OAR Box 1872 

Prepped by Keeia Richards 

Document Number: 

142) ll-J-4 

Docket Number: 

A-90-19 

Printed 11/26/2008 8:52:04 AM Sheet 142 of 204 
P.2 

Federal Register / Vol. 55, No. 126 / Friday, June 29, 199 

A-90-19 

ll-J-4 ! 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[AD-FRL-2823-6) 

PIN 2060-AB55 

Standards of Performance for New 

Stationary Sources; Volatile Organic 

Compound (VOC) Emissions From the 

Synthetic Organic Chemical 

Manufacturing Industry (SOCMI) 

Reactor Processes 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Fropoi-^d rule and notice of 

public hsanr.g. 

CU5*MAi"Y:The proposed standards 

would hm!? the ernissior.s cf VOC from 

netv. nic'lfied. end reconstructed 

SOO.!: rt: ictor process facilities. The 

prupoieG standards implement section 

1 •; 1 of the Clean Air Act (CAA) and are 

based on the Administrator's 

determination that emissions from the 

SOCMI cause or contribute significantly 

to air pollution which tr.ay reasonably 

bt anticipated to endanger public health 

cr welfare. The intent is to require new, 

modified, and reconstructed SOCMI 

reactor process facilities to control 

(.'missions to the level achievable by the 

lest demonstrated system of continuous 

emission reduction, considering costs, 

r.onai: quality health and environmental 

impacts, and energy requirements. 

A public hearing will be held, if 

;-quested, to provide interested parties 

.' r. opportunity for oral presentation cf 

data, views, or arguments concerning 

the proposed standards. 

DATES: Comments. Comments must be 

received on or before September 12, 

1990. 

Public Hearing. If anyone contacts 

EPA requesting to speak at a public 

hearing by July 20,1990. a public hearing 

will ba held on August 7,1990 beginning 

at 10:00 a.m. Persons interested in 

attending the hearing should call Ms. 

Ann Eleanor at (919) 541-5578 to verify 

that a hearing will be held. 

Request to Speak at Public Hearing. 

Persons wishing to present oral 

testimony must contact EPA by July 20, 

1990. 

Incorporated by Reference. The 

incorporation by reference of certain 

publications in these standards will be 

approved by the Director of the Federal 

Register as of the date of publication of 

the final rule. 

ADDRESSES: Comments. Comments 

should be submitted (in duplicate if 

possible) to: Central Docket Section 

(LE-131), Attention: Docket Number A83-29, U.S. Environmental Protection 

Agency. 401 M Street, SW., Washington, 

DC 20460. 

Public Hearing. If anyone contacts 

EPA requesting a public hearing, it will 

be held at the EPA's Office of 

Administration Auditorium, Research 

Triangle Park, North Carolina. Persons 

interesisd in attending the hearing or 

wishing to present oral testimony should 

notify Ms. Julia Stevens, Standards 

Development Branch (MD-13), U.S. 

Environmental Protection Agency. 

Research Triangle Park, North Carolina 

27711. telephone number (919) 541-5578. 

Background Information Document 

The background information document 

(BID) for the proposed standards may be 

obtained from the U.S. EPA library 

(MD-35), Research Triangle Park, North 

Carolina 27711, telephone number (919) 

541-2777. Please refer to "Reactor 

Processes in Synthetic Organic 

Chemical Manufacturing Industry— 

Background Information for Proposed 

Standards," EPA/450-3/85-O05a. 

Docket. Docket Number A-83-29, 

containing supporting information used 

in developing the proposed standards, is 

available for public Inspection and 

copying between 8 a.m. and 4 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: 

Mr. Doug Bell or Ms. Debbie 

Stackhouse, telephone (919) 541-5568 

and 5258, respectively, concerning 

regulatory decisions. Mr. Robert E. 

Rosensteel or Mr. Leslie B. Evans, 

telephone (919) 541-5608 and 5410. 

respectively, concerning technical 

aspects of the industry and control 

technologies. The address for the above 

contacts is Emission Standards Division 

(MD-13), U.S. Environmental Protection 

Agency, Research Triangle Park, North 

Carolina 27711. 

SUPPLEMENTARY INFORMATION: 

I. Introduction 

A. New Source Performance 

Standards—General 

New source performance standards 

(NSPS or "standards") implement 

section 111 of the CAA. The NSPS are 

issued for categories of sources which 

causa, or contribute significandy to, air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. They apply to new stationary 

sources of emissions, i.e., sources whose 

construction, reconstruction, or 

modification begins after a standard for 

them is proposed. 

control emissions tpithe level»achievabl»r 

by "best demonstrat _ 

"BDT," which is defSwd»inHtenrB:d; 

below. 

dt@naiog\i'RrOCC.C 

B. The NSPS Decision Scheme 

An NSPS is the product of a series of 

decisions related to certain key 

elements for the source category being 

considered for regulation. The elements 

identified in this "decision scheme" are 

generally the following: 

1. Source category to be regulated— 

usually an entire industry but can be a 

process or group of processes within an 

industry. 

2. Pollutant(s) to be regulated—the 

particular substance(s) emitted by the 

source that the standard will control. 

3. Regulatory approach—the genera! 

strategy for regulating sources. 

4. Affected facility—the pieces or 

groups of equipment that comprise the 

sources to which the standards will 

apply. 

5. Emission points to be regulated— 

within the affected facility, the specific 

physical location emitting pollutants 

(e.g., vents, stacks, and equipment 

leaks). 

6. Best demonstrated technology—the 

technology on which the Agency will 

base the standards, i.e., 

* * * application of the best technological 

system of continuous emission reduction 

which (taking into consideration the cost of 

achieving such emission reduction, and any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated. (Section 111(a)(1)). 

7. Format for the standards—the form 

in which the standards are expressed, 

i.e., as a percent reduction in emissions, 

as pollutant concentrations or aa 

equipment standards. 

8. Actual standards—based on what 

BDT can achieve, the maximum 

permissible emissions. 

Note: In general, standards do not require 

that a specific technology be used to achieve 

them. The source owner/operator may select 

the method for achieving the pollution control 

required.) 

9. Other considerations—in addition, 

this NSPS includes: modification/ 

reconstruction considerations, 

performance test methods, monitoring 

requirements, and reporting and 

recordkeeping requirements. 

C. Overview of This Preamble 

This preamble will: 

1. Summarize the important features 

of this NSPS by discussing the 

conclusions reached with respect to 
P.3 

26954 Federal Register / VoL 55, Na 126 / Friday, June 29, 1990 / Proposed Roles 

each of the elements in the decision 

scheme. 

2. Describe the estimated 

environmental, energy, and economic 

impacts of this NSPS. 

3. Present a rationale for each of the 

decisions in the decision scheme. 

4. Discuss administrative 

requirements relevant to thia action. 

II. Summary of the NSPS 

J4. Source Category to be Regulated 

The source category to be regulated is 

the SOCML Tliese standards affect the 

reactor process subcategory of the 

SOCML A reactor process is the means 

by which one or more synthetic organic 

chemicals are produced by the reaction 

of feedstocks or chemical intermediates 

other man air. (Processes using air are 

covered in a separate NSPS.) 

B. Pollutant to be Regulated 

The proposed standards would 

control emissions of VOC from reactor 

process vent streams. 

C. Regulatory Approach 

Rather than develop a separate 

standard for each chemical produced in 

reactor processes, this proposal is a 

single standard covering all reactor 

processes producing one or more 

designated high production volume 

chemicals. These 173 high production 

volume chemicals account for about 90 

percent of total chemical production 

from the SOCMI and are estimated to 

account for the majority of the emissions 

from reactor processes as well. This 

same approach was used in the two 

previous process vent standards for the 

SOCMI (distillation. 48 FR 57538, and air 

oxidation. 48 FR 48932). 

D. Affected Facility 

The facility affected by the proposed 

standards is designated as a single 

reactor with its own recovery system (if 

any) or the combination of two or more 

reactors and the common recovery 

system they share. 

E. Emission Points to be Regulated 

The emission points to be regulated 

include VOC discharged from chemical 

reactors either directly from a reactor or 

indirectly after passing from one or 

more reactors through one or more 

product recovery devices. 

F. Best Demonstrated Technology 

A variety of control techniques are 

capable of reducing VOC from reactor 

process vent stream by 98 weightpercent or to 20 parts per million by 

volume (ppmvl However, certain 

combustion controls (thermal 

incinerators and flares) are the only 

devices that are applicable to all reactor 

process vent streams. The selection of 

the best device for an individual stream 

depends on the process vent stream 

characteristics and other site-specific 

considerations. Bach of these two 

devices, however, is capable of 

achieving 98 weight-percent VOC 

destruction or 20 ppmv. 

For facilities where the costs of 

combustion control by thermal 

incinerators or flares ara reasonable, 

BDT is 98 weight-percent control or 

reduction to 20 ppmv, whichever is less 

stringent For facilities where the costs 

to control VOC by combustion are not 

reasonable, BDT is no additional 

controL The standards do not require 

that a specific device or technology be 

used to comply with the emission 

reduction requirements. Rather, any 

control can be used as long as it can be 

demonstrated that it is at least as 

effective as BDT at reducing VOC 

emissions. Trie EPA is unable, with 

available information, to identify 

subcategories of reactor processes for 

which VOC control techniques other 

than incineration or flaring (e.g., 

catalytic oxidation and carbon 

adsorption) have been demonstrated to 

always apply. The applicability of these 

devices may be greatly affected by the 

vent stream flow rate, water content 

temperature, VOC concentration and 

VOC properties such as solubility, 

molecular weight and liquid/vapor 

equilibrium. These characteristics vary 

widely within the SOCML Therefore, 

consideration of these devices in 

developing regulatory options was not 

feasible. Even with greater resources, 

this analysis would be Infeasible 

because it would require a stream-bystream characterization, ultimately 

resulting in die need to create a separate 

standard for each reactor process 

facility. Hie number of standards 

required to regulate the same number of 

sources would increase significantly. 

The Agency believes that such an 

approach to regulating SOCMI reactor 

processes would be administratively 

infeasible and therefore 

environmentally counter-productive. 

This approach does not preclude later 

regulation of subcategories of reactor 

process facilities should diat become 

feasible. 

C. Format ofthe Standards 

The format of the proposed standards 

would allow owners and operators of 

affected facilities to comply with the 

standards by controlling emissions or by 

maintaining or adding product recovery 

devices. Where me cost effectiveness of 

controls is reasonable, a percentage 

reduction or concentration limit 

whichever is less stringent would apply. 

Where the costs of control are 

unreasonably high, no additional 

emission reduction would be required. 

The cutoff is calculated by using a set of 

equations and coefficients in the 

regulation that produce a total resource 

effectiveness (TRE) index value. A TRE 

index value of 1.0 or less indicates the 

need to control. This format permits 

owners and operators of facilities near, 

but below, the 1.0 cutoff to change the 

process operation or equipment in order 

to reduce emissions and, thereby, raise 

the TRE index value to a point above 

the cutoff. 

H. Actual Standards 

Sources with TRE values of 1 JO or 

below would be subject to the following: 

(1) A 98 weight-percent reduction of the 

total organic compounds (minus 

methane and ethane) in the reactor vent 

stream, or a reduction to 20 ppmv, 

whichever is less stringent; (2) if a boiler 

or process heater is used to comply with 

the standards, the reactor vent stream 

must be Introduced into the flame rone; 

(3) if a flare ia used to comply with the 

standards, it must comply witii the 

requirements set forth in 40 CFR 60.18. 

For sources where the costs of 

combustion control result in a TRE 

index value greater than 1.0. no 

additional VOC control is required. 

Facilities with low flow rates (less 

than or equal to 0.011 scm/mln) and 

facilities which are in process units with 

low production capacities (less than or 

equal to t gigagram per year for all 

chemicals produced) would be exempt 

from the standards except for certain 

recordkeeping and reporting 

requirements. Batch processes would 

also be exempt from the standards, 

/. Modification/Reconstruction 

Considerations 

An existing facility would be required 

to meet these standards if it is modified 

or reconstructed as determined under 

the General Provisions of 40 CFR part 

60. With some specific exceptions, an 

existing facility is considered to be 

modified if a physical or operational 

change results in an increase in VOC 

emissions. For example, if a reactor is 

added to a group of existing reactors 

and if an Increase in VOC emissions 

results, all reactors—existing and new— 

would be subject to the standards 

because the facility had been modified. 

A reconstruction occurs when 

components of an existing facility ara 

replaced to such an extent that the fixed 

capital costs of ths new components 

exceed SO percent of die fixed capital 

costs that would be required to 
P.4 

Federal Register / Vol. 55. No. 128 / Friday. )une 29. 1990 / Proposed Rules 26955 

construct an entirely new facility 

comparable to the existing facility..A 

facility will be considered to have been 

reconstructed only if it is technologically 

and economically feasible for the 

facility to meet the standards. 

/. Compliance Testing 

Initial performance testing is required 

to demonstrate that a facility complies 

with the TRE provisions of the standard 

or, for facilities complying with the 

emission reduction requirements, that 

control devices achieve 98 weightpercent control of VOC emissions or 20 

ppmv. Facility owners or operators 

seeking to demonstrate compliance with 

the TRE index provisions must 

determine vent stream flow rate, heating 

value, VOC emissions, and the presence 

or absence of halogenated compounds. 

The vent stream heating value and flow 

rate are used to select the appropriate 

TRE index coefficients for calculating 

the TRE index value. For facilities that 

seek to comply with the 98 weightpercent reduction requirement, an initial 

performance test is required if an 

incinerator, a small boiler or small 

process heater (less than 150 million 

Btu/hr) is used. The initial perfonnance 

test for a flare includes a measurement 

of exit velocity and stream heat content 

to verify that the operating 

specifications are met. The initial 

performance test has been waived for 

large boilers and large process heaters 

(greater than 150 million Btu/hr). 

K. Monitoring Requirements 

For facilities using any combustion 

device to comply with the emission 

reduction requirements, vent stream 

flow to the combustion device would be 

monitored by use of flow indicators. For 

facilities using thermal incinerators, 

small boilers or small process heaters, 

continuous measurements of firebox 

temperatures are also required. For 

facilities using large boilers or large 

process heaters, records indicating 

when the device is being operated are 

also required. For facilities using a flare, 

the regulation requires continuous 

monitoring of the presence of a flame. 

For facilities using catalytic incinerators, 

the regulation requires continuous 

monitoring of the gas stream 

temperature immediately before and 

after the catalyst bed. 

For facilities using product reco% ery 

devices to maintain a TRE index value 

greater than 1.0. the following 

parameters are required to be 

continuously monitored: The 

temperature and specific gravity of the 

absorbing liquid where an absorber is 

the final product recovery device; the 

exit temperature of the vent stream 

where a condenser is the final product 

recovery device; and the carbon bed 

temperature and regeneration stream 

flow where a carbon adsorber is the 

final product recovery device. 

L. Reporting and Recordkeeping 

Requirements 

As required under the General 

Provisions of 40 CFR part 60. the 

recommended standards require three 

types of reports. First, there are 

notification requirements under the 

General Provisions, which would enable 

the Agency to keep abreast of facilities 

subject to the standards of performance. 

Second, there is the reporting of 

performance test results, which would 

show that a facility is meeting the 

standards initially. Third, there is the 

semiannual reporting of exceedances of 

certain monitored parameters and any 

change in equipment or process 

operation that could affect compliance 

with the TRE or emission reduction 

requirements or with the low flow and 

low capacity exemptions. The proposed 

standards would require records 

indicating proper operation and 

maintenance of the control device or 

product recovery equipment. First, 

specific operating parameters would be 

monitored and the results recorded. 

Second, records of periods when the 

measured values of these parameters 

significantly deviated from the values 

measured in the most recent 

performance test would be maintained. 

Third, there would be recordkeeping of 

major changes that could affect the TRE 

index value or the low flew and low 

capacity exemption status. Finally, 

records and reporting of periods when 

control device are not operating or when 

the vent stream is not routed to the 

control device would be required. 

III. Impacts of the NSPS 

A. Air 

In the fifth year after this NSPS is 

proposed, it is estimated that 

nationwide emissions of VOC will be 

decreased by 2,100 megagrams per year 

compared with projected emissions 

calculated to occur in the absence of the 

standards (baseline). During the first 5 

years of the standards' apphcability, en 

estimated 58 facilities would be 

candidates for the control attributable 

solely to the requirements of this NSPS. 

It is estimated that 7 of the 56 facilities 

are anticipated to be required to meet 

the 98 weight-percent reduction 

requirements. However, the VOC 

emissions from the 7 facilities account 

for about 90 percent of the total from all 

56 facilities. Any increase in emissions 

of other air pollutants as a result of 

controlling VOC emissions will be 

negligible. 

B. Water 

A Negligible increase in total plant 

wastewater is projected under this 

NSPS. 

C. Solid Waste. Noise and Radiation 

No solid waste, noise, or radiation 

impacts are expected under this NSPS. 

D. Energy 

In the fifth year after this NSPS wov.!d 

become applicable, energy consumption 

in the SOCMI nationwide would be 

increased by as much as the equivalent 

of about 141 barrels of crude oil per day 

if incinerators and flaxes are used to 

comply with the proposed standards 

when compared with the existing energv 

consumption associated with the 

baseline level. 

E. Control Costs 

During'the fifth year of applicability of 

the proposed standards, the nationwide 

annualized costs of control at facilities 

covered by the standards would amour, t 

to $3.7 million (1982 dollars) per year. 

The nationwide cumulative 5-year 

capital costs for control under the 

proposed standards would be $5.9 

million (1982 dollars). These costs are 

based on the assumption that flares or 

incinerators would be used to comply 

with the proposed standards. If less 

expensive control devices such as 

boilers and process heaters are used, the 

costs would be significantly lower. 

F. Economic Effects 

No chemical that is projected both to 

have new, modified, or reconstructed 

facilities built in the first 6 years of the 

standards and to be required to control 

emissions beyond current State 

requirements is projected to have a price 

increase greater than 5 percent. 

Furthermore, chemicals that are 

produced downstream of die listed 

chemicals will not have price increases 

over 5 percer.i. Most of the projected 

price increases for the listed chemicals 

and chemicals produced downstream 

are small: 81 percent are under 2 

percent. Lr.pacts on industry structure, 

industry growth, inflation, foreign trade, 

and capital formation are projected to 

be insignificant. 

IV. Rationale for the Proposed 

Standards 

A. Selection of Scarce Category 

The EPA priority list, 40 CFR 60.18 (44 

FR 49222, August 21,1979), ranks major 

source categories for which NSPS are to 

be promulgated. This list implements 
P5 

T 

Fsdeml asgistiBF / VoL 55, No. 128 / Friday. June 29, 1SS0 / Proposed Rules 

section 111(b) of the Clean Air Act and 

reflects the Administrator's 

determination that emissions from the 

listed source categories contribute 

significantly to air pollution that 

endangers health or welfare. The 

SOCMI was ranked highest priority for 

NSPS development on the final priority 

list of 59 major source categories. 

Organic chemical plants are a major 

source of VOC emissions that contribute 

to ozone formation. 

The VOCs are emitted from four main 

subcategories of sources within the 

SOCMI: Losses from storage and 

handling of volatile organic liquids, 

fugitive leaks from valves and process 

equipment, evaporative losses from 

liquid and solid wastes (secondary 

sources), and emissions from process 

vents. A breakdown by source type 

indicates that over half of the VOC 

emitted from the SOCMI are from 

process vents. 

