . 

determine endangered status for Queen 

Alexandra's birdwing butterfly [Troides 

(= OmithopteraJ alexandrae). This 

species, the world's largest butterfly, . 

occurs only ih a small part of Papua 

New Guinea, where it is rare and is 

losing its restricted forest habitat to 

logging and agricultural activity. This 

proposal, if made final, would 

implement the protection of the 

Endangered Species Act of 1973, as 

amended, for this butterfly. The Service 

seeks relevant data and comments from 

the public. 

DATES: Comments must be received by 

May 1,1989. Public hearing requests 

must be received by April 17,1989. 

ADDRESSES: Comments and materials 

concerning this proposal should be sent 

to Chief, Office of Scientific Authority; 

Mail Stop: Room 527, Matomic Building; 

U.S. Fish and Wildlife Service; 

Washington, DC 20240. Comments and 

materials received will be available for 

public inspection from 8:00 a.m. to 4:00