Process vent emission sources are 

typically associated with product 

recovery systems in a SOCMI chemical 

manufacturing facility. Process vent 

emission sources consist primarily of the 

venting of VOC-containing inert gases 

and evacuation of equipment for 

vacuum processing. For purposes of 

developing an NSPS for the SOCMI, 

EPA has divided process vents into two 

categories: Continuous and batch 

processes. Batch process vents are 

currently being evaluated by the 

Agency. Continuous process vents 

include distillation unit operations, air 

oxidation processes, and reactor 

process. Standards for distillation unit 

operations were proposed on December 

30.1983 (48 FR 57538). Standards for air 

oxidation processes were proposed on 

October 21,1983 (48 FR 48932). The 

standards being proposed today address 

the third type of process vents: Reactor 

processes. A reactor process is the 

means by which one or more substances 

or reactants. otiier than air. are 

chemically altered such that one or more 

new organic chemicals are formed. The 

VOCs are emitted from reactor process 

vents in one of two ways: (1) Indirectly 

from the reactor following product 

recovery (e.g., tiirough condensation, 

absorption, or adsorption), or (2) directly 

from the reactor to die atmosphere. An 

estimated 8 percent of the total VOC 

emitted by the SOCMI source category 

are from reactor processes. 

In developing standards, 

environmental, cost, economics, small 

business, and other impacts are 

examined. It would be very resource 

intensive and time consuming to analyze 

all of these impacts for each of the many 

chemicals produced. The result of 

following such am approach would bs to 

delay developing standards 

significantly, (resulting in him in a 

significant loss in emission reduction. 

Therefore, EPA has decided to limit the 

scope of these standards initially to a 

relatively small number of high 

production chemicals. The Agency 

performed an analysis to determine the 

probable effects of ouch a limitation. 

Two alternatives were considered for 

limiting the scope to nigh production 

volume synthetic organic chemicals. The 

first involved limiting the scope of the 

standards to about 870 organic 

chemicals produced in quantities greater 

than 4,500 Mg/yr (10 million Ib/yr). This 

would cover roughly 97 percent of 

organic chemical production but would 

result in an unworkable number of 

chemicals for the impact analyses. The 

second alternative would limit the scope 

of the standards to 173 organic 

chemicals generally produced in 

quantities greater than 45,000 Mg/yr (100 

million lb/yr). The chemicals covered 

under this second alternative would 

account for about £0 percent of total 

U.S. production of organic chemicals. 

Therefore, the Administrator concluded 

that limiting the scope of the standards 

to die 173 chemicals generally produced 

in quantities greater than 45,000 Mg/yr 

would provide a workable scope while 

covering the great majority of organic 

chemical production. A list of the 

affected chemicals is included in the 

regulation. 

B. Pollutant to be Regulated 

In addition to VOC emissions, other 

pollutants are emitted from reactor 

process sources in much smaller 

quantities. These include carbon 

monoxide (CO). Nitrogen oxides (NOJ 

sulfur oxides (SOJ and hydrochloric 

acid (HCI). The VOC is by far the 

primary pollutant emitted from reactor 

processes. Due to the size and 

complexity of this source category, 

acquiring the information to determine 

the applicable technology for the other 

pollutants that have low emissions at 

the same time the Agency analyzes the 

pollutant covered by these standards 

would have been an unmanageable task. 

Therefore, the pollutant to be regulated 

by these standards io VOC. 

C. Selection of Regulatory Approach 

Two general regulatory approaches 

were considered for use in developing 

standards for reactor processes. The 

first approach would involve 

establishing standards for each of the 

173 specific chemicals included under 

these proposed standards. St would be 

very difficult to develop standards using 

this approach due to the large number of 

chemical reactions and chemical 

products that are produced by reactor 

processes and the variable emission 

characteristics associated with each. 

There are about 39 separate types of 

chemical reactions usee* to produce the 

173 chemicals that account for the great 

majority of the emissions from reactor 

processes. 

The second approach involves the 

development of standards on the basis 

of similar types of emission sources and 

applicable emission control techniques. 

This approach would allow a timely and 

resource-efficient regulatory 

development because a large number of 

specific chemicals can be covered by 

only one regulation. Using this approach 

would mean that an NSPS for the 

SOCMI reactor processes could be 

developed in a relatively short period of 

time at much less public cost, compared 

to the chemical-by-chemical approach. 

Despite the large number of reaction 

types and chemicals produced by 

reactor processes, VOC emissions from 

reactor process units can be controlled 

by commonly used combustion and 

noncombustion control techniques. 

Because regulating the entire group 

would be more resource-efficient and 

the chemical-by-chemical approach is 

for practical purposes infeasible and 

lacks any clear advantage, the 

Administrator has determined that a 

single regulation should be proposed for 

all reactor processes in the SOCMI. This 

approach is consistent with the 

approach taken for the SOCMI 

distillation and air oxidation standards. 

D. Selection of Affected Facility 

The choice of the affected facility for 

these standards is based on the 

Agency'o interpretation of section 111 of 

the Clean Air Act and on the judicial 

construction of its meaning [ASARCO. 

Inc., v. EPA. 578 F.2d 319 (D.C. Cir. 

1978)). Under Section ill. the standards 

of performance for new stationary 

sources must apply to "new sources." 

"Source" is defined as "any building, 

structure, facility, or installation which 

emits or may emit any air pollutant" 

(section 111(a)(3)). Most industrial 

plants, however, consist, of numerous 

pieces or groups of equipment that emit 

air pollutants and that may be viewed 

as "sources." The EPA. therefore, uses -

the term "affected facility" to designate 

the equipment within o particular kind 

of plant that is chosen as die "source" 

covered by a given standard. 

In designating the affected facility, 

EPA must decide which piece or group 

of equipment is the appropriate unit (the 

source) for emission otandardo in the 

particular industrial context. The 
P.6 

Federal Register / Vol. 55, No. 128 / Friday, June 29, 1990 / Proposed Rules 

Agency must do this by examining the 

situation in light of the terms and 

purpose of section 111 of the Clean Air 

Act. The main purpose of section 111 is 

to minimize emissions by requiring the 

application of BDT at all new, modified, 

and reconstructed sources (considering 

cost nonair quality health and 

environmental effects, and energy 

impacts). The EPA believes that in most 

cases a narrow affected facility 

designation will best further this 

purpose, because in most cases a 

narrow designation ensures that new 

emission units will be brought under the 

coverage of the standards. If, for 

example, an entire plant is designated 

as the affected facility, no part of an 

existing plant would be covered by die 

standard unless the replacement caused 

the plant as a whole to be "modified" or 

"reconstructed." If each piece of 

equipment is designated as a separate 

affected facility, then as each piece is 

replaced, die replacement piece would 

be a new source subject to the 

standards. For this reason, EPA 

generally presumes that the narrow 

designation is appropriate. 

The EPA treats the narrow 

designation only as a presumption, 

however, because in some cases a 

broader affected facility designation 

may be more consistent with the 

ptiroses of section 111. For example, the 

Agency might choose a broader 

designation if it concluded that either (a) 

it would result in greater emissions 

reduction than would a narrow 

designation; or (b) the otiier relevant 

statutory factors (technical feasibility, 

economic cost, energy, and nonair 

quality health and environmental 

impacts) point to a broader designation. 

The EPA analyzed several alternative 

affected facility designations for the 

reactor process standards, including (1) 

each individual reactor witii its recovery 

system; (2) tiie group of reactors whose 

vent streams flow togedier through a 

single recovery system: and (3) the 

entire plant. Using the presumption 

mentioned above, EPA examined as a 

single affected facility each individual 

reactor whose vent stream is sent to its 

own recovery system. The EPA 

concluded, however, that when reactor 

vent streams are joined and sent 

through a single recovery system, the 

group of reactors and their recovery 

system, rather than each reactor, should 

be a single affected facility. 

The EPA estimates that a greater 

reduction in national VOC emissions 

would likely result under the broader 

designation of affected facility. This 

conclusion io based upon the behavior 

of the industry with regard to the 

expansion of reactor capacity and 

replacement reconstruction or 

modification of existing reactors. 

Capacity expansions will occur either 

as a result of new facilities being built or 

existing ones being expanded. When 

expanding production capacity et an 

existing reactor facility, it is common 

industry practice to add new reactors to 

existing sets of reactors and recovery 

systems. When this occurs, there are 

two possible outcomes under the 

broader affected facility designation— 

both of which will result in a greater 

emissions reduction than would occur 

under a more narrow designation of 

affected facility. One possibility is that 

the total emissions from die group of 

reactors will increase. In this case, it 

would bring all (new plus existing) 

reactors discharging into a common 

recovery system under the standard by 

virtue of the NSPS General Provisions 

regarding "modifications." The second 

possibility is that the owners or 

operators of the plant could completely 

offset the increased emissions from the 

new reactors by increasing recovery. 

Although this outcome is unlikely, the 

result is that a greater emissions 

reduction will occur under the broad 

rather than the narrow designation of 

affected facility. The reason is that by 

completely offsetting the increased 

emissions from the new reactors through 

additional recovery, the emissions from 

the new reactors have been controlled 

at 100 weight-percent effectiveness. This 

exceeds the control effectiveness (i.e.. 98 

weight-percent) required under tiiis 

standard. 

Replacement of existing reactors 

rarely occurs within the industry 

because reactors are expensive pieces 

of equipment designed and usually built 

to last the lifetime of the plant. Reactor 

replacements usually occur as a result of 

process changes (e.g., from chlorination 

to hydrochlorination) or as a result of 

fires or explosions. Whether in 

multireactor or single reactor facilities, 

the replacements of individual reactors 

(as opposed to replacement of entire 

facilities) are rare. When reactor 

replacements do occur, however, all 

reactors tend to be replaced, and, 

therefore, the reactor replacements 

would bring the entire facility under the 

standards under the broader affected 

facility designation. 

Reactor changes that source owners ' 

could make that might be considered 

modifications are substantial changes in 

catalysts, reactor conditions, or product 

separation purification equipment. The 

cost of these changes is so great, 

however, that most owners would 

choose to build a new group of reactors 

rather than radically modify individual 

existing reactors. Therefore, few 

reactors would undergo process changes 

that might be considered a modification 

under any designation of affected 

facility. 

Thus, greater emissions reductions are 

likely to occur under this broader 

designation. For that reason, the 

Administrator has determined that the 

appropriate affected facility designation 

is an individual reactor with its own 

individual recovery system (if any) or 

the combination of two or more reactors 

and the common recovery system they 

share. 

When several reactors feed vent 

streams into a common recovery system, 

the characteristics of the emissions 

vented into the atmosphere from the 

recovery system are determined by both 

the vent streams from each of the 

reactors and the efficiency of the 

recovery system. Under the narrow 

designation, it would have been required 

that only that portion of the combined 

vent stream contributed by any new, 

modified or reconstructed reactor unit 

comply with the standards when the 

unit shares a recovery system with 

existing units. Therefore, the TRE index 

value would have been determined for 

the portion of the stream contributed by 

that unit only. At least three sampling 

locations would be used in this case. 

Two of the locations (i.e., before and 

after the common recovery system) 

would be used to determine the overall 

efficiency of the common recovery 

system. This efficiency would then be 

applied to the emissions measurement 

taken at the third sample location which 

is just prior to the new or changed unit 

being joined with any other vent stream. 

Thus, three sample locations would be 

needed to determine the contribution by 

die new or changed unit to the total 

emissions from the common recovery 

system. 

However, under the broader affected 

facility option selected above, only one 

sampling site is necessary to determine 

the facility's TRE index value. No 

estimation of the recovery system's 

efficiency on individual reactors is 

required, because the standards cover 

the entire vent stream. Therefore, there 

is no need to determine which portion of 

the final vent stream from a group of 

reactors is attributable to new, modified, 

and reconstructed reactors and which 

portion is attributable to reactors that 

have not been changed or added. This 

results in performance testing that is 

simpler and cheaper because fewer 

sampling sites and simpler analyses are 

needed. 
P.7 

26958 Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 

The Administrator has decided to 

exclude from these standards reactors 

that are operated in a batch mode rather 

than operated continuously. The data 

upon which the standards are based 

(including the cost and control device 

perfonnance) assume a continuous or 

near continuous type of operation. 

Also excluded from these standards 

are facilities in plants witii very low 

capacities or with very low vent stream 

Hows. Most research and development 

or laboratory scale facilities are not 

designed to produce more than one 

gigagram (Gg) per year. It is not the 

intent of the standards to cover such 

facilities because they are generally 

intermittent operations. Moreover, the 

control techniques that are applicable to 

industry-scale production facilities 

would not necessarily be appropriate for 

these operations. For tiiese reasons, EPA 

has decided to exempt facilities which 

are part of process units with one Gg 

production capacity per year or less of 

ail chemicals produced witiiin die 

process unit. Similarly, facilities with 

vent stream flows below 0.011 standard 

cubic meters per minute (scm/min) are 

excluded from the standards. No facility 

with flows below this cutoff are 

anticipated to have TRE index value 

less than 1.0, and thus to include diem 

under the standards would impose 

unnecessary reporting and 

recordkeeping requirements on these 

facilities. For the low flow facilities, 

only an initial measurement and report 

ia required to verify entitlement lo ike 

exclusion. In addition, owners and 

operators of both low capacity and low 

flow facilities are required to notify EPA 

if a change occurs that would result in 

production capacities or Cows above the 

respective cutoff levels. 

E. Selection of Control Techniques 

The Clean Air Act requires that 

standards of perfonnance be based on 

t;:3 best system of continuous emission 

reduction, considering costs, energy 

usage and nonair health and 

environmental impacts ("best 

demonstrated technology" or BDT). As 

discussed in the BID. one or more 

combustion techniques (boiler, process 

heater, incinerator, or flsri's) are 

cpplicabis to arty redcior process vent 

stream and can achieve a! least Go 

weight-percent control or 20 pprnv in the 

outlet gss. 

However, combustion control devices 

are the only types of control devices 

which are applicable to reactor 

processes. The EPA examined several 

VOC control technologies that achieve 

the same or less emission reduction. 

such as absorption, adsorption, 

condenser devices, and catalytic 

oxidation, but found that tiiese control 

technologies are not applicable to all 

reactor process vent streams. Moreover, 

EPA is unable, with available 

information, to identify subcategories of 

reactor processes for which the above 

mentioned control technologies have 

been demonstrated to always apply. The 

applicability and effectiveness of these 

devices may be greatly affected by the 

vent stream flow rate, water content, 

temperature. VOC concentration, and 

VOC properties such as solubility, 

molecular weight, and liquid/vapor 

equilibrium. These characteristics vary 

widely within die SOCMI. Therefore, 

there is no way to evaluate technologies 

for application to reactor process units 

for which tiiermal incineration and 

flaring have been determined to be too 

costly. Even with greater resources, this 

approach would be infeasible because it 

would require a stream-by-stream 

characterization, ultimately resulting in 

the need for a separate standard for 

each vent stream from a process used to 

produce a reactor chemical. 

Combustion devices were found to be 

applicable to any nonhalogenated vent 

stream. For incinerators, operating 

conditions can be identified tiiat will 

ensure 98 weight-percent reduction or 20 

ppmv total organics (minus methane and 

ethane) in die outlet gas, whichever is 

less stringent. Boilers and process 

heaters were found to be capable of 

achieving 98 weight-percent reduction if 

the organic-laden stream is used as a 

fuel and is put into die flame zone. In 

recent tests, smokeless steam-assisted, 

air-assisted and nonassisted flares were 

also found to be as efficient as these 

other combustion devices in achieving 

98 weight-percent reduction of VOC if 

they were operated as specified in 40 

CFR 60.18. In terms of cost, boilers and 

process heaters are generally the least 

expensive combustion devices, because 

these units are already in place in 

SOCMI plants and because of heat 

recovery from the VOC-containing vent 

streams. Flares can control most 

nonhalogenated VOC-containing 

streams for less cost than incinerators. 

Incinerators were found to be the only 

devices applicable to halogenated 

streams because incinerators can accept 

a wide variety of stream types and can 

be constructed to tolerate the corrosive 

effects of halogenated streams. 

Furthermore, an absorber can be used to 

remove halogens from the offgases 

exiting the incinerator. 

In summary, 98 weight-percent control 

or reduction to 20 ppmv is achievable 

for all halogenated and nonhalogenated 

reactor process vent streams using one 

of the combustion devices discussed 

above. Thus, these four combustion 

devices are candidates for BDT for the 

emission source category of organic 

chemical reactor processes. 

Since vent stream characteristics 

within this category vary widely, it is to 

be expected that die cost per unit of 

emission reduction among streams will 

also vary. The potential environmental 

impacts of using a combustion device to 

control VOC emissions vary from vent 

stream to vent stream. The 

Administrator, therefore, has analyzed 

the environmental, economic, and 

energy impacts and die cost per unit oi 

emission reduction for reactor processes 

vent streams included in the scope of 

tiiese standards to determine if. due to 

adverse impacts associated with the use 

of die most applicable combustion 

devices, BDT for certain classes, types. 

or sizes of reactor processes might be no 

additional control. The following 

sections discuss these additional 

impacts. 

Consideration of Environmental Impacts 

The potential adverse environmental 

impacts that could result from reactor 

process standards were assessed. The 

generation of NO, by the combustion 

process was examined as a possible 

native impact on ambient air quality. 

The principal factors affecting the rate 

of NO, formation during combustion are 

the amount of excess air available, the 

peak temperature, and die rate of 

cooling of die combustion products. 

Relatively low combustion temperatures 

of approximately 870 °C (1,600 °F) are 

associated with control of VOC using 

thermal incinerators, and residence 

times are generally too short to be 

conducive to NO, formation. Therefore, 

the rate of NO, formation is expected to 

be low if incinerators are used. 

Introduction of a reactor process vent 

stream as a supplement to the fuel and 

combustion air normally introduced into 

a boiler or process heater could, in some 

cases, result in increases in NO, 

emissions. The combustion temperatures 

in these devices are well in excess of 

2.000 'F and are therefore conducive to 

NO, formation, and sums reactcr 

process vents being controlled would 

contain nitrogenous organic compounds 

or nitrogen from air in the vent stream. 

However, reactor process vent slreams 

would represent only a small part of the 

total input to the boiler or heatt r. Also, 

in many case3. ir.troducuon cf the 

reector process vent stream wculd result 

in lowered fuel requirements anj could 

result in lower NO, emissions if the 

nitrogen from nitrogenous organic 

compounds is less than the fuel-bound 

nitrogen of the fuel being replaced In 
P.8 

Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 26959 

addition, measures to minimize NO, 

formation could be implemented due to 

NO, standards under development for 

industrial boilers. Any Increase or 

decrease in NO, emissions due to 

introduction of the reactor process 

stream would be slight. 

Only limited data are available for 

NO, emissions from flares. In a recent 

study of steam-assisted and air-assisted 

flares, the highest estimated NO, 

emissions were well below the reported 

NO, emissions tabulated for industrial 

boilers and process heaters firing gas or 

oil. Because NO, emissions from flares 

are less than the NO, emissions from 

boilers and process heaters (which are 

themselves slight), NO, emissions from 

flares are considered to be insignificant. 

Therefore, any increase in NO, 

emissions resulting from the combustion 

of a reactor process vent stream is 

expected to be relatively small. 

In additions to generation of NO,, the 

control of VOC emissions from 

halogenated vent streams by thermal 

incinerators may result in the release of 

halogenated combustion products to the 

environment. However, Due gas 

quenching and scrubbing could be used 

to remove these compounds from the 

incinerator outlet stream. State or local 

regulations may require use of these 

scrubbers if die halogenated combustion 

products are in high enough 

concentrations. Current industry 

practice among reactor process facilities 

with halogenated vent streams that 

employ combustion devices is to use 

flue gas scrubbing to reduce plant 

maintenance costs by preventing 

corrosion of equipment. The capital cost 

and operating costs associated with flue 

gas quenching and scrubbing were taken 

into account in projecting the cost 

impacts for the standards. 

Control of VOC emissions using 

combustion devices would not result in 

any significant increase in wastewater 

discharge by reactor processes. No 

water effluents are generated by the 

combustion devices themselves. 

Use of an incinerator/scrubber system 

for control of VOC emissions from 

halogenated streams would result in 

increased water consumption. The 

increase in total plant wastewater 

would be relatively small and would not 

affect plant waste treatment capacity or 

sewer capacity. However, if the 

scrubber effluent is not recovered, it 

may be necessary to adjust the pH of 

the scrubber effluent by treatment with 

caustic (NaOH) before it is released into 

the plant wastewater system. The salt 

(NaCl) formed by the caustic treatment 

must be purged from the system and 

properly disposed. Brine solutions are 

currently disposed of in a variety of 

ways depending on site-specific 

conditions. These include direct 

discharge to sewer systems and surface 

waters (fresh and salt water bodies or 

rivers), discharge to evaporative 

lagoons, and injection into a disposal 

well. Because it is not possible to 

determine which options will be 

selected by the individual facilities 

analyzed, it would be impractical to 

represent all of these types of brine 

disposal in the cost analysis. Therefore, 

the costs most likely to occur at affected 

facilities, handling halogenated 

compounds, where considered instead. 

The Agency has investigated brine 

disposal costs and has found that the 

deep well injection cost represents the 

cost associated with the most expensive 

disposal option available. In addition, 

available data indicate that this cost is 

appropriate for disposal of hazardous 

wastes in deep wells, not nonhazardous 

brine solutions. Furthermore, the cost 

associated with this option is not 

applicable to the majority of facilities 

generating brine. 

For the reactor processes NSPS, the 

cost for brine disposal was considered 

to be negligible and not included in the 

TRE equation because the disposal 

options most likely to be used by 

affected facilities are of a relatively low 

cost. These include ocean dumping; 

direct discharge to fresh water, brackish 

water, and sewer systems were 

permitted, and injection into existing oil 

or gas wells that are located on-site. The 

Agency sees no reason why any facility 

would have to choose the most 

expensive option of deep well injection; 

therefore, these costs were not included 

in the TRE equation. 

For each of the 173 chemicals under 

consideration, the adverse 

environmental impacts of VOC control 

using combustion devices would not be 

significant Therefore, these impacts do 

not provide a basis for exempting any of 

the chemicals from the proposed 

standards or affecting the selection of 

BDT. 

Consideration of Economic Impacts 

An economic analysis was performed 

to determine if the price of any of the 

173 chemicals or chemicals produced 

from the listed chemicals would be 

adversely affected by control at the 98 

weight-percent reduction level. 

Assumptions that tend to maximize 

projected price increases were used in 

the analysis. 

Some of the 173 chemicals are basic 

chemicals produced directly from the 

petroleum, while others are 

intermediates or end-use chemicals 

produced from the basic chemicals. The 

price increase caused by the use of a 

combustion device for a particular 

chemical was assumed to be reflected 

also in the price of all chemicals 

produced from that chemical. The 

projected price increase was calculated 

assuming that all control costs would be 

reflected as price increase, and that 

none would be absorbed. The price 

increase was calculated by dividing the 

estimated annualized control costs by 

the annual production of a facility. The 

price increase was then rolled into the 

price of chemicals that are produced 

downstream of the listed chemicals. 

No chemical that is projected both to 

have new, modified, or reconstructed 

facilities built in the first 5 years of the 

standards and to be required to control 

emissions beyond current State 

requirements is projected to have a price 

increase greater than 5 percent. 

Furthermore, chemicals that are 

produced downstream of the listed 

chemicals will not have price increases 

over 5 percent Most of the projected 

price increases for listed and 

downstream chemicals are small: 81 

percent are under 2 percent while 90 

percent are under 3 percent; any actual 

price increases are expected to be less 

than these projections. Impacts on 

industry structure, industry growth, 

inflation, foreign trade, and capital 

formation are projected to be 

insignificant 

Consideration of Cost and Energy 

Impacts 

After it had been determined that the 

98 weight-percent VOC emission 

reduction could be achieved from a 

variety of combustion controls without 

significant adverse environmental or 

economic impacts, the Administrator 

next examined the cost energy, and 

costs per unit of VOC reduced (i.e., cost 

effectiveness) of these controls on the 

projected new, modified, or 

reconstructed reactor process units. 

Based on EPA's previous experience in 

developing an NSPS for SOCMI process 

vents, the Agency anticipated that the 

cost of removing VOC from the vent 

streams of some of the process units 

would be unreasonably high and 

therefore, conducted additional 

analysis. 

The analysis required to determine 

costs, energy requirements, and costs 

per unit of VOC reduced included the 

following steps. First, the total number 

of new, modified, and reconstructed 

process units with vent streams which 

would be affected by the standard 

during the first 5 years was estimated. 

These include all process units with 

vent streams projected to not use 

combustion in the absence of an NSPS. 
P.9 

26960 Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 

The process units with these 

uncontrolled streams are assumed to be 

those that would incur the cost and 

energy impacts resulting from the 

control requirements of the standards. 

The costs of controlling the emissions 

from these process units were then 

developed for each. These process units 

were then ranked according to costs of 

control per Mg of VOC reduced. From 

thi3 ranking, a set of regulatory 

alternatives consisting of increasingly 

large numbers of controlled process 

units was developed. The remainder of 

this section provides a discussion of the 

approach and results of this regulatory 

analysis; 

In order to project the number of 

process units that would be affected by 

the standards during the first 5 years of 

its applicability, estimates of SOCMI 

growth std replacement capacity were 

determi.v.il for each of the 173 

chemicrls. This step identified all ofthe 

chemicals which may have new, 

modified or reconstructed process unit3 

built between 1985 and 1990. The next 

step was to identify which of these 

chemicals would likely have units built 

where combustion devices would be 

applied in the absence of an NSPS. A 

total of 22 chemicals were identified as 

where combustion would be applied as 

a result of existing regulations or 

industry practices. Any impacts 

associated with process units making 

these chemicals would not be attributed 

to the NSPS and, therefore, these 

chemicals were eliminated from tiie 

analysis of impacts. The next step was 

to estimate the number and size of new, 

modified, and reconstructed process 

units producing chemicals which would 

likely not use a combustion device in the 

absence of an NSPS. A total of 56 such 

units were projected to come on-line 

and these were the facilities included in 

ths analysis of impacts. 

To determine the emission 

characteristics of these 56 process units, 

an extensive data base on existing 

reactor processes was developed. This 

data b3se or Emissions Data Profile 

(EDP) covers 127 reactor process units 

and is discussed in detail in the BID. The 

emission characteristics contained in 

the EDP were used to represent the 

emission characteristics of the 56 

process units. It was assumed the EDP 

was representative of units making all of 

the chemicals associated with the 56 

units. The EDP is based upon reactor 

process units rather than affected 

facilities. A process unit is defined in 

die BID as one or more combinations of 

reactor(s) and recovery system(s) 

located at a common site and producing 

the same chemical. Therefore, it should 

be noted that this regulatory analysis is 

based upon an industry unit which, in 

some cases, may include more than one 

affected facility. The EPA does not 

believe tii3t this difference will affect 

the validity of the conclusions of this 

regulatory analysis because where a 

process unit contains more than one 

affected facility it is likely that 

emissions from both facilities will be 

ducted to a common control device. This 

is the situation represented in the 

regulatory analysis. 

As previously stated, the 56 process 

units projected to come on-line between 

1965 and 1990 are estimated to have 

vent streams that would not be 

controlled in the absence of an NSPS. 

The VOC emissions from these 56 

process units are estimated to be about 

2,400 Mg/yr. Total emissions from the 77 

process units making the 22 chemicals 

anticipated to use combustion in the 

absence of an NSPS are estimated to be 

910 Mg/yr. Therefore, the baseline 

emissions for all new, modified, and 

reconstructed reactor process units 

projected to come on-line between 1985 

and 1990 are estimated to be 3,310 Mg/ 

yr (the sum of 2,400 and 910). Baseline 

represents conditions that would exist in 

the absence of a standard. The proposed 

standards would affect the 2,400 Mg/yr 

from the 56 process units with 

uncontrolled vent streams. 

In order to rank the 56 process units 

and to conduct the regulatory analysis, 

the cost for controlling each of the 

process units was determined. 

Estimating the cost of controlling VOC 

emissions from reactor process units 

consists of first designing the control 

system and then costing the system. The 

general approach used consists of 

determining the design parameters for a 

control system applied to a particular 

reactor process that emits VOC. The 

system was costed based upon these 

design parameters and by using cost 

equations developed from data supplied 

by vendors and industry. It was not 

possible with available data to identify 

those reactor process vent streams for 

which the use of catalytic incinerators. 

process heaters, and boilers would be 

applicable. Therefore, only tiiermal 

incinerators and flares were used to 

develop these cost data. Flares or 

incinerators (whichever were 

determined to be less costly) were 

applied to nonhalogenated streams. 

Incinerators are applied to vent streams 

containing halogenated VOC because 

flare tip corrosion may prohibit use of 

flares and because halogenated streams 

may create secondary emissions that 

require flue gas scrubbing (which is not 

possible from flared emission). Because 

this regulatory analysis is based upon 

the assumption that facilities will use 

flares and incinerators, when in fact, the 

less expensive boilers and process 

heaters (because they are already in 

place and they accrue heat recovery 

credits) will be used in some plants, the 

cost impacts are overstated. 

Once the cost and emissions 

reductions for each of the 56 process 

units were estimated, the cost per Mg of 

VOC reduction for each process unit 

was determined. Then, each of the 58 

units was ranked by cost effectiveness 

(i.e., from the lowest to the highest cost 

per Mg of VOC). To illustrate how 

impacts change as a result of increasing 

the number of units controlled, nine 

regulatory alternatives were developed ' 

based on discrete cost-effectiveness 

cutoffs from a continuum of all possible 

cost-effectiveness values. These 

alternatives are presented in Table 1. 

TABLE 1.—SUMMARY OF ENVIRONMENTAL, COST, AND ENERGY IMPACTS OF NINE REGULATORY ALTERNATIVES ' 

[All Costs are in Third Quarter 1982 Dollars] 

Regulatory alternatives 

(1) 

l« 

il 

HI 

iv :. 

v 

vl 

Theoretical * worst 

casecosteffectivaness cutoff 

value ($/Mg) 

(2) 

1,200 

2.500 

5.500 

20,000 

50,000 

Average 

cost per Mg 

of VOC 

removed 

($/Mg) 

(3) 

500 

1.700 

1,800 

2,100 

2.900 

Costs per Mg of 

VOC removed 

($/Mg) 

(4) 

250-760 

2,000 

5.400 

5,600-14,000 

21,000-43.000 

Number of 

units 

controlled 

(5) 

0 

4 

7 

9 

21 

33 

Emission 

reduction from 

baseline (Mg/ 

y) 

(6) 

0 

300 

2.100 

2.300 

2.300 

2.300 

Percent 

"controllable" 

emissions 

reduced* 

(7) 

0 

13 

90 

91 

97 

100 

National 

annualized 

costs (million 

$/yr) 

(8) 

0 

0.15 

3.7 

3.9 

4.7 

6.7 

National 

energy 

requirements (TJ/ 

' iD' 

(9) 

0 

3 

320 

340 

390 

430 
P.10 

V) 

Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 2SSS1 

TABLE 1.—SUMMARY OF ENVIRONMENTAL, COST, AND ENERGY IMPACTS OF NINE REGULATORY ALTERNATIVES "—Continued 

[All Costs ore in Third Quarter 1982 Dollars] 

Regulatory alternatives 

(D 

VII „ ..... 

VIII _ 

IX 

Theoreticol * worst 

casscosteffectivenass cutoff 

valuo (S/Mg) 

(2) 

200,000 

500,000 

> 500.000 

Average 

cost per Mg 

of VOC 

removed 

($/Mg) 

(3) 

3.200 

3.500 

4,000 

Costs psr Mgof 

VOC removed 

($/Mfl) 

(4) 

64.000-110.000 

280.000-4S0.0O0 

> 4.000,000 

Number ot 

units 

controlled 

(5) 

42 

4a 

S3 

Emission 

reduction from 

baseline (Mg/ 

yr) 

(6) 

2.300 

2.3O0 

2.300 

Percent 

"controllable" 

amiasono 

reduced' 

(7) 

100 

100 

100 

National 

annualized 

costs (million 

S/yr) 

(8) 

7.4 

8.2 

9.3 

National 

energy 

requirement!) (TJ/ 

yr)d 

(9) 

440 

450 

520 

" Calculated for the firth year ot the NSPS. 

* This b a theoretical cost effectiveness. As oxplained elsewhere in this document, at) tre units with calculated costs psr Mg srhich approach the indicated value 

are expected to mako process adjustments and thus not experience control costs oo high oo indicated by this theoretical worst case. 

' Controllable emissions ore tho 2,400 Mg/yr that would be controlled if all 56 units ners controlled at 98-aeight-percent VOC destruction efficiency (i.e.. ot the 

most stringent possible alternative, Alternative IX). 

0

 Expressed in Terajoutes par year. 

° Baseline, or conditions that would exist in the absence of tha standards. 

Column 1 in Table 1 identifies each of 

the nine alternatives. Regulatory 

Alternative I represents baseline or the 

conditions which would exist in die 

absence of a standard. At the other 

extreme is Alternative IX, which would 

control all 56 units. The number of units 

controlled above baseline for each 

alternative is presented in Column 5. 

The ranges of costs per Mg of VOC 

removed within each alternative are 

presented in Column 4. These ranges 

represent the additional costeffectiveness values achieved at 

successively higher alternatives. Column 

3 presents the average costs per Mg of 

VOC removed for each alternative. 

Thus, for example, Regulatory 

Alternative III could theoretically 

control 7 of tiie 56 process units with an 

average cost of Sl.700/Mg of VOC 

controlled (in 1982 dollars). 

Column 6 in Table 1 presents an 

estimate of the VOC emissions 

reduction over baseline from die 56 

units. At baseline 2,400 Mg/yr of VOC 

would be emitted by the 56 units. Under 

Alternative II. 4 units would be 

controlled resulting in a reduction of 300 

Mg/yr. However, under Alternative III, a 

total of 7 units are Uieoretically 

controlled resulting in an emission 

reduction of 2.100 Mg/yr. If all 56 units 

were controlled at 98 weight-percent 

(Alternative IX), there would be a 

reduction of 2,300 Mg/yr of VOC being 

emitted from the 56 units. This 

alternative is the most stringent 

possible. These 2.300 Mg/yr of VOC 

emissions are the maximum available 

for control. Column 7 presents the 

percentage of the "controllable" 

emissions that each regulatory 

alternative would control "Controllable" 

emissions are 98 percent of total 

emissions from the 56 units (98 percent 

of 2.400 Mg/yr). 

It is evident from Columns 6 and 7 

that most of the emissions reduction 

occurs as a result of controlling only a 

small fraction of the 56 process units. 

For example. Alternative III would 

control only 7 of the 56 process units. 

For example. Alternative III would 

control only 7 of the 56 process units but 

would account for about 80 percent of 

the controllable emissions. 

Column 8 presents the national 

annualized costs requirements for each 

alternative. These cost impacts range 

from $0.15 million (1982 dollars) for 

Alternative II to $9.3 million for 

Alternative IX. Capital costs 

accumulated over the 5-year period (not 

shown in the table) range from $270,000 

for Alternative II to $17.3 million for 

Alternative IX. These cost and costeffectiveness data reflect die costs of 

controlling these units at 98 weightpercent VOC reduction through the use 

of incinerators and flares. The actual 

costs and cost effectiveness should be 

considerably less than those indicated 

in Table 1 for two reasons. First, plant 

owners and operators may be able to 

use boilers, process heaters or catalytic 

oxidizers rather than the more 

expensive flares and incinerators to 

comply with the 98 weight-percent 

reduction requirement. Secondly, as will 

be discussed later in this preamble, 

plant owners and operators may be able 

to increase the efficiency of product 

recovery sufficiently to comply with this 

standard and thereby would not have to 

apply 98 weight-percent-efficient 

reduction controls. To the extent that 

this alternative means of compliance is 

used; costs as well as emission 

reduction will be lower than those 

indicated in Table 1. 

Column 9 presents the energy impacts 

of die various alternatives. Electricity is 

frequently required to operate the 

pumps, fans, blowers and 

instrumentation that may be necessary 

to control VOC using an incinerator or 

flare. The amount of supplemental fuel 

needed to increase the heating value of 

vent streams depends on vent stream 

temperature, net heating value of vent 

streams depends on vent stream 

temperature, net heating value, flow 

rate, combustion temperature, and type 

of heat recovery used. Due to the use of 

heat recovery techniques, combustion of 

some reactor process vent streams 

would result in a net production of 

energy event though supplemental fuel 

would be necessary for flame stability. 

Total electricity needs are relatively 

small compared to energy requirements 

in the form of supplemental fuel for 

combustion. The fifth year national 

energy use would range from about 3 

terajoules per year (TJ/yr) (453 barrels 

of oil/yr) for Alternative II to 517 TJ/yr 

(85,000 barrels of oil/yr) for Alternative 

IX. As with the cost data, these impacts 

may be overstated because some facility 

operators will choose to comply with the 

standards through the alternative 

devices and mechanisms previously 

discussed. 

F. Selection of Best Demonstrated 

Technology 

As explained previously, the control 

of reactor process units would not result 

in unreasonable nonair environmental 

impacts or cause any of die chemicals to 

experience a significant adverse 

economic impact. Therefore, the 

Administrator analyzed the cost per 

megaram of emission reduction and 

energy impacts before determining 

which regulatory alternative should be 

selected. This analysis assures that the 

cost of units being controlled is 

reasonable, not only in terms of 

economic impacts, but also in terms of 

the emission reductions that would 

result. In this analysis, the cost data in 

Table 1 were first considered. The 

energy impacts shown in Table 1 

indicate diat mere would be no 

unreasonable adverse energy impacts. 
P.11 

26963 Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 

even if all units were controlled by 

combustion devices. 

In selecting cutoffs related to 

applicability of NSPS, EPA looks at a 

variety of factors including: (1) The 

technical feasibility of additional 

control; (2) die economic feasibility 

associated with different control 

alternatives; (3) the magnitude of 

emission reductions associated with a 

control alternative (e.g , a slightly higher 

cutoff could be selected if it led to a 

substantial increase in the emission 

reduction achieved by the NSPS); (4) die 

cost effectiveness (C/E) of die control 

alternative in terms of annual cost per 

megagram ($/Mg) of emissions reduced; 

(?) the quality of the cost estimates (e.g., 

worst case versus realistic estimates); 

(6) potential reductions in other air 

pollutants not specifically regulated by 

the NSPS resulting from a control 

Biieina':-. e; and (7) the location of ihe 

sources (e.g., urban versus rural). 

Because these factors vary from 

industry to industry and, in seme cases, 

within the same industry, decisions on 

the appropriate level of control are 

made on a category-by-category basis. 

After evaluating the above factors, die 

Administrator concluded that Uie cost of 

requiring control of any reactor process 

unit below die $2,500/Mg cutoff (1982 

dollars) is reasonable and found diat die 

following considerations were key to 

electing die cutoff: (1) The cost 

effectiveness of NSPS for VOC 

emissions previously promulgated by 

EPA; (2) the probability diat these 

maximum costs will not actually be 

incurred by industry: and (3) die 

presence of potentially toxic compounds 

in SOCMI reactor process vent streams 

and tbe fact that many of the facilities 

ere located in urban areas. 

In the past, the estimated cost per 

megagram of VOC removed has 

sometimes ranged as high as $2,800/Mg 

(1382 dollars) for affected facilities 

covered by other NSPS. (See Docket 

Item No. II-B-64). The Agency's 

experience in implementing these 

standards reveals that NSPS requiring 

this level of control have proved a useful 

tool in bringing about the installation of 

much emissions control technology, 

significant reductions in emissions, and 

corresponding improvements in air 

quality, yet have not imposed costs that 

appear "grossly disproportionate" to die 

emission reduction achieved. Portland 

11. 513 F.2d at 508. Such an approach 

simply makes this NSPS consistent (as 

to dollars spent per metric ton of VOC 

removed) with the existing body of 

NSPS regulations, all of which have 

either been promulgated without legal 

challenge or have been judicially 

upheld. As indicated in column 2 of 

table 1, the cost-effectiveness cutoff of 

$2,500/Mg used in die standard 

corresponds to Regulatory Alternative 

III. This alternative is estimated to result 

in a national annualized cost of $3.7 

million (1982 dollars) by controlling 

seven process units with a VOC 

emissions reduction of 2,100 Mg/yr. The 

range of cost effectiveness would vary 

from $250/Mg to $2,000/Mg with a $1,700 

average cost per megagram of VOC 

reduced. 

Because of the conservative 

assumptions used to develop die 

regulatory analysis and because of the 

flexibility inherent in die means by 

which industry can comply with the 

standards, it is very unlikely that any 

facility would actually have to incur a 

cost of $2,500/Mg (die cost-effectiveness 

cutoff). Data on current capita! costs of 

thermal incinerators indicate that units 

are now available at substantially 

reduced costs compared to tiiose used in 

developing these proposed standards. 

Lower capital costs would result in 

lower annualized costs Uian previous 

estimates, though die change in 

annualized costs will not be as 

significant as die change in capital 

costs. This is an important factor to 

consider in selecting die appropriate 

regulatory alternativs. Another 

consideration is the fact diat natural gas 

prices used to calculate the cost 

effectiveness for each stream are 

overstated by about 40 percent. These 

conservative assumptions have resulted 

in higher cost and cost-effectiveness 

estimates than would actually occur. In 

addition, as discussed earlier, die 

regulatory analysis assumes (for costing 

purposes) diat flares and incinerators 

would be used to comply with the 

standards. In fact, it may be feasible for 

these facilities to use boilers or process 

heaters. If they are able to use these 

devices, die costs of compliance would 

be significantly reduced. Costs would 

also be reduced for reactors diat share 

control systems with other process 

vents. Finally, die proposed standard 

would encourage pollution prevention 

by not requiring 98 weight-percent 

reduction if a TRE index greater than 1.0 

is maintained. As detailed in the section 

entitled "TRE Index," die costs shown in 

table 1 do not take into account die 

ability of facilities to comply with Uie 

standards through changes in die 

equipment or operation of die process 

facility, in certain cases, thereby 

avoiding additional control device costs. 

Available data indicate diat reactor 

process facilities witii a TRE index just 

below die 1.0 cutoff (equivalent to 

$2,500/Mg) would probably opt to 

comply witii the standards by making a 

process change such as adding recovery 

equipment to reduce VOC emissions 

and raise tiieir TRE index above 1.0 

ratiier than by combusting the vent 

stream. The objective of making a 

process change is to reduce VOC 

emissions widiout disposing of the VOC 

to the point at which the cost 

effectiveness associated with 

combustion is over the cutoff. For 

example, reactor process far.ihips with 

TRE values as low as 30 percent below 

the cutoff could potentially apply 

product recovery devices to comply with 

the standards. Due to this ability, no 

reactor process facility is likely to incur 

the maximum cost-effectiveness va'ue of 

$2,500/Mg. The highest value tint a 

facility would actually incur by using a 

combustion device is estimated lo be 

approximately $1,700/Mg. 

A thiid consideration in the selection 

of tiiis regulatory alternative is that 

SOCMI reactor process vent streams 

contain a wide variety of suspected or 

confirmed toxic compounds (e.g, 

benzene, acrylonitrile. butadiene, 

ethylene dichloride. ethylene oxide, 

carbon tetrachloride, and chloroform). A 

document listing die known toxic effects 

for the chemicals covered by tiiis 

standard has been placed in Docket A83-29 (Item II-I-168). Data on the 

emissions sources of more than 80 

potentially toxic air pollutants indicate 

that die SOCMI emissions account for a 

disproportionate share of potentially 

toxic constituents compared to other 

VOC sources (see Docket Entry II-A39). In addition, as stated in die EPA's 

Air Toxics Strategy published in July 

1985, die Agency will consider the likely 

toxic pollutant control benefits in die 

course of carrying out its responsibilities 

under section 111. This strategy reduces 

emissions of potentially toxic 

compounds from new sources and from 

industries as tiieir facilities are 

reconstructed and modified. This 

approach is to work in tandem with 

EPA's efforts to control existing and 

new sources of specific toxic 

compounds under section 112 of the 

CAA. In setting an NSPS under section 

111 of the CAA, the Agency evaluates 

all relevant factors (including costs, 

control technologies, environmental end 

energy impacts, and secondary impacts 

or benefits). Control of potentially toxic 

compounds by this NSPS is a secondary 

benefit that was considered by tho 

Administrator in determining die 

reasonableness of die cost of different 

regulatory alternatives. Therefore, 

although EPA has not yet decided 

whether to list many of these 

compounds under section 112 of the 
eg / Vol 55, No. 126 / Friday, ]une 29, 1990 / Proposed Rules 

CAA, the Agency believes that it may 

properly consider tiieir potential toxicity 

along with otiier relevant factors when 

choosing the cutoff. Many SOCMI 

facilities are located in urban areas and, 

as a result, many people will be exposed 

to any hazardous air pollutants emitted 

from these facilities. 

Consideration of all of die above 

factors confirmed EPA's belief diat a 

TRE value of 1.0 (i.e., $2,5C0/Mg) 

represents an appropriate cutoff for 

determining which facilities must reduce 

VOC emissions by 98 weight-percent or 

to 20 ppmv. The cutoff is specific to die 

SOCMI reactor processes source 

category and would not necessarily be 

appropriate for otiier source categories; 

therefore, it should not be viewed as a 

benchmark for other standards. It is not 

surprising, however, tiiat die costeffectiveness cutoff for reactors of 

S2.500/Mg (1982 dollars) is equivalent to 

the $1,9C0/Mg (1978 dollars) cutoff for 

die SOCMI air oxidation processes and 

distillation operations standards 

considering that the industry, the 

pollutants emitted, and tiie emission 

controls are the same. The only 

differences among the sources are the 

processes that are the sources of VOC 

emissions. 

C Selection of Format for the Standards 

Several formats could be used to 

implement the proposed standards. 

Section 111 of the Clean Air Act requires 

that numerical standards of 

performance be prescribed unless, in the 

judgment of the Administrator, it is not 

feasible to prescribe or enforce such 

standards. In this case, section 111(h) 

allows die Administrator to prescribe 

design, equipment, work practice or 

operational standards, or combinations 

thereof. Under that Section the term 

"not feasible" is applicable if the 

emissions cannot be captured and 

vented through a vent or stack designed 

for that purpose, or if the application of 

a measurement methodology is not 

practicable because of technological or 

economic limitations. Because emissions 

from reactor vents and emissions from 

incinerators, process heaters, and 

boilers can be measured, an emission 

limitation (performance) standard for 

these combustion devices would 

generally be appropriate. 

Because of the variety in process vent 

flow rates and VOC contents for many 

chemical reaction processes and 

facilities in die reactor source category, 

mass emission rates from sources using 

98 weight-percent efficient control 

devices would vary considerably. 

Consequently, a mass emission limit 

based on an average source would 

require that more than 98 weight-percent 

control be selected as BDT at some 

facilities and less at others. Therefore, a 

mass emission standard was considered 

inappropriate, because it would not 

require die BDT at each source. Reactor 

process vent streams have as much 

variation in volume percent organics 

concentration ao in mass emission rates. 

Any standards based solely on a 

concentration limit would also require 

more tiian BDT at some facilities and 

less than BDT at others. Therefore, 

standards based solely upon 

concentration were considered 

inappropriate. However, as discussed 

below, a concentrations limit might be 

used in combination with another type 

of emission limit if die applicability of 

die concentration limit were restricted 

to facilities within a limited range of 

process vent gas VOC content. 

A weight-percent reduction standard 

would be feasible for incinerators, 

boilers, and process heaters because the 

control device inlet and outlet emission 

rates can be measured. A weightpercent reduction standard would result 

in die application of BDT at all sources. 

Furtiiermore, a given set of incinerator, 

boiler, or process heater operating 

conditions tends to result in a given 

weight-percent reduction, rather tiian in 

an absolute outlet organics 

concentration or emission rate. As 

discussed above in die section entitled 

Selection of Best Demonstrated 

Technology, all new incinerators can 

achieve at least a 98 weight-percent 

reduction in total organics (minus 

methane and ethane), provided that die 

total organic (minus mediane and 

ethane) concentraton of die process vent 

stream is greater than approximately 

2.000 ppmv (corresponding to 1,000 

ppmv VOC in die incinerator inlet 

stream because air dilution is typically 

1:1). Therefore, a weight-percent 

reduction standard, based on die mass 

rate of organics exiting the control 

device versus die mass rate of organics 

entering die device, would be 

approxriate for vent streams with total 

organics (minus mediane and etiiane) 

concentrations above approcimately 

2,000 ppmv. For vent streams with 

organics concentrations below 

approximately 2,000 ppmv, it has been 

determined diat an incinerator outlet 

concentration of 20 ppmv is achievable 

by all new incinerators. Therefore. EPA 

concluded that the format of die 

proposed standards for reactor process 

vents using an incinerator, boiler, or 

process heater should include a 

combination of a weight-percent 

reduction standard and a volume 

concentration standard. The proposed 

emission limits would be a 98 weightpercent reduction in total organic 

compounds (minus methane and ethane) 

or reduction to 20 ppmv total organic 

compounds (minus methane and 

ethane), whichever would be less 

stringent. The concentration limit of 20 

ppmv would be based on a 3 percent 

vent stream oxygen concentration in the 

outlet stream. 

Boilers and process heaters can 

achieve a 98 weight-percent reduction, 

provided that the waste stream is 

introduced into the flame zone where 

temperatures are highest. Unlike 

incinerators, in which furnace 

temperatures are fairly constant, furnace 

temperatures in heat-generating units 

are highest. Ulike incinerators, in which 

furnace temperatures are fairly constant, 

furnace temperatures in heat-generating 

units are hightest in the flame zone, and 

a temperature gradient is experienced 

between die flame zone and the walls. 

The combustion kinetics are much more 

rapid in tiie flame zone, due to the 

higher temperatures (2.8O0°F to 3,000'F). 

This results in very small residence time 

requirements (much less than furance 

residence times) to achieve 98 weightpercent reduction or greater than is 

required in an incinerator. When burned 

as a fuel in the flame zone, the organic 

compounds to be destroyed are exposed 

to these higher temperatures. As a result 

of die more rapid combustion kinetics at 

these temperatures, high destruction 

efficiencies comparable to those 

achieved by incinerators are attainable. 

In tests of die combustion of organic 

compounds burned as fuels in boilers 

and process heaters, greater than 98 

weight-percent destruction efficiencies 

were demonstrated. Therefore, a reactor 

process vent stream, when combusted in 

a boiler or heater, must be introduced 

into the flame zone to ensure that it 

reaches sufficient combustion 

temperatures for destruction of the 

VOC. If the waste stream is not 

introduced into the flame zone, 

measuring 98 weight-percent efficiency 

across the control device has no value 

(i.e., does not assure the stream is being 

reduced by 98 weight-percent) since 

reactor process vent streams comprise 

generally a small portion of the total 

combustible stream to the heat 

generating unit. It is infeasible to 

"measure" whether the waste stream is 

introduced into the flame zone. 

Therefore, where a boiler or process 

heater is used as the control device, it is 

appropriate under section 111(h) of the 

CAA to have a combination format of 

performance standard and operational 

requirement. The proposed emission 

limit therefore would require any owner 

or operator using a boiler or process 
26964 Federal Register / Vol. 55, No. 128 / Friday, June 29, 1990 / Proposed Rules 

heater to introduce the reactor process 

vent stream into die flame zone of the 

combustion device. 

Unlike boilers, heaters and 

incinerators in which combustion takes 

place in an enclosed chamber, flaring is 

an open combustion process. It is very 

difficult, therefore, to measure die 

emissions from a flare to determine its 

efficiency. It may be technologically 

possible to measure tiiese emissions, but 

the costs involved due to the necessity 

of hooding the flare and otiier equipment 

needs would be economically 

impracticable. The Administrator, 

therefore, has determined that it is not 

feasible to measure die emissions from a 

flare. Consequently, an equipment 

standard with stated specifications is 

being proposed as die format for die use 

of flares. 

As described in die BiD, test data 

show that flares meeting certain 

conditions achieve a 98 weight-percent 

emission reduction. The proposed 

standards require the use of a flare diat 

meets tiie requirements of 40 CFR 60.18 

to comply witii the standards. This 

mear.3 diat only flares that are steam 

assisted, air assisted, or nonassisted 

may be used. Furthermore, die net 

heating value of the flared gas must not 

be less than 11.2MJ/scm (300 Btu/scf) 

for steam-assisted and air-assisted 

flares or lesss tiian 7.45 Mf/scm (200 

Btu/scf) for a nonassisted flare. In 

addition, die exit velocity of die flare 

gas at the flare tip must not exceed 18.3 

m/sec (60 ft/ssc) fur steam-assisted and 

nonassisted flares, except for die 

following conditions. If the net heating 

value of the gas being combusted is 

greater than 37.3 MJ/scm (1,000 Etu/scf), 

the exist velocity of the flare gas at die 

flare tip must rot exceed 122 m/sec (400 

ft/sec) for steam-assisted and 

nonassisted flares. When the net heating 

value is less dian 37.3 M;/scm but 

greater than 11.2 MJ/scm. the maximum 

exit velocity for nonassisted and steamassisted flares is a function of die 

heating value. Air-assisted flares must 

also operate below a maximum exit 

velocity, which is dependent upon die 

r.dt heating value cf the flared stream. 

There aro the only conditions for which 

EPA has data supporting die finding tiiat 

flares achieve 90 weight-percent 

emission redjeuon. 

Another consideration in developing 

the equipment standard for streams 

using flares is the potential for process 

variations such as flow surges that can 

cause a flare to smoke for short periods 

of time until die flare can be adjusted. 

Five minutes is a reasonable period of 

time for alleviating die smoking 

conditions by making the needed 

adjustment to the steam or air to the 

flare. The provisions in 40 CFR 60.18 

limit visible emissions to no more than 5 

minutes within any 2-hour period. 

Some reactors process facilities 

recycle all vapors to die manufacturing 

process and, therefore, do not emit 

VOC. For others, die product recovery 

devices remove virtually all of die vent 

stream. Analysis by EPA indicates that, 

even witii large vent stream VOC 

emission rates and heat contents, no 

vent stream witii flow rate below 0.011 

scm/min (0.30 scfm) would be required 

to implement combustion controls. 

These facilities would have an 

unreasonably high control cost per 

megagram of VOC destroyed (greater 

than $2,500/Mg). For this reason, the 

proposed standards exclude facilities 

with flow rates less tiian 0.011 scm/min 

from die provisions of die standards 

except for an initial measurement and 

reporting requirement. 

H. TRE Index 

After selecting the cost-effectiveness 

cutoff above which additional control of 

VOC is not required, it was necessary to 

develop a method for use in the 

regulation tiiat would distinguish those 

reactor process units below the cutoff 

(which would be required to meet the 98 

weight-percent reduction requirements) 

from tiiose process units for which no 

additional VOC reduction would be 

required. The EPA, therefore, has 

included equations in die regulation to 

calculate an index to determine whetiier 

further control is required. This index is 

termed TRE. j\n important feature of 

this index is diat it is independent of 

cost changes over time so that it is not 

necessary to periodically revise the 

calculation to reflect current year 

dollars. The equations include die 

parameters used in calculating costs 

considered in selecting the cutoff. These 

parameters are the vent stream 

characteristics of flow rate, net heating 

value, mass flow of total organic 

compounds, and corrosion properties 

(presence of halogenated compounds). 

There parameters can be measured 

easily and objectively. The TRE value 

calculation allows the owner or operator 

of an effected facility to determine if 

that facility would be required to reduce 

VOC emissions by 98 weight-percent or 

to 20 ppmv. The standardized 

calculation allows objective 

enforcement since all TRE values would 

be calculated based on the same 

parameters and calculated by iY.e same 

method. 

The TRE index of a process vent 

stream is calculated according to one or 

both equations given in 9 60.704(e)(7). 

The TRE index cutoff as calculated by 

die equation is 1.0. Affected reactor 

process facilities with a TRE index of 

less tiian or equal to 1.0 would be 

required to reduce VOC emissions by 98 

weight-percent or to 20 ppmv, whichever 

is less, while affected facilities with a 

TRE index above 1.0 would not be 

required to comply with emission 

reduction requirements. The set of 

coefficients used in the equations that 

apply to a process vent stream can be 

obtained from Tables 1 and 2 of the 

regulation. These coefficients were 

derived directly from the ccst and 

emission reduction equations associ.tt-.i 

with control of VOC emissions from 

reactor process facilities by flares and 

incinerators. 

The standards require that a plan I 

owner or operator calculate the TRE cf 

the process vent stream based on the 

specific characteristics of the vent 

stream. If the vent stream contains 

halogenated VOC, the equation for 

determining the TRE value for 

incineration must be used, along with 

the appropriate coefficients (in Table ") 

based upon vent stream heat content 

and flow rate. For vent streams 

containing nonhalogenated VOC. the 

plant owner or operator must calculate 

TRE values, using both the incineration 

equation and the equation for flares 

(selecting the appropriate set of 

coefficients in Table 1 or 2 based upon 

heat content and flow rate). After 

calculating both die incineration and 

flaring TRE values, die plant owner or 

operator must select die lowest TRE 

value for purposes of determining 

compliance with the standards. In most 

instances incinerators are more 

expensive than flares for controlling 

nonhalogenated vent streams; but in 

some instances the reverse is true. For 

this reason the regulation requires thai 

die least expensive technique be u»ed 

for TRE index calculation purposes. If 

tiiis requirement did not exist, it is 

possible tiiat a plant owner or operator 

could avoid die emission reduction 

requirements by not selecting the least 

cosily control device in determining 

TRE. 

The vent stream of an affected facility 

is considered "halogenated" under the 

proposed standards if it is determined to 

contain a concentration of halogenated 

compounds of 20 ppmv (by compound) 

or greater. This low 20 ppmv 

halogenation cutoff was chosen for the 

analysis to avoid control cost and TRE 

underestimates. Even small amounts of 

halogenated compounds may be 

corrosive and can necessitate 

incinerator temperatures greater than 

870 °C to achieve a 98 weight-percent 

control. Therefore, it was judged 
^7"~ 

Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 2SS35 

essential to set a low cutoff, so that the 

control cost and TRE would not be 

underestimated for any facility. This 

does not imply that flares, boilers, and 

process heaters are prohibited from use 

on streams containing more than 20 

ppmv halogenated compounds. 

The BDT selected allows flexibility in 

implementing the standards. For sources 

below the TRE index cutoff where tiie 

cost of combustion control is considered 

reasonable, BDT is the use of a control 

device capable of achieving a reduction 

of 98 weight-percent, or to 20 ppmv total 

organics (minus methane and etiiane) 

whichever is less stringent. Control is 

achievable through the use of 

combustion devices such as 

incinerators, boilers, process heaters, 

and flares. Incinerators may be the only 

applicable combustion device for use on 

streams containing halogenated VOC. 

Above the TRE index cutoff, BDT is no 

additional control. 

The use of a TRE index cutoff will 

also permit die use of recovery 

techniques or process modification in an 

effort to raise die TRE index to a point 

above the 1.0 cutoff. The parameters 

used to calculate the TRE index are 

measured at the outlet of the recovery 

system. Additional recovery can be used 

to change the values of die parameters 

(e.g., decrease die emission rate) and 

subsequently increase the TRE index 

value. The total cost to a facility for 

improved recovery to exceed die TRE 

cutoff may, in some cases, be much 

lower than die total cost of a flare, 

boiler, or incinerator. It may, therefore, 

be economically advantageous for such 

a facility to choose to improve its 

recovery system or make some otiier 

change witiiin the process. The decision 

by the owner of a facility concerning die 

design and resulting VOC removal 

efficiency of a change within the process 

is primarily made prior to die 

construction, modification, or 

reconstruction of that facility. As a 

practical matter, EPA has no ability to 

assess the extent to which VOC removal 

efficiency is influenced by economic 

versus regulatory considerations. As 

such, the source's motivation for 

establishing a particular process design 

is not considered when tiie TRE index 

value is measured. Consider an example 

where die owner or operator of a facility 

chooses to improve die facility's 

recovery system. For this type of 

process change. EPA presumes that the 

recovery systems are integral to die 

process and that therefore, BDT is best 

determined according to die 

characteristics of the stream existing die 

last recovery device. 

/. Selection of Actual Standards 

In summary, under die proposed 

standards, sources for which the costs of 

combustion control are reasonable 

would be subject to the following 

requirements: (1) A 98 weight-percent 

reduction of uie total organic 

compounds (minus methane and etiiane) 

in die reactor vent stream or a reduction 

to 20 ppmv total organic compound 

(minus mediane and etiiane), whichever 

is less stringent; and if a boiler or 

process heater is used to comply with 

the standards, die reactor vent stream 

must be introduced into the flame zone 

of the boiler or process heater, or (2) 

when a flare is used to comply with the 

standards, a smokeless flare is required 

and must be operated in accordance 

with the requirements in 40 CFR 60.18. 

As previously discussed, facilities with 

low flow rate (less than or equal to 0.011 

scm/min) and facilities with low 

capacities (less than or equal to one Cg/ 

year) would be exempt from these 

standards except for certain 

recordkeeping and reporting 

requirements. 

For sources where die costs of control 

are not reasonable, the proposed 

standards would require tiiat the TRE 

index be maintained at a value of 1.0 or 

above. This TRE concept is explained in 

Section H. 

/. Compounds Used in Determining 

Compliance 

The proposed standards are intended 

to reduce emissions of VOC through the 

application of BDT (considering costs 

and other impacts); and the emission 

limits in die standards are designed to 

reflect die performance of BDT. Where a 

control device for a reactor process is 

BDT. that control device (i.e., 

combustion) does not selectively control 

VOC (that is, die proportion of the 

organics that is regarded as 

photochemically reactive), but rather 

these technologies control all organic 

compounds. Moreover, the numerical 

values of the emission limits (98 weightpercent reduction and 20 ppmv) in die 

case of reactor processes, were based 

on total organic compounds data that 

excluded mediane and ethane. 

To reflect accurately die performance 

of these control devices and to make die 

emission limits consistent witii the data 

and test methods from which the limits 

were derived, EPA has expressed die 

standards in terms of organic 

compounds, minus methane and etiiane. 

For the same reason, die test procedure 

in the proposed standards prescribes 

measurement of total organic 

compounds, excluding mediane and 

ethane. In short, EPA is relying on 

control of total organic compounds, 

minus mediane and ethane, as the best 

surrogate for controlling VOC which 

react to form ozone in the atmosphere. 

K. Modification/Reconstruction 

Considerations 

The proposed standards would apply 

to all affected facilities which 

commenced construction, 

reconstruction, or modification after the 

date of proposal of the NSPS. 

Modification is defined in 40 CFR 60.14 

as any physical or operational change to 

an existing facility which results in an 

increase in the emission rate to the 

atmosphere of any air pollutant to which 

a standard applies. (Section 60.14(e) lists 

the six exemptions which would not be 

considered modifications even if 

emissions increased.) Reconstruction, as 

defined in 40 CFR 60.15. occurs when 

components of an existing facility are 

replaced to such an extent that: (1) The 

fixed capital cost of the new 

components exceed 50 percent of the 

fixed capital cost that would be required 

to construct a comparable entirely new 

facility, and (2) it is technologically and 

economically feasible to meet the 

applicable standards. 

Potential modifications involving 

SOCMI reactor processes include 

process equipment changes, changes in 

operating parameters, or both. Two 

types of process changes that may result 

in modification are: (1) Feedstock (i.e., 

basic chemical) or reactant substitution 

in reactors which were not designed to 

accommodate the new feedstock or 

reactant. and (2) process equipment 

changes. 

Many of die chemicals produced in 

reactors can be manufactured from two 

or more feedstocks. For example, 

cyclohexanone can be produced using 

either phenol (a reactor process 

reactant) or cyclohexanol (an air 

oxidation reactant). If a feedstock 

change were made and if: (1) Emissions 

increased, and (2) as required under 

§ 60.14(e) the reactor was not designed 

to accommodate the feedstock change, 

the feedstock change would result in a 

modification. In the example cited 

above, all die reactors could have to be 

rebuilt, possibly requiring a capital 

expenditure in excess of 50 percent of 

the capital cost of the affected facility. 

In this case, a reconstruction could 

result, regardless of the emissions. 

The second type of process change is 

a process equipment change. As 

discussed earlier, this type of change 

rarely occurs within tile industry. 

Examples include die replacement of a 

fixed-bed reactor witii a fluidized-bed 

reactor, die expansion in the size of a 
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26966 Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 

reactor, or die replacement of an 

absorber or substitution of a condenser 

for an absorber in the gas treatment 

system. If any of tiiese process 

equipment changes result in an increase 

in emissions, a modification could 

result; if any of the changes requires tiie 

expenditures of more tiian half of the 

replacement cost of the affected facility, 

then a reconstruction could occur. 

L. Selection of Monitoring Requirements 

and Test Methods 

Following is a discussion of die 

monitoring requirements and test 

methods selected for demonstrating 

compliance with both die emission 

reduction and the TRE provisions of die 

proposed standards. 

Percent Reduction/Concentration Limit 

The combined gas chromatograph/ 

flame ionization detection method (GC/ 

FID) (Reference Method 18) is the best 

available procedure for determining 

emissions from reactor process facilities. 

It has the advantage of being able to 

measure individual organic compounds. 

Details concerning the use of this 

methodology, including sampling, 

analysis, preparation of standards, 

calibration procedures, and reporting of 

results are discussed in Reference 

Metiiod 18, "Measurement of Gaseous 

Organic Compound Emissions by Gas 

Chromatography," which was 

promulgated with the NSPS for SOCMI 

equipment leaks (48 FR 48328). 

The owner or operator of a facility 

using an incinerator to comply with the 

proposed 93 weight-percent/20 ppmv 

emission limit would be required to 

determine compliance according to 

Reference Metiiod 18 during any 

performance test. Reference Method 1 or 

IA would be required, as appropriate, to 

be used for selection of the sampling 

site. The control device inlet sampling 

site for determination of reduction 

efficiency would be required to be prior 

to the inlet of any control device and 

after all product recovery devices. 

Reference Methods 2, 2A, 2C, or 2D 

would be required, as appropriate, to be 

used for determination of die volumetric 

flow rate. Reference Method 3 would be 

required to be used for an air dilution 

correction, based on 3 percent oxygen in 

the emission sample. 

If any process vent stream(s) frcm 

outside the affected facility were 

normally routed through die product 

recovery system or directly to the 

control device of the affected facility, 

ths proposed standards would permit 

such a stream to be routed normally 

during any performance test to 

determine compliance witii the proposed 

reduction requirement. The Agency 

considered requiring such streams to be 

rerouted or turned off, in order to assure 

that 98 weight-percent reduction or 

reduction to 20 ppmv would be achieved 

for control of die reactor process stream 

itself. However, the Agency determined 

diat if a performance test conducted on 

such a facility while routing its vent 

streams from a nonaffected facility 

showed compliance with die proposed 

emission limit, that limit would also be 

achieved by the combustion device 

when only die reactor process vent 

stream is routed through it provided 

that the combustion device operating 

parameters, such as temperature and 

residence time, remained unchanged. 

Therefore, the Agency concluded that 

requiring the nonaffected facility 

process stream to be rerouted or turned 

off during a performance test would be 

unnecessary. 

The Agency believes that boilers and. 

process heaters witii a design heat input 

capacity of 44 MW (150 million Btu/hr) 

or greater would achieve a reduction 

efficiency of 98 weight-percent or 

reduction to 20 ppmv, so long as the 

reactor process stream is introduced 

into the flame zone. Therefore, tiie 

Agency believes that an initial 

measurement of control efficiency 

would not be necessary for boilers of 

this size. As explained in the discussion 

of combustion kinetics given in the BID, 

a firebox temperature of 1,100 °C and 1 

second residence time represent die 

conditions tiiat might, in the worst case, 

be necessary to achieve 98 weightpercent reduction, even if die organics 

were halogenated. Boilers (and process 

heaters) with a design heat input 

capacity of 44 MW or greater are 

operated at temperatures and residence 

times greater than 1,100 °C and 1 

second, respectively. In some cases, the 

residence time is less than 1 second. 

However, in tiiese cases, the firebox 

temperature is much greater tiian 1,100 

°C, and 98 weight-percent reduction 

would still be achieved.) Otiier than an 

adequately high temperature and 

residence time, the two primary 

conditions necessary for high 

combustion device control efficiency are 

stable flow rate and adequate mixing cf 

gases. It is the economic advantage of 

the owners of facilities using boilers or 

process heaters to design and operate 

them with stable flow rates to avoid 

upsets. For die same reason, such 

devices would be designed and operated 

with adequate mixing of gases to 

maximize the extent of die combustion 

efficiency, tiiereby maximizing the 

steam or heat generation rate. 

For these reasons, the Administrator 

has decided that using a boiler or heater 

with a design heat input capacity of 44 

MW or greater to control VOC 

emissions from reactor process 

operations is an acceptable means of 

demonstrating compliance with the 

proposed standards if die vent stream is 

introduced into die flame zone. 

Therefore, in accordance with S 60.8(b). 

the Administrator has waived die 

requirement for a performance test on 

such devices. An initial report is 

required widiin 180 days of start-up. 

describing the location at which the ver.i 

stream is introduced into the boiler or 

process heater. The reference methods 

applicable to incinerators described 

below apply to die smaller (i.e., less 

than 44 MW) boiler and process heaters. 

As explained under Selection of 

Format for the Standards, an 

operational standard was selected for 

cases where a flare is used to meet the 

standards. Therefore, a performance test 

measuring percent reduction is not 

required for streams equipped with 

flares. However, the standard requires 

diat the flare operate in accordance with 

the requirements in 40 CFR 60.18. Flow 

rate and heat content of the flared 

stream are to be determined in 

accordance with the procedures 

prescribed in $ 60.703. 

Incinerators used to comply with the 

proposed emission limit need to be 

maintained and operated properly if 

eitiier a 98 weight-percent reduction or 

reduction to 20 ppmv is to be achieved 

on a continuing basis. Monitoring can 

generally be used to ensure such proper 

operation and maintenance are 

occurring. Two metiiods of monitoring to 

ensure die proper operation and 

maintenance of die control equipment 

used to comply with die proposed 

emission limit were considered. These 

methods were continuous emission 

monitoring and continuous combustion 

control device parameter measurement. 

Examples of such parameters are 

combustion temperature and vent 

stream flow. 

Continuous combustion control de-. ;ce 

inlet and outlet emission monitoring 

would be the preferred method of 

monitoring, because it would provide a 

continuous, direct measurement cf 

actual emissions. However, no 

continuous monitor measuring total 

organics (minus methane and ethane) 

has been demonstrated for incinerators 

because each of die many different 

compounds in reactor process vent 

streams would have to be identified 

separately and the concentrations of 

each determined. Therefore, the 

Administrator has determined that 

continuous monitoring of compliance 

with the proposed standards is not 

feasible. 
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Federal Register / Vol. 55, No. 126 / Friday. June 29, 1990 / Proposed Rules 26967 

Provided that combustion parameters 

that accurately reflect the level of 

combustion device efficiency can be 

identified and monitored continuously, 

monitoring of such parameters alone 

would have several advantages, such as 

low cost and high reliability. However, a 

disadvantage of combustion parameters 

monitoring alone is that the correlation 

of the parameters with the numerical 

emission limit is not exact. However, 

exact correlation is not necessary if the 

parameter monitored would 

demonstrate proper operation and 

maintenance of the control device. 

The combustion device operating 

parameters that affect incinerator 

performance were analyzed. These 

variables are temperature, mixing, type 

of compound, residence time, inlet 

concentration, and flow regime. Of tiiese 

variables, die inlet concentration was 

judged to have only a small impact on 

incinerator performance (provided 

reactor vent concentrations are at least 

? 300 ppmv). Residence time is 

tssentially set after incinerator 

construction unless the vent stream flow 

rate is changed. At temperatures above 

760 "C, the compound type has litde 

effect on combustion efficiency. 

Temperature and flow rate were then 

analyzed in more detail to define their 

impact on performance and the ability 

to monitor diem. 

Temperature was analyzed first. Test 

results and theoretical calculations 

show that lower temperature can cause 

significant decreases in control device 

efficiency. Test results also indicate tiiat 

temperature increases can also 

adversely affect control device 

efficiency, apparentiy by decreasing die 

thoroughness of mixing of process vent 

gases, burner gases, and combustion air. 

In terms of cost temperature monitors 

are relatively inexpensive, costing less 

than $5,000 installed with strip charts, 

and are easily and cheaply operated 

Given the large effect of temperature on 

efficiency and the low cost of 

temperature monitors, this variable is 

clearly an effective parameters to 

monitor. The proposed standards would, 

dierefore, require the owner or operator 

of an affected facility using a thermal 

incinerator to comply witii the proposed 

98 weight-percent/20 ppmv emission 

limit to install, calibrate, maintain, and 

operate according to manufacturer's 

specifications a temperature 

measurement device. This device would 

be required to be equipped with a 

continuous recorder and have an 

accuracy of 1 percent of the temperature 

being measured, expressed in degrees 

Celsius, or ±0.5 *C, whichever is 

greater. The device would be required to 

be installed in the firebox. If a catalytic 

incinerator were used, the temperature 

measuring device would be required to 

be installed in the gas stream 

immediately before and after the 

catalyst bed. 

Flow rate of the reactor process vent 

stream to the combustion device was 

die next parameters to be analyzed as a 

potential monitoring parameter. Where 

a combustion device is used to 

incinerate VOC streams alone, total 

flow rate into the unit can provide useful 

information regarding destruction 

efficiency since it relates to residence 

time in the combustion device. Reactor 

process vent stream flow rates can be 

small in comparison to otiier streams 

that may also be ducted to the same 

combustion device. Since total flow rate 

must be monitered in order to provide 

reliable information, and reactor vents 

may be combined witii otiier nonreactor 

vents, then the monitoring requirements 

would be applied to vents that were not 

intended to be covered by the 

standards. Flow indicators, as opposed 

to flow rate monitors, are relatively 

inexpensive and easy to operate. 

Therefore, because it gives an indication 

diat the organic-laden stream is being 

routed for destruction and it is 

monitored inexpensively, indication of 

flow is also an effective parameter to 

monitor for combustion devices. 

The proposed standards would, 

therefore, require the operator of an 

affected facility using an incinerator to 

comply with the proposed emission limit 

to install, calibrate, maintain, and 

operate a flow indicator, according to 

the manufacturer's specifications. The 

flow indicator would be required to be 

installed at die combustion device inlet. 

These two combustion parameters 

(temperature and flow) would be 

required to be monitored during the 

original (or most recent) performance 

test. Temperature would then be 

monitored to determine if it deviated 

from die values measured during die 

performance test. Flow indicators would 

be required to determine whether die 

vent stream was being continuously 

routed for destruction. 

If a reactor process vent stream is 

introduced into die flame zone of a 

boiler (or process heater) of any size, it 

is necessary, for the purpose of ensuring 

proper operation and maintenance, to 

know that the boiler (or process heater) 

is operating and to know that the vent 

stream is being introduced into the 

boiler (or process heater). The 

maintenance of records (such as steam 

production records) would be required 

that would indicate tiie periods of 

operation of the boiler (or process 

heater). The Administrator must be 

notified if the location at which the vent 

stream is introduced into a boiler or 

process heater is changed after the 

initial performance test. The nature of 

the records to be kept to comply wim 

this requirement are left to the 

discretion of the owner or operator of 

tiie facility, but they must be readily 

available for inspection. To ensure diat 

the vent stream is being introduced into 

the boiler (or process heater), the 

proposed standards require owners or 

operators to install and operate a flow 

indicator tiiat provides a record of vent 

stream flow to the boiler (or process 

heater). 

For heat generating units (boilers and 

process heaters) of less than 44 MW (150 

million Btu/hr) heat input design, 

performance testing is required to 

ensure efficient VOC destruction. For 

these units, just as for incinerators, 

temperature would be required to be 

measured during die original (or most 

recent) performance test and to be 

monitored to determine if it deviated 

from die values measured during the 

performance test Monitoring of 

temperature would not be required for 

heat generating units with a design heat 

capacity of 44 MW or greater. 

A flare will be in compliance with the 

proposed standards provided it is 

operating in accordance with 40 CFR 

60.18 (i.e., it is operating smokelessly (no 

more than 5 minutes of visible emissions 

from any 2-hour period), a flame is 

present, die minimum heat content 

requirements for the flared gas are met, 

and a maximum exit gas velocity is not 

exceeded). Because flares are not 

enclosed combustion devices, it is not 

feasible to measure combustion 

parameters. Moreover, temperatures and 

residence times are more variable 

throughout the combustion zone for 

flares than for enclosed devices and, 

therefore, such measurements would not 

necessarily provide a good indicator of 

flare performance even if measurable. 

The typical metiiod of monitoring 

continuous operation of a flare is visual 

inspection. However, if a flare is 

operating smokelessly, it can be difficult 

to visually determine if a flame is 

present. The presence of a flame can 

also be determined through the use of a 

heat sensing device on a flare's pilot 

flame, such as a thermocouple or ultraviolet (U-V) beam sensor. If a flame is 

absent, the temperature probe can be 

used to alert the plant operator. The cost 

of available thermocouple sensors 

ranges from $800 to $3,000 per pilot. (The 

more expensive sensors in this price 

range have elaborate automatic relight 

and alarm systems.) The cost of a U-V 
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Federal Regigteg / Vol. 55, No. 126 / Friday, June 29, 1980 / Proposed Rules 

sensor is approximately $2,000. While UV sensors are designed primarily to 

monitor flames within enclosed 

combustion devices, they can be applied 

to open flames so long as any outside 

interferences are corrected for. The use 

of either tiiermocouples or U-V sensors 

is suitable for indication of die presence 

of a flame. The proposed standards 

would require continuous monitoring to 

indicate die presence of a flame to 

ensure proper operation and 

maintenance of a flare, but the 

standards do not specify a particular 

monitoring technique. 

Among the criteria governing the use 

of flares under die proposed standards 

is maximum exit gas velocity 

requirement. Compliance with tiiis 

requirement is determined by 

performance testing. Methods 2, 2A, 2C, 

or 2D (see § 60.704) are used in 

performance tests to determine the 

actual exit velocity of flares. These tests 

must be performed under representative 

flare operating conditions. Exceedances 

of velocity limitations during periods in 

which one or more processes (tiiat vent 

to die flare) start-up, shutdown, and 

malfunction are not considered a 

violation (see i 60.8(c)). These tests are 

used to ensure diat die flare is designed 

to be and is capable of being operated 

within die velocity limitation during 

representative process conditions. 

Curing nonperformance test periods, 

operators must maintain and operate 

flares used to comply with Subpart RRR 

in a manner consistent with good air 

pollution control practices for 

minimizing emissions, even during 

periods of start-up, shutdown and 

malfunction (see § 60.11(d)). 

The formula specified at § 60.704 

requires that Metiiod 2, 2A, 2C, or 2D be 

used as die test method to determine die 

volumetric flow rate. This flow rate 

should be determined in die flare header 

or headers that feed the flare because 

the volumetric flow rate determined in 

these headers reflects the flow rate in 

the flare": After this flow rate is 

determined, an operator would use 

design and engineering principles to 

determine die unobstructed crosssectional area of the flare tip. Witii 

these two factors, the actual exit 

velocity is determined. 

The TRE Index Cutoff 

Calculation of the TRE index value for 

an affected facility is dependent upon 

measurement of the process vent gas 

volumetric flow rate, net heating value, 

total organic compound emission rate, 

and corrosion properties (presence or 

absence of halogenated compounds into 

the stream, and also prior to the inlet of 

any combustion device). Subject to die 

requirements just mentioned, the 

sampling site would also be required to 

be downstream of all product recovery 

equipment except as discussed in die 

remainder of tiiis section. In the 

situation where vent streams from new 

and existing reactors are ducted to a 

common product recovery system, a 

single TRE measurement is required 

downstream of the common product 

recovery system for the control of the 

combined new and existing reactor vent 

streams. 

The final piece of recovery equipment 

will not always be associated with only 

the affected facility; it can sometimes 

include nonreactor process facilities. 

These are configurations diat could 

influence die location and number of 

sampling sites required. One possible 

exception to the previous discussion 

involves a vent stream from an affected 

facdity that is normally routed through a 

final recovery system tiiat is shared witii 

a nonreactor process gas stream. The 

Agency considered whether or not to 

require in the proposed standards that 

such nonreactor process streams be 

bypassed during any test to determine 

die TRE index. The efficiency of die 

recovery system including both die 

reactor and die nonreactor process vent 

stream would often be different from the 

efficiency of similar devices designed to 

handle each vent stream separately. 

Furthermore, it is reasonable to 

conclude diat, especially for recovery 

devices, their design would be different 

for reactor and nonreactor vent streams 

constituents. Therefore, for purposes of 

determining compliance with the TRE 

index cutoff of such cases, die Agency 

requires that the TRE index be 

determined based upon die portion of 

the recovery outiet stream contributed 

by the reactor process facility alone. 

Thus, it is necessary to locate sampling 

sites directly upstream and downstream 

of die recovery system (to determine 

tiiat overall control efficiency for the 

device or devices) and also directly 

downstream of die reactor process 

facility. In all cases, compliance witii the 

TRE index cutoff would be determined 

for die total portion of the vent stream 

contributed by a reactor facility by 

determining the effects of the overall 

efficiency of the device upon die 

characteristics of the vent stream 

determined from the upstream sampling 

site (or sites) and by measuring flow 

rate and molar composition at a point 

just downstream of each affected 

facility (i.e., downstream of die final 

recovery device). 

For any sampling site, die volumetric 

flow rate would be required to be 

determined according to Reference 

Methods 2,2A. 2C, or 2D, as 

appropriate. The molar composition of 

the offgas stream, including die total 

molar concentration of halogenated 

compounds, would be required to be 

calculated according to die proposed 

Reference Method 18, Measurement of 

Gaseous Organic Compound Emission 

by Gas Chromatography. The water 

vapor concentration of the vent stream 

would be required to be calculated 

according to Reference Method 4. 

The net heating value of the process 

vent stream (25 "C, 760 mm Hg) would 

be required to be calculated according 

to an equation specified in the 

regulation. This equation would make 

use of die molar composition of the 

process vent stream, as measured by 

Reference Methods 4 and 18. The net 

heat of combustion of each vent stream 

component would be required to be 

determined using ASTM D2382-76 if 

published values are not available or 

cannot be calculated. This metiiod of 

determining net heating value was 

chosen because it would not require a 

separate test procedure from that 

required for determination of reduction 

efficiency and offgas halogenation. 

Moreover, the Agency believes that the 

proposed method for determining net 

heating value would be more accurate 

than any available direct experimental 

measure, such as bomb calorimetry. 

The total organic mass emission rate 

of the process vent stream would also 

be required to be calculated according 

to an equation specified in die 

regulation. This equation would make 

use of the molar composition of the 

offgas stream, as measured by 

Reference Method 18, and of the 

volumetric flow rate, as measured by 

Reference Metiiod 2. 

After an initial performance test to 

determine compliance with the proposed 

TRE index cutoff value, variations in 

process parameters, process 

modifications or improper operation or 

maintenance of recovery equipment 

could lead to higher emissions and a 

true TRE index below the cutoff. Some 

metiiod is necessary to determine if the 

TRE index measured during die initial 

performance test has changed. Methods 

considered were continuous monitoring 

of selected operating parameters of the 

final piece of product recovery 

equipment in die affected facility and 

periodic performance testing of the TRE 

index of die facility. As explained 

previously, continuous vent sti'eam 

molar composition and flow rate 

monitoring are not feasible. The first 

method investigated for determining if 

die initial TRE index had changed, 

involved die monitoring of product 
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Federal Register / Vol. 55, No. 128 / Friday, June 29. 1990 / Proposed Rules 26969 

recovery device parameters. The 

operating parameters of tiie three types 

of product recovery equipment 

commonly used in reactor processes 

were analyzed for correlation witii 

product recovery device operation and 

maintenance, which in turn would give 

an indication of changes in TRE index. 

The tiiree types of product recovery 

equipment are absorbers, condensers, 

and carbon adsorbers. 

For an absorber, two operating 

parameters were identified as die 

primary determinants of product 

recovery device operations: absorbing 

liquid temperature and specific gravity 

(or some other parameter used by a 

facility to measure absorbing liquid 

saturation). In the absence of the 

proposed standard, facilities employing 

an absorber for product recovery would, 

in general, monitor continuously some 

parameter related to die degree of 

saturation of absorbing liquid with 

recovered material. Specific gravity is 

one such parameter that is frequently 

monitored. Absorbing liquid 

temperature monitors and specific 

gravity measurement devices are 

available at a reasonable cost. The 

estimated one-time combined capital 

investment for such equipment is $8,000. 

These absorption parameters would be 

required to be measured during each 

performance test. (If approved by die 

enforcing Agency, an alternate 

parameter that would indicate the 

degree of absorbing liquid saturation 

could be measured during each 

performance test.) These absorption 

parameters would then be monitored to 

determine if any value had changed 

since die performance test. This 

monitoring would indicate whetiier the 

absorber was being operated and 

maintained properly. Therefore, an 

operator of an affected facility for which 

an absorber was the final device in the 

product recovery system would be 

required to install, calibrate, maintain, 

and operate according to a 

manufacturer's specifications an 

absorbing liquid temperature monitor 

and specific gravity measurement device 

(or an alternate device that would 

measure the degree of absorbing liquid 

saturation, if approved by the enforcing 

agency), each recorded continuously. 

For a condenser, the exit (product 

side) temperature of the offgas was 

identified as the primary determinant of 

product recovery device operation. 

Condenser temperature monitors are 

available at a reasonable cost. The 

estimated one-time capital investment 

for such equipment is $3,000. The 

condenser exit (product side) 

temperature would be required to be 

measured during each performance test. 

The temperature would then be 

monitored to determine if the value had 

changed since the most recent 

performance test This monitoring would 

indicate whether the condenser was 

being operated and maintained properly. 

Therefore, an operator of an affected 

facility for which a condenser was the 

final device in die product recovery 

system would be rquired to install, 

calibrate, maintain, and operate 

according to manufacturer's 

specifications a condenser temperature 

monitor equipped with a continuous 

recorder. 

For a carbon absorber, die carbon bed 

temperature (after regeneration and 

completion of any cooling cycle), as well 

as the amount of steam used to 

regenerate the adsorption bed, were 

identified as the primary determinants 

of product recovery device operation. 

Steam flow meters diat indicate die 

quantity of steam used over a period of 

time and bed temperature monitors are 

available at a reasonable cost. The 

estimated one-time capital investment 

for such equipment is $10,000. These 

adsorption parameters would be 

required to be measured during each 

performance test. These adsorption 

parameters would then be monitored to 

determine if any value had changed 

since die most recent performance test. 

This monitoring would indicate whether 

the carbon adsorption unit was being 

operated and maintained properly. 

Therefore, an operator of an affected 

facility for which a carbon adsorber is 

the final unit of the product recovery 

system would be required to install, 

calibrate, maintain, and operate 

according to manufacturer's 

specifications an integrating steam flow 

meter and a carbon bed temperature 

measurement device, each equipped to 

be recorded continuously. 

Some carbon absorbers, adsorbers, 

and condensers may include vent 

stream organic concentration monitors 

to aid operators maximizing the 

recovery of raw materials or products. 

Such devices equipped witii a 

continuous recorder may be used as an 

alternative to monitoring the otiier 

operating parameters for absorbers, 

adsorbers, and condensers specified in 

die regulation. 

The enforcement agency would 

specify, on a case-by-case basis, 

appropriate monitoring procedures or 

requirements where the owner or 

operator of an affected facility uses 

emission control or product recovery 

techniques other tiian tiiose specified to 

comply with die proposed standards. 

The Agency has determined that an 

affected facility with a TRE index value 

greater than B.O could not lower its TRE 

index value below 1 without a process 

change. Therefore, facilities with TRE 

index values greater than 8.0 are exempt 

from the monitoring, recordkeeping and 

reporting requirements other than the 

initial performance test requirements 

unless a process change is made to the 

facility. If a process change occurs, the 

TRE index value would have to be 

recalculated. If the recalculated TRE 

index value is below or equal to 8.0 and 

greater than 1.0, the facility would have 

to comply witii the monitoring, 

recordkeeping, and reporting 

requirements of die standards. 

M. Reporting and Recordkeeping 

Requirements 

The General Provisions for the NSPS 

regulations (40 CFR part 60, subpart A) 

require submittal of several one-lime 

notifications for occurrences such as 

construction, modification, 

reconstruction, scheduled dates for 

performance tests, and performance test 

results. Owners and operators of boilers 

and process heaters with design heat 

input capacities of 44 MW (150 million 

Btu/hr) or greater would not report 

performance test results, since the 

proposed standards would waive the 

requirement of such a test. Instead, 

operators would be required to file an 

initial report describing the location at 

which the reactor vent stream is 

introduced into the boiler (or process 

heater) to be used. Owners and 

operators of flares used to comply with 

die proposed standards would be 

required to file an initial report on the 

results of performance testing to 

determine compliance witii the visible 

emission requirements and the heat 

content and maximum exit gas velocity 

criteria for flares. 

The proposed standards exempt 

reactor process facilities from the 

quarterly report required by the General 

Provisions. However, records of startup, shutdown, and malfunction would 

still be required. Also, records indicating 

whether control equipment is being 

operated and maintained properly 

would be required. The proposed 

standards would require owners or 

operators of those facilities, exempted 

because tiieir operational flow rate was 

less than 0.011 scm/min, to send an 

initial report to the Administrator 

containing a measurement of the 

operating flow rate, maintain records of 

and report semiannually if any changes 

in equipment process operation occur 

that would increase tneir flow rate 

above 0.011 scm/min. Similarly, owners 
P.19 

26970 Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 

or operators of those facilities that 

would be excluded from control 

requirements because the process unit in 

which they are located has a design 

capacity below 1 Gg/yr, would be 

required to send an initial report to the 

Administrator ofthe design production 

capacity. They would also be required 

to record and report changes that 

increase their process unit capacities 

above the one Gg/yr cutoff. 

Records indicating proper operation 

and maintenance would be based on the 

monitoring of control device or recovery 

device parameters discussed in die 

previous section. Two types of records 

would be required. The first would be 

the monitoring results themselves. This 

information can be automatically 

recorded, and therefore, essentially the 

only labor necessary for keeping these 

records would consist cf filing 

automatically recorded parameters. The 

second type of record would be a 

tabulation of periods when the 

measurements of these automatically 

recorded parameters significantly 

deviated from measurements ofthe 

same parameters during the most recent 

performance test. Although this requires 

more effort, it is a necessary step for 

both the owner or operator and 

enforcement agency to ensure that the 

control equipment is being operated and 

maintained properly. This information 

would be necessary for the owner or 

operator to know when to make 

necessary corrections to the control 

equipment. For this second type of 

record it would be necessary for the 

owner or operator to record control 

device or product recovery equipment 

operating parameters, as appropriate, 

during all performance tests and keep 

these records for purposes cf 

comparison. The owner or operator 

would not be required to record all 

deviations from Ihese measurements, 

but only certain deviations as listed in 

ihn proposed regulation. All records 

would be required to be kept up to date 

and in readily accessible files for 2 

years. The parameter boundaries 

included in the proposed regulation 

would allow for norma! fluctuations in 

operation of the equipment monitored. 

The VOC reduction efficiency of the 

control device would not be affected by 

such normal fluctuations. 

Where a recovery system is used to 

comply with the proposed TRE index 

value, the proposed standards would 

also require recording of any change in 

production capacity; feedstock; type of 

catalvst; or ofthe replacement, removal, 

or additional of product recovery 

equipment. When any such change 

occurs, the TRE index value would have 

to be recalculated to document diat die 

facility continues to have a TRE index 

value above 1.0. Such recalculation can 

be based on die best engineering 

estimates of the effects of the change or 

on emission test data. A record would 

be maintained of die recalculated TRE 

value. If the recalculated TRE index 

value for the facility is below 1.0, die 

owner, or operator of the facility would 

have to demonstrate compliance witii 

the 98 weight-percent reduction or 20 

ppmv emission limits. Performance tests 

must be conducted as soon as possible 

after the process change but no later 

tiian 180 days from the time of the 

process change. 

If the initial TRE index value for a 

facility were above 8.0 and the 

recalculated value were below or equal 

to 8.0 but greater than 1.0, the facility 

must report the recalculated TRE index 

value to the Administrator as socn as 

possible after the change and no later 

than 180 days after the change. In 

addition, a performance test must be 

completed witiiin the same time period 

to verify the recalculated value and to 

obtain the initial operating parameters. 

The performance test is subject to the 

requirements of § 60.8 of the General 

Provisions. The facility must begin 

complying with the monitoring, 

recordkeeping, and reporting 

requirements immediately after the 

performance test. 

In addition to the one-time 

notifications and performance test 

reports discussed above, semiannual 

reporting of recorded data would be 

required for instances where monitored 

parameters exceed the allowable 

limitations set forth in die standards. 

These data include the operating 

parameters cited above for combustion 

and other control devices. Other 

instances that would be reported 

semiannually ar periods of no flow to 

control devices used for compliance 

with the standards and periods where 

there is no flame present for flares used 

for compliance with die standards. The 

requirement for semiannual reporting, 

however, is waived for affected facilities 

in States where die program has been 

delegated, if EPA, in the course of 

delegation, approves reporting 

requirements or an alternative means of 

source surveillance adopted by the 

State. Such affected facilities would be 

required to comply with the 

requirements adopted by die State. 

During the first 3 years of this 

regulation, the average annual burden of 

die reporting and recordkeeping 

requirements would be 7.9 person-years, 

based on an average of 27 respondents 

per year. 

V. Administrative Requirements 

J4. Public Hearing 

A public hearing will be held, if 

requested, to discuss the proposed 

standards in accordance witii section 

307(d)(5) of the CAA. Persons wishing to 

make oral presentations should contact 

EPA at the address given in die 

ADDRESSES section of the preamble. 

Oral presentations will be limited to 15 

minutes each. Any member of the public 

may file a written statement 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 die preamble. 

A verbatim transcript of the hearing 

and written statements will be available 

•for public inspection and copying during 

normal working hours at the EPA's 

Central Docket Section in Washington, 

DC (see die ADDRESSES section of this 

preamble). 

B. Docket 

The docket is an organized and 

complete file of all die information 

submitted lo, or otherwise considered 

in, die development of tiiis proposed 

rulemaking. The principal purposes of 

the docket are; (1) To allow interested 

parties to identify and locate documents 

so diat they can effectively participate 

in die rulemaking process, and (2) to 

serve as die record in case of judicial 

review (except for interagency review 

materials as noted in Section 

307(d)(7)(A)). 

C. Clean Air Act Procedural 

Requirments 

Administrator Listing—Section 111. 

As prescribed by section 111 of the 

CAA, as amended, establishment of 

standards of performance for SOCMI 

reactor process units was preceded by 

the Administrator's determination (40 

CFR 60.18. 44 FR 49222, dated August 21, 

1979) that SOCMI contributes 

significantiy to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. 

Periodic Review—Section 111. This 

regulation will be reviewed witnin 4 

years from the date of promulgation as 

required by the CJ\A. This review will 

include an assessment of such factors as 

the need for integration with other 

programs, the existence of alternative 

methods, enforceability, impiovements 

in emission control technology, and 

reporting requirements. 

External Participation—Section 117. In 

accordance with Section 117 of the Act, 

publication of tiiis proposal was 

preceded by consultation witii 
Federal Register / Vol. 55. No. 126 / Friday, June 29, 1990 / Proposed Rules 26971 

appropriate advisory committees, 

independent experts, and Federal 

departments and agencies. In addition, 

numerous meetings were held with 

industry representatives and trade 

associations during development of die 

proposed standards. The Administrator 

will welcome comments on all aspects 

of the proposed regulation, including 

economic and technolgical issues. 

Economic Impact Assessment— 

Section 317. Section 317 of the CAA 

requires the Administrator to prepare an 

economic impact assessment for any 

NSPS promulgated under section 111(b) 

of the Act. An economic impact 

assessment was prepared for the 

proposed regulations and for other 

regulatory alternatives. All aspects of 

the assessment were considered in the 

formulation of the proposed standards 

to ensure tiiat the proposed standards 

would represent the best system of 

emission reduction considering costs. 

The economic impact assessment is 

included in the BID. 

D. Office of Management and Budget 

Reviews 

1. Paperwork Reduction Act 

There are no reporting requirments by 

other governmental agencies for the 

information required by these standards 

which would result in overlapping 

requirements. In particular, there is no 

overlap with the reporting requirements 

of the Superfund program. The 

Superfund program was established in 

1980 by the Comprehensive 

Environmental Response, 

Compensation, and Liability Act 

(CERCLA. Pub. L. 96-510) and 

authorizes the Federal government to 

respond directly to releases (or 

threatened releases) of hazardous 

substances and pollutants or 

contaminants to any media that may. 

endanger public health or welfare. 

Under tiie notification and liability 

provisions of section 103 (see 48 FR 

23552. May 25,1983), CERCLA requires 

that persons in charge of vessels or 

facilities from which hazardous 

substances have been released in 

quantities that are equal to. or greater 

than, the reportable quantities 

immediately notify the National 

Response Center of the release (800-

424-8802; in Washington, DC. 

metropolitan area 202-426-2675). 

However, air releases which qualify as 

Federally permitted releases, such as 

VOC emissions that are regulated under 

section 111 of the Clean Air Act, are not 

subject to the notification or liability 

provisions of CERCLA unless the air 

releases are in excess of the allowable 

NSPS emissions by an amount equal to 

or greater tiian the reporting quantity; in 

this case, persons in charge must report 

the excess air releases to the National 

Response Center. (Reporting under 

CERCLA does not excuse die persons in 

charge from any responsibility, 

including reporting, or liability under the 

NSPS program.) 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act of 1980,44 U.S.C. 3501 et seq and 

has been assigned an OMB control 

number. Comments on these 

requirements should be submitted for 

approval to the Office of Information 

and Regulatory Affairs of OMB; 726 

Jackson Place, NW.; Washington. DC 

20503 marked "Attention: Desk Officer 

for EPA." The final rule wdl respond to 

any OMB or public comments on the 

information collection requirements. 

Public reporting burden for this 

collection of information is estimated to 

be 15,771 hours per year, with an 

average of 584 hours per response, 

including time for reviewing 

instructions, searching existing data 

sources, gathering and maintaining the 

data needed, and completing and 

reviewing the collection of information. 

Send comments regarding the burden 

estimate or any other aspect of this 

collection of information, including 

suggestions for reducing this burden, to 

Chief, Information Policy Branch PM223, U.S. Environmental Protection 

Agency. 401 M St.. SW., Washington, DC 

20460; and to the Office of Information 

and Regulatory Affairs, Office of 

Mangement and Budget Washington. 

DC 20503. 

2. 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 proposed regulation is 

not major because; (1) The national 

annualized control costs, including 

capital charges resulting for the 

standards total less than $100 million; 

(2) the standards do not cause a major 

increase in prices or production costs for 

most of the chemicals considered: and 

(3) given the low levels of investment 

required and the small price increases 

estimated for chemicals with low TRE 

values, the effects of the regulation on 

domestic competition, employment, 

investment, productivity, innovation, 

and competition in foreign markets will 

be negligible. 

This regulation was submitted to 

OMB for review as required by 

Executive Order 12291. Any written 

comments for OMB and any written 

responses by EPA will be included in 

Docket A-83-29. This docket is 

available for public inspection at EPA's 

Central Docket Section, which is listed 

under die ABOBE83E8 section of this 

notice. 

E. Regulatory Flexibility Act 

Compliance 

The Regulatory Flexibility Act (Pub. L. 

96-354, September 19,1980) requires that 

special consideration be given to the 

impacts of all Federal regulations on 

small businesses, small governments. 

and small organizations. These 

standards will have no known effects on 

small governments and small 

organizations. Some small businesses 

may be affected. However, the economic 

analysis described above indicates that 

these standards will have no significant. 

adverse economic impact on firms 

producing affected chemicals, regardless 

of firm size. Furthermore, no burden will 

be placed upon small businesses 

disproportionate to their potential 

contribution to VOC emissions. 

The price increase screening analysis 

uses many conservative control cost 

assumptions and demonstrates that not 

even small plants should incur control 

costs in excess of 5 percent of 

production costs. There should be no 

capital availability or industrial growth 

problems associated with these 

standards. Thus, no significant, adverse 

economic impacts on small businesses 

are anticipated. 

No burden will be placed on any firm 

disproportionate to the VOC tiiat it 

would emit in the absence of these 

standards. This is ensured by 

application of the TRE index, which 

identifies facilities that would emit a 

substantial amount of reasonably 

controllable VOC in the absence of 

these standards. 

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

605(b), I hereby certify that this rule will 

not have a significant impact on a 

substantial number of small entities. 

List of Subjects in 40 CFR Part 60 

Air pollution control. Reporting and 

recordkeeping requirements. 

Incorporation by reference. 

Intergovernmental relations, SOCMI. 

Dutud: June 13, 1900. 

William K. Reilly. 

Adminiszrctor. 

PART 60—[AMENDED] 

It is proposed that 40 CFR part 6 be 

amended as follows: 

1. the authority citation for part 60 

continues to read as follows: 

u 

p 
Federal Regjsteg / Vol. 55, No. 128 / Friday, June 29, 1980 / Proposed Rules 

Authority: Sees. 101, 111. 114.116. and 301 

of die Clean Air Act (CAA) ao amended (42 

U.S.C. 7401. 7411. 7416, 7601). 

2. By adding a new subpart RRR to 

read as follows: 

Subpart RRR=-StomSardo of Poriormonco 

for Volotllo Organic Compound (VOC) 

Emlcolono from Syntttotto Organic ChomteaO 

Manufacturing Industry (SOCMI) RGGCSOSProcesses 

Sec. 

60.700 Applicability and designation of 

affected facility. 

60.701 Definitions. 

60.702 Standards. 

60.703 .Monitoring of emissions and 

operations. 

60.70; Test methods and procedures. 

60.705 Reporting and recordkeeping 

requirements. 

60.706 Reconstruction. 

60.707 Chemicals affected by subpart RRR. 

60.708 Delegation of authority. 

Subpart RRR=Standartis otf 

Performance for Volatile Organic 

Compound (VOC) Enrtiasiono frona 

Synthetic Organic Shomiesl 

Manufacturing Industry (SOCMI) 

Reactor Processes 

§ 60.700 Applicability and designation off 

affected fcctlity. 

(a) The provisions of this subpart 

epply to each affected facility 

designated in paragraph (b) of this 

section that produces any of the 

chemicals listed in § 60.707 as a product 

co-product, by-product, or intermediate, 

except as provided in paragraph (c) of 

this section. 

(b) The affected facility is any of die 

following for which construction, 

modification, or reconstruction 

commenced after June 29,1980. 

(1) Each reactor process not 

discharging its vent stream into a 

recovery system. 

(2) Each combination of a reactor 

process and the recovery system into 

which its vent stream is discharged. 

(3) Each combination of two or more 

reactor processes and die common 

recovery system into which their vent 

streams are discharged. 

(c) Exemptions from the provisions of 

paragraph (3) of this section are as 

follows: 

(1) Any reactor process that is 

designed and operated as a batch 

operation is not an affected facility. 

(2) Each affected facility that has a 

total resource effectiveness (TRE) index 

value greater than 8.0 is exempt from all 

provisions of this subpart except for 

i § 60.702; 60.704(d), (e), and (f): and 

60.703 (h) and (1). 

(3) Each affected facility in a process 

unit with a total design capacity for all 

chemicals produced within that unit of 

less than 1 gigagram per year is exempt 

from all provisions of this subpart 

except for the recordkeeping and 

reporting requirements in paragraphs (j), 

(1)(8), and (n) of 6 60.705. 

(4) Each affected facility operated 

with a vent stream Sow rate less than 

0.011 scm/min is exempt from all 

provisions of this subpart except for the 

test method and procedure and the 

recordkeeping and reporting 

requirements in g 60.704(g) and 

paragraphs (i), (1)(5), and (o) of § 60.705. 

(Note: The intent of these standards is to 

minimize the emissions of VOC through the 

application of best demonstrated technology 

(BDT). The numerical emission limits in tiiese 

standards are expressed in terms of total 

organic compounds (TOC) measured as TOC 

less methane and ethane. These emission 

limits reflect the performance of BDT.) 

g 60.701 Oeflnrdono. 

As used in this subpart all terms not 

defined here shall have the meaning 

given them in the Act and in subpart A 

of part 60, and the following terms shall 

have the specific meaning given them. 

Batch process means any 

noncontinuous reactor process which is 

not characterized by steady-state 

conditions and in which reactants are 

not added and products are not removed 

simultaneously. 

Boiler means any enclosed 

combustion device that extracts useful 

energy in the form of steam. 

By compound means by individual 

stream components, not carbon 

equivalents. 

Continuous recorder means a data 

recording device recording an 

instantaneous data value at least once 

every 15 minutes. 

Flame zone means the portion of the 

combustion chamber in a boiler 

occupied by the flame envelope. 

Flow indicator means a device which 

indicates whetiier gas flow is present in 

a vent stream. 

Halogenated vent stream means any 

vent stream determined to have a total 

concentration (by volume) of 

compounds containing halogens of 20 

ppmv (by compound) or greater. 

Incinerator means any enclosed 

combustion device that is used for 

destroying organic compounds and does 

not extract energy in the form of st.rem 

or process heat. 

Process heater means a device that 

transfers heat liberated by burning fuel 

to fluids contained in tubes, including a!! 

fluids except water that is heated to 

produce steam. 

Process unit means equipment 

assembled and connected by pipes or 

ducts to produce, as intermediates or 

final products, one or more of die 

chemicals in § 60.707. A process unit can 

operate independently if supplied with 

sufficient feed or raw materials and 

sufficient product storage facilities. 

Product means any compound or 

chemical listed in § 60.707 which is 

produced for sale as a final product as 

that chemical, or is used for die 

production of other chemicals or 

compounds. By-products, co-products, 

and intermediates are considered to be 

products. 

Reactor processes are unit operations 

in which one or more chemicals, or 

reactants other than air, are combined 

or decomposed in such a way that their 

molecular structures are altered and one 

or more new organic compounds are 

formed. 

Recovery device means an individual 

unit of equipment, such as an absorber, 

carbon adsorber, or condenser, capable 

of and used for the purpose of 

recovering chemicals for use, reuse, or 

sale. 

Recovery system means an individual 

recovery device or series of such 

devices applied to the same vent stream. 

Total organic compounds (TOC) 

means those compounds measured 

according to the procedures in 

§ 60.704(b)(4). For the purpose of 

measuring molar composition as 

required in § 60.704(d)(2)(i); and hourly 

emissions rate as required in 

g 60.704(d)(5), and g 60.704(d)(6); and 

TOC concentration as required in 

g 60.705(b)(4) and g 60.705(g)(4), those 

compounds which the Administrator has 

determined do not contribute 

appreciably to the formation of ozone 

are to be excluded. 

TRE index value means a measure of 

the supplemental total resource 

requirement per unit reduction of TOC 

associated with an individual vent 

stream from an affected reactor process 

facility based on vent stream flow rate, 

emission rate of TOC, net heating value, 

and corrosive properties (whetiier or not 

the stream contains halogenated 

compounds), as quantified by the 

equation given under g 60.704(e). 

Vent stream means any gas stream 

discharged directly from a reactor to the 

atmosphere or indirectly to die 

atmosphere after diversion through 

other process equipment. The vent 

stream excludes relief valve discharges 

and equipment leaks including, but not 

limited to, pumps, compressors, and 

\alves. 

g 60.703 Standordo. 

Each owner or operator of any 

affected facility which is subject to the 

requirements of tiiis subpart shall 

comply with paragraph (a), (b), or (c) of 
Federal Register / Vol. 55, No, 126 / Friday, {une 29, 1990 / Proposed Rules 26973 

this section for each vent stream on and 

after die date on which the initial 

performance test, required by S 60-fl and 

§ 60.704, is completed, but not later than 

00 days after achieving the maximum 

produclion rate at which the affected 

facility will be operated, or 180 days 

after die initial: start-up, whichever date 

comes first. Each owner or operator 

shall: 

(a) Reduce emissions of TOC (less 

mediane and ethane) by 98 weightpercent, or to a TOC (less methane and 

ethane) concentration of 20 ppmv, on a 

dry basis corrected to 3 percent oxygen, 

whichever is less stringent If a boiler or 

process heater is used to comply with 

this paragraph, then the vent stream 

shall be introduced into the flame zone 

of die boiler or process heater. 

(b) Combust die emissions in a flare. 

Flares used to comply witii this subpart 

shall comply witii tiie requirements of 

S 60.18. 

(c) Maintain a TRE index value 

greater than 1.0 without use of a VOC 

emission control device. 

S 60.703 Monitoring of emissions and 

operations. 

(a) The owner or operator of an 

affected facility that uses an incinerator 

to seek to comply witii the TOC 

emission limit specified under 

§ 60.702(a) shall install, calibrate, 

maintain, and operate according to 

manufacturer's specifications the 

following equipment: 

(1) A temperature monitoring device 

equipped with a continuous recorder 

and having an accuracy of ±1 percent 

of die temperature being monitored 

expressed in degrees Celsius or ±0.5°C, 

whichever is greater. 

(i) Where an incinerator other than a 

catalytic incinerator is used, a 

temperature monitoring device shall be 

installed in die firebox. 

(ii) Where a catalytic incinerator ia 

used, temperature monitoring devices 

shall be-installed in the gas stream 

immediately before and after the 

catalyst bed. 

(2) A flow indicator that provides a 

record of vent stream flow to the 

incinerator at least once every hour for 

each affected facility. The flow indicator 

shall be installed in die vent stream 

from each affected facility at a point 

closest to the inlet of each incinerator 

and before being joined with any other 

\ent stream. 

(b) The owner or operator of an 

affected facility that uses a flare to seek 

to comply with { 60.702(b) shall install, 

calibrate, maintain and operate 

according to manufacturer's 

specifications the following equipment: 

(1) A heat sensing d: ice. such es a 

ultra-violet beam sense: or 

thermocouple, at tiie pi.ot light to 

indicate continuous presence of a flame. 

(2) A flow indicator that provides a 

record of vent stream flow to the Rare at 

least once every hour for each affected 

facility. The flow indicator shall be 

installed in the vent stream from each 

affected facility at a point closest to the 

flare and before being joined with any 

other vent stream. 

(c) The owner or operator of an 

affected facility that uses a boiler or 

process heater to seek to comply with 

S 60.702(a) shall install, calibrate, 

maintain, and operate according to die 

manufacturer's specifications the 

following equipment: 

(1) A flow indicator tiiat provides a 

record of vent stream flow to die boiler 

or process heater at least once every 

hour for each affected facility. The flow 

indicator shall be installed in the vent 

stream from each affected facility at a 

point closest to the inlet of each boiler 

or process heater and before being 

joined with any other vent stream. 

(2) A temperature monitoring device 

in the firebox equipped with a 

continuous recorder and having an 

accuracy of ±1 percent of the 

temperature being measured expressed 

in degrees Celsius or ±0.5°C, whichever 

is greater, for boilers or process heaters 

of less than 44 MW (150 million Btu/hr) 

design heat input capacity. 

(3) Monitor and record die periods of 

operation of the boiler or process heater 

if the design heat input capacity of the 

boiler or process heater is 44 MW (150 

million Btu/hr) or greater. Tbe records 

must be readily available for inspection. 

(d) The owner or operator of an 

affected facility that seeks to 

demonstrate compliance with the TRE 

index value limit specified under 

S 60.702(c) shall install, calibrate, 

maintain, and operate according to 

manufacturer's specifications the 

following equipment unless alternative 

monitoring procedures or requirements 

are approved for that facility by die 

Administrator. 

(1) Where an absorber is the final 

recovery device in the recovery system: 

(i) A scrubbing liquid temperature 

monitoring device having an accuracy of 

±1 percent of the temperature being 

monitored expressed in degrees Celsius 

or ±0.5 *C, whichever is greater, and a 

specific gravity monitoring device 

having an accuracy of ±0.02 specific 

gravity unit each equipped with a 

continuous recorder, or 

(ii) An organic monitoring device used 

to indicate the concentration level oi 

organic compounds exiting die recovery 

device based on a detection principle 

such as infra-red, photoianization, or 

thermal conductivity, each equipped 

with a continuous recorder. 

(2) Where a condenser is the final 

recovery device in the recovery system: 

(i) A condenseT exit (product side) 

temperature monitoring device equipped 

witii a continuous recorder and having 

an accuracy of ±1 percent of the 

temperature being monitored expressed 

in degrees Celsius or ±0.5 °C. 

whichever is greater, or 

(ii) An organic monitoring device ustd 

to indicate the concentration level of 

organic compounds exiting the reco\ cry 

device based on a detection principle 

such as infra-red, photcionizalion, or 

thermal conductivity, each equipped 

witii a continuous recorder. 

(3) Where a carbon adsorber is th* 

final recovery device unit in the 

recovery system: 

(i) An integrating steam flow 

monitoring device having an accur-.icy of 

±10 percent, and a carbon bed 

temperature monitoring device having 

an accuracy of ±1 percent of the 

temperature being monitored exp: essed 

in degrees Celsius or ±0.5 °C. 

whichever is greater, both equipped 

with a continuous recorder, or 

(ii) An organic monitoring device used 

to indicate die concentration level of 

organic compounds exiting the recovery 

device baaed on a detection principle 

such as infra-red, photoionization, or 

thermal conductivity, each equipped 

with a continuous recorder. 

(e) An owner or operator of an 

affected facility seeking to demonsttute 

compliance with the standards specified 

under § 60.702 with control devices 

other tiian incinerator, boiler, process 

heater, or flare: or recovery devices 

other than an absorber, condenser, or 

carbon adsorber shall provide to the 

Administrator information describing 

the operation of die control device or 

recovery device and the process 

parameter(s) that would indicate proper 

operation and maintenance of the 

device. The Administrator may request 

further information and will specify 

appropriate monitoring procedures ot 

requirements. 

§60.704 Test methods and procedures. 

(a) For the purpose of demonstrating 

compliance with 9 60.702, all affected 

facilities shall be run at full operating 

conditions and flow ra!es during any 

performance test. 

(b) The following methods in 

appendix A to this part, except as 

provided under 9 60.8(b), shall be used 

as reference methods to determine 

compliance with the emission limit or 
percent reduction efficiency specified 

under § 60.702(a). 

(1) Method 1 or IA, as appropriate, for 

selection of the sampling sites. The 

control device inlet sampling site for 

determination of vent stream molar 

composition or TOC (less methane and 

ethane) reduction efficiency shall be 

prior to the inlet of the control device 

and after the recovery system. 

(2) Method 2. 2A, 2C, or 2D, as 

appropriate, for determination of the gas 

volumetric flow rates. 

(3) The emission rate correction 

factor, integrated sampling and analysis 

procedure of Method 3 shall be used to 

determine the oxygen concentration 

(%02d) for the purposes of determining 

compliance with the 20 ppmv limit. The 

sampling site shall be the same as that 

of the TOC samples and the samples 

shall be taken during the same time that 

the TOC samples are taken. The TOC 

concentration corrected to 3 percent Oj 

(CJ shall be computed using the 

following equation: 

17.9 

Cc=Croc= 

20.9-%0id 

Where: 

C, =Cortcentration of TOC corrected to 3 

percent Oi. dry basis, ppm by volume. 

CT.<-=Concentration of TOC (minus methane 

and ethane), dry basis, ppm by volume. 

%iht—Concentration of Oj. dry basis, percent 

by volume. 

(4) Method 18 to determine the 

concentration of TOC in the control 

device outlet and the concentration of 

TOC in the inlet when the reduction 

efficiency of die control device is to be 

determined. 

(i) The sampling time for each run 

shad be 1 hour in which either an 

integrated sample or four grab samples 

shall be taken. If grab sampling is used 

then the samples shall be taken at 15-

minute intervals. 

(ii) The emission reduction (R) of TOC 

(minus methane and ethane) shall be 

determined using the following equation: 

Ei-E. 

X10O 

where: 

R = Emission reduction, percent by weight. 

E,=Maso rate of TOC entering the control 

device, kg TOC/hr. 

E„-Maoo rate of TOC discharged to the 

atmosphere, kg TOC/hr. 

(iii) The mass rates of TOC (Et. E„) 

shall be computed using tiie following 

equations: 

n 

E,=K8 ( X CMi) Qi 

i =* 

*%=K* ( 2 C*H»> Qo 

i=* 

where: 

Croc=Concentration of sample component 

"j" of die gas stream at die inlet and 

outlet of the control device, respectively, 

dry basis, ppm by volume. 

M„. Mo=Molecular weight of sample 

component "j" of the gas stream at the 

inlet and outlet of the control device, 

respectively, g/g-mole (lb/lb-mole). 

Qi. Q0=Flow rate of gao stream at the inlet 

and outlet of the control device, 

respectively, dscm/min (dscf/min). 

Ka=2.490 X 10-."(l/pm)(g-mole/scm)(kg/ 

g)(min/hr), where standard temperature 

for (g-mole/scm) io 20*C 

(iv) The TOC concentration (Croc) is 

the sum of die individual components 

end shall be computed for each run 

using the following equation: 

n 

Croc = X Cj 

1=1 

where: 

CTOC=Concentration of TOC (minus methane 

and ethane), dry basis, ppm by volume. 

C,=Concentration of oample component "j". 

dry basis, ppm by volume. 

n=Number of components in the sample. 

(5) When a boiler or process heater 

with a design heat input capacity of 44 

MW (150 million Btu/hour) or greater io 

used to seek to comply with g 60.702(a). 

the requirement for an initial 

performance test is waived, in 

accordance with g 60.8(b). However, the 

Administrator reserves the option to 

require testing at such other times as 

may be required, as provided for in 

section 114 of the Act 

(c) When a flare io used to seek to 

comply with g 60.702(b), the flare shall 

comply with the requirements of g 60.16. 

(d) The following test methodo in 

appendix A to this part, except so 

provided under 0 60.8(b), shall be used 

ao reference metiiods for determining 

die net heating value of ths gao 

combusted to determine compliance 

under 8 60.702(b) and for determining 

tiie process vent stream TRE index 

value to determine compliance under 

§ 60.702(c). 

(l)(i) Method 1 or IA, as appropriate, 

for selection of the sampling site. The 

sampling site for the vent stream molar 

composition determination and flow 

rate prescribed in g 60.704(d)(2) and 

(d)(3) shall be, except for the situations 

outlined in paragraph (d)(1)(H) of this 

section, prior to the inlet of any control 

device, prior to any post-reactor dilution 

of the stream with air, and prior to any 

post-reactor introduction of halogenated 

compounds into die process vent stream. 

No traverse site selection method is 

needed for vents smaller than 4 inches 

in diameter. 

(ii) If any gas stream other than the 

reactor vent stream is normally 

conducted through the final recovery 

device: 

(A) The sampling site for vent stream 

flow rate and molar composition shall 

be prior to the final recovery device and 

prior to the point at which any 

nonreactor stream or stream from a 

nonaffected reactor is introduced. 

(B) The efficiency of the final recovery 

device is determined by measuring the 

TOC concentration using Method 18 at 

the inlet to the final recovery device 

after the introduction of all vent streams 

and at the outlet of the final recovery 

device. 

(C) The efficiency of the final recovery 

device shall be applied to the TOC 

concentration measured prior to the 

final recovery device and prior to the 

introduction of any nonreactor stream or 

stream from a nonaffected reactor to 

determine the concentration of TOC in 

the reactor vent stream from the final 

recovery device. This concentration of 

TOC io then used to perform the 

calculations outlined in g 60.704(d) (4) 

and (5). 

(2) The molar composition of the vent 

stream shall be determined as follows: 

(i) Method 18 to measure the. 

concentration of TOC including those 

containing halogens. 

(ii) ASTM D1946-77 to measure the 

concentration of carbon monoxide and 

hydrogen. 

(iii) Method 4 to measure die content 

of water vapor. 

(3) The volumetric flow rate shall be 

determined using Method 2, 2A, 2C, or 

2D. as appropriate. 

(•>) The net heating value of Uie vent 

stream shall be calculated using the 

following equation: 

MT=K, ( 2 C.H,) 

| =1 

where: 
Federal Register / Vol. 55, Na 126 / Friday, June 29, 1990 / Proposed Rules 26975 

--Net heating value of die sample. M]/ 

sent, where the net enthalpy per mole of 

vent stream is based on combustion at 25 

"C and 760 mm Hg. bot me standard 

temperature for determining-the volume 

corresponding to one mole is 20 *C, as in 

the definition of Q, (vent stream flow 

rate). 

1 

ppm 

MJ 

Constant. 1.74OM0-r f \( moi e \( \ where standard temperature for ( mo! e ] i»20°C. 

C, = Concrr.tration on a wet basis of 

compound j rn ppm. as measured for 

organics by Method 18 and measured for 

hydrogen and carbon monoxide by 

ASTM D1946-77 as indicated in 

8 60.704(d)(2). 

H,=N'et heat of combustion of compound j, 

kca!/g-mole, based on combustion at 25 

°C and 700 trim Hg. The heats of 

combustion of vent stream components 

would be required to be determined 

using ASTM D2332-78 if published 

values are not available or cannot be 

calculated. 

(5) The emission rate of TOC in the 

vent stream shall be calculated using the 

following equation: 

E

- »

c

-

K

- U CM1Q. 

1=1 

where: 

Eroc=Emissior. rate of TOC in ihe sample, 

kg/hr 

Ki= Constant, 2.494 x 10"«(l/ppm)(g-mole/ 

scrn)fkg/g)(rr.in/hr), where standard 

temperature for (g-moie/scm) is 20 °C 

C,=Concentration on a dry basis of 

compound J. in ppm a* aiea«uzed by 

Method 18 as indicated in { 60.704(d)(2) 

Mj = Molecular weight of sample J, g/g-mole 

Q, = Vent stream flaw rate (scm/min) at a 

standard temperature of 20 *C 

(8) The total vent stream 

concentration (by volume) of 

compounds containing halogens (ppmv. 

by compound) shall be summed from the 

individual concentrations of compounds 

containing halogens which \ve:e 

measured by Metiiod 18. 

(e) For purposes of complying with. 

{f 60.702tc), the owner or operator of a 

facility affected by this subpart shall 

calculate the TRE index value of the 

vent stream using the equation for 

incineration in paragraph (e)(1) of this 

section for halogenated vent streams. 

The owner or operator of an affected: 

facility with a nonhalogenated vent 

stream shall determine the TRE index 

value by calculating values using both 

the incinerator equation in paragraph 

(e)(1) of thia section and the flare 

equation in paragraph (e)(2) of this 

section and selecting tile lower of the 

two values. 

(1) The equation for calculating ths 

TRE index value of a vent stream 

controlled by an incinerator is ss 

follows: 

TRE = (a+bfQJ a"+c(CW+-l(qjlHT) + etQ.r*,mr) a"**flYJ'--) 

ETOC 

(i) where for a vent stream flow rate 

(scm/min) at a standard temperature of 

20 °C that is greater than or equal to 14.2 

scm/min: 

TRE-TRE index value. 

Q.== Veirt stream flow rate (scm/min) at a 

stmid.-ird temperature of 20 "C. 

Ht= Vent stream net heating value (MJ/scm). 

where the net enthalpy per mole of vent 

stream is based on combustion at 25 *C 

and 760 mm Hg, but the standard 

temperature for determining die volume 

corresponding to one mole is 20 *C a* in 

the definition of Q, 

V. = Q. for all vent stream categories listed 

in Table 1 except for Category E vent 

streams where Y, = (Q.) (Hr)/3.9. 

E10C = Hourly emissions of TOC reported in 

kg/hr. a, b, e, d, e. and f are coefficients. 

The set of coefficients that apply to a 

vent stream can be obtained from Table 

1. 

BILUH6 COOE 6M0-M-M 
P.25 

26976 Federal Register / Vol. 55, No. 126 / Friday, June 29.1990 / Proposed Rules 

TABLE 1 . REACTOR PROCESSES NSPS TRE COEFFICIENTS FOR VENT STREAMS CONTROLLED BY AN INCINERATOR 

DESIGN CATEGORY Al . FOR HALOGENATED PROCESS VENT STREAMS. IF 0 < NET HEATING VALUE (MJ/scm) < 3.5 : 

Q, • Vent Stream Flow rate 

(scm/min) 

14.2 < 0. < 

18.8 < 0? -

699 

1400 

2100 

2800 

«s 

°s 

Q$ 

Qs 

Os 

18.8 

699 

1400 

2100 

2800 

3500 

19.65559 

20.48848 

40.83338 

61.17828 

81.52318 

101.66608 

0.27948 

0.27948 

0.30372 

0.31887 

0.33007 

0.33902 

0.76683 

0.30929 

0.30929 

0.30929 

0.30929 

0.30929 

-0.13173 

-0.13173 

-0.13173 

-0.13173 

-0.13173 

-0.13173 

0.01044 

0.01044 

0.01477 

0.01809 

0.02088 

0.02335 

DESIGN CATEGORY A2. FOR HALOGENATED PROCESS VENT STREAMS. IF NET HEATING VALUE > 3.5 MJ/scm: 

Q. • Vent Stream Flow rate 

(scm/min) 

14.2 < Q, < 18.8 

18.8 < Qf < 699 

699 < Q, < 1400 

1400 < Q, < 2100 

2800 < QJ < 3500 

19.31203 

20.14491 

40.14625 

60.14759 

80.14892 

100.15026 

0.27099 

0.27099 

0.29449 

0.30917 

0.32003 

0.32872 

-0.20500 

-0.25255 

-0.25255 

-0.25255 

-0.25255 

-0.25255 

0.01044 

0.01044 

0.01477 

0.01809 

0.02088 

0.02335 

DESIGN CATEGORY B. FOR NONHALOGENATED PROCESS VENT STREAMS. IF 0 < NET HEATING VALUE (MJ/scm) < 0.48: 

Vent Stream Flow rate 

(scm/min) 

14.2 < Qs < 1340 

1340 "< 0. < 2690 

2690 < 0, < 4040 

8.84312 

17.55267 

26.25721 

0.10696 

0.11623 

0.12203 

0.09188 

0.09188 

0.09188 

-0.17252 

-0.17252 

-0.17252 

0.01044 

0.01477 

0.01809 

DESIGN CATEGORY C. FOR NONHALOGENATED PROCESS VENT STREAMS. IF 0.48 < NET HEATING VALUE (MJ/scm) < 1.9: 

Q« • Vent Stream Flow rate 

(scm/min) 

14.2 < Q, < 1340 

1340 < Q, < 2690 

2690 < Q, < 4040 

9.56783 

18.99209 

28.41635 

0.06187 

0.06723 

0.070S8 

0.32303 

0.32303 

0.32303 

-0.16316 

-0.16316 

-0.16316 

0.01044 

0.01477 

0.01809 

DESIGN CATEGORY D. FOR NONHALOGENATED PROCESS VENT STREAMS. IF 1.9 < NET HEATING VALUE (MJ/scm) < 3.6: 

Vent Stream Flow rate 

(scm/min) 

14.2 < Q, < 1180 

1180 < QI < 2370 

2370 < Q! < 3550 

6.87612 

13.60866 

20.34120 

0.07036 

0.07646 

0.08028 

0.02669 

0.02669 

0.02669 

0.01044 

0.01477 

0.01809 

DESIGN CATEGORY E. FOR NONHALOGENATED PROCESS VENT STREAMS, IF NET HEATING VALUE > 3.6 MJ/scm: 

Y, • Dilution Flow rate 

(scVmln) • (Q,) (HT)/3.6 

14.2 « Y. < 1180 

1180 « Y" < 2370 

2370 « Y, < 3550 

6.87612 

13.60866 

20.34120 

-0.00730 

-0.00730 

-0.00730 

0.02249 

0.02445 

0.02566 

0.01044 

0.01477 

0.01809 

WUJNO COOt MW-fO-C 
Federal Register / Vol. 55, No. 126 / Friday, June 29, 1990 / Proposed Rules 2G977 

(ii) For a vent stream flow rate (scm/ 

min) at a standard temperature of 20 *C 

that is less than 14.2 scm/min: 

TRE = TRE index value. 

Q, = 14.2 scm/min. 

HT = (FLOW) (HVAL)/112 

where die following inputs are used: 

FLOW = Vent steam flow rate (scm/min), at 

a standard temperature of 290 *C 

HVAL - Vent stream net heating value (MJ/ 

scm), where the net enthalpy per mole of 

vent stream is based on combustion at 25 

*C and 780 mm Hg, but uie standard 

temperature for determining the volume 

corresponding to one mole is 20 *C as in 

definition of Q, 

Y, — 14.2 scm/min for all vent streams 

except for Category E vent streams, 

where Y, - (14.2)(Hr)/3.6. 

Eroc - Hourly emissions of TOC reported in 

kg/hr. 

a. b, c, d. e, and f are coefficients. 

The set of coefficients that apply to a 

vent stream can be obtained from Table 

1. 

(2) The equation for calculating die 

TRE index value of a vent stream 

controlled by a flare is as follows: 

TRE : 

Eroc 

(a (QJ+b (Q."+r (Q.)(Hr)-i-d (ErocJ+e) 

where: 

TRE = TRE index value. 

Eroc = Hourly emission rate of TOC reported 

in kg/hr. 

Q, = Vent stream flow rate (scm/min) at a 

standard temperature of 20 "C. 

HT *> Vent stream net heating value (M]/ 

scm). where the net enthalpy per mole of 

offgas it based on combustion at 25 "C 

and 760 mm Hg, but the standard 

temperature for determining the volume 

corresponding to one mole is 20 "C as in 

definition of Q,. 

a, b, c d, e, and f are coefficients. 

The set of coefficients that apply to a 

vent stream can be obtained from Table 

2. 

TABLE 2.—REACTOR PROCESSES NSPS TRE COEFFICIENTS FOR VENT STREAMS CONTROLLED BY A FLARE 

Hr<11.2MJ/scm.. 

HT>11.2 MJ/scm., 

2.25 

0.309 

0.288 

0.0619 

-0.183 

-0.0043 

-0.0081 

-0.0034 

2.08 

2.08 

(f) Each owner or operator of an 

affected facility seeking to comply with 

§ 60.700(c)(2) or § 60.702(c) shall 

recalculate the TRE index value for the 

affected facility whenever process 

changes are made. Examples of process 

changes include changes in production 

capacity, feedstock type, or catalyst 

type, or whenever there is replacement, 

removal, or addition of recovery 

equipment. The TRE index value shall 

be recalculated based on test data, or on 

best engineering estimates of the effects 

of the change on the recovery system. 

(1) Where the recalculated TRE index 

value is less than or equal to 1.0, the 

owner or operator shall notify the 

Administrator within 1 week of the 

recalculation and shall conduct a 

performance test according to the 

methods and procedures required by 

S 60.704 in order to determine 

compliance with 8 80.702(a). 

Performance tests must be conducted as 

soon as possible after die process 

change but no later than 180 days from 

die time of the process change. 

(2) Where the initial TRE index value 

is greater than 8.0 and the recalculated 

TRE index value is less than or equal to 

8.0 but greater than 1.0, the owner or 

operator shall conduct a performance 

test in accordance with § 60.8 and 

S 60.704 and shall comply with { 60.703, 

§ 60.704, and 8 60.705. Performance tests 

must be conducted as soon as possible 

after the process change but no later 

than 180 days from the time of the 

process change. 

(g) Any owner or operator subject to 

the provisions of this subpart seeking to 

demonstrate compliance witii 

S 60.700(c)(4) shall use Method 2, 2A, 2C, 

or 2D of appendix A to part 60, as 

appropriate, for determination of 

volumetric flow rate. 

§ 60.705 Reporting and recordkeeping 

requirements. 

(a) Each owner or operator subject to 

S 60.702 shall notify the Administrator of 

the specific provisions of 9 60.702 

(5 60.702 (a), (b). or (c)) with which the 

owner or operator has elected to 

comply. Notification shall be submitted 

with the notification of initial start-up 

required by $ 60.7(a)(3). If an owner or 

operator elects at a later date to use an 

alternative provision of § 60.702 witii 

which he or she will comply, then the 

Administrator shall be notified by the 

owner or operator 90 days before 

implementing a change and, upon 

implementing die change, a performance 

test shall be performed as specified by 

S 60.704 within 180 days. 

(b) Each owner or operator subject to 

the provisions of this subpart shall keep 

an up-to-date, readily accessible record 

of the following data measured during 

each performance test, and also include 

the following data in the report of the 

initial performance test required under 

8 60.8. Where a boiler or process heater 

with a design heat input capacity of 44 

MW (150 million Bru/hour) or greater is 

used to comply with S 60.702(a), a report 

containing performance test data need 

not be submitted, but a report containing 

the information in S 60.705(b)(2)(i) is 

required. The same data specified in thia 

section shall be submitted in the reports 

of all subsequently required 

performance tests where either the 

emission control efficiency of a control 

device, outlet concentration of TOC, or 

die TRE index value of a vent stream 

from a recovery system is determined. 

(1) Where an owner or operator 

subject to the provisions of tiiis subpart 

seeks to demonstrate compliance with 

8 60.702(a) through use of either a 

thermal or catalytic incinerator 

(i) The average firebox temperature of 

the incinerator (or the average 

temperature upstream and downstream 

of the catalyst bed for a catalytic 

incinerator), measured at least every 15 

minutes and averaged over the same 

time period of the performance testing, 

and 

(ii) The percent reduction of TOC 

determined as specified in 8 60.704(bj 

achieved by the incinerator, or the 
26978 Federal Register / Vol. 55. No. 126 / Friday, June 29, 1990 / Proposed Rules 

concentration of TOC (ppmv. by 

compound) determined as specified in 

8 60.704(b) at the outlet of die control 

device on a dry basis corrected to 3 

percent oxygen. 

(2) Where an owner or operator 

subject to the provisions of this subpart 

seeks to demonstrate compliance with 

8 60.702(a) through use of a boiler or 

process heater 

(i) A description of the location at 

which the vent stream is introduced into 

the boiler or process heater, and 

(ii) The average combustion 

temperature of the boiler or process 

heater with a design heat input capacity 

of less than 44 MW (150 million Btu/hr) 

measured at least every 15 minutes and 

averaged over the same time period of 

the performance testing. 

(3) Where an owner or operator 

subject to die provisions of this subpart 

seeks to demonstrate compliance with 

8 60.702(b) through use of a smokeless 

flare, flare design (i.e., steam-assisted, 

air-assisted or non-assisted), all visible 

emission readings, heat content 

determinations, flow rate 

measurements, and exit velocity 

determinations made during the 

performance test continuous records of 

the flare pilot flame monitoring, and 

records of all periods of operations 

during which die pilot flame is absent. 

(4) Where an owner or operator 

subject to die provisions of this subpart 

seeks to demonstrate compliance with 

8 60.702(c): 

(i) Where an absorber is the final 

recovery device in the recovery system, 

the exit specific gravity (or alternative 

parameter which is a measure of the 

degree of absorbing liquid saturation, if 

approved by the Administrator), and 

average exit temperature of the 

absorbing liquid, measured at least 

every 15 minutes and averaged over die 

same time period of die performance 

testing (both measured while die vent 

stream is normally routed and 

constituted), or 

(ii) Where a condenser is die final 

recovery device in die recovery system, 

the average exit (product side) 

temperature measured at least every 15 

minutes and averaged over the same 

time period of the performance testing 

while the vent stream is routed and 

constituted normally, or 

(iii) Where a carbon adsorber is die 

final recovery device in the recovery 

system, the total steam mass flow 

measured at least every 15 minutes and 

averaged over die same time period of 

the performance test (full carbon bed 

cycle), temperature of the carbon bed 

after regeneration (and within 15 

minutes of completion of any cooling 

cycle(s)), and duration of the carbon bed 

steaming cycle (all measured while the 

vent stream fa routed and constituted 

normally), or 

(iv) As an alternative to 8 60.705 

(bpjtil (bJHJCm or [hmm. the 

concentration level or reading indicated 

by the organics monitoring device at the 

oudet of the absorber, condenser, or 

carbon adsorber, measured at least 

every 15 minutes and averaged over the 

same time period of die performance 

testing while the vent stream is normally 

routed and constituted. 

(v) All measurements and calculations 

performed to determine the TRE index 

value of the vent.stream. 

(c) Each owner or operator subject to 

the provisions of this subpart shall keep 

up-to-date, readily accessible 

continuous records ofthe equipment 

operating parameters specified to be 

monitored under 8 60.703 (a) and (c) as 

well as up-to-date, readily accessible 

records of periods of operation during 

which the parameter boundaries 

established during die most recent 

performance test are exceeded. The 

Administrator may at any time require a 

report of tiiese data. Where a 

combustion device is used to comply 

with 8 60.702(a), periods of operation 

during which the parameter boundaries 

established during the most recent 

performance tests are exceeded are 

defined as follows: 

(1) For thermal incinerators, all 3-hour 

periods of operation during which the 

average combustion temperature was 

more than 28 X (50 °F) below die 

average combustion temperature during 

the most recent performance test at 

which compliance with 8 60.702(a) was 

determined. 

(2) For catalytic incinerators, all 3-

hour periods of operation during which 

die average temperature of the vent 

stream immediately before the catalyst 

bed is more than 28 "C (50 °F) below the 

average temperature of the vent stream 

during die most recent performance test 

at which compliance with 8 60.702(a) 

was determined. The owner or operator 

also shall record all 3-hour periods of 

operation during which the average 

temperature difference across the 

catalyst bed is less than 80 percent of 

the average temperature difference of 

the device during the most recent 

performance test at which compliance 

with 8 60.702(a) was determined. 

(3) All 3-hour periods of operation 

during which die average combustion 

temperature was more than 28 *C (50 °F) 

below the average combustion 

temperature during die most recent 

performance test at which compliance 

with 8 66702(a) was determined for 

boilers or process heaters with a design 

heat input capacity of less than 44 MW 

(150 million Btu/hr). 

(4) For boilers or process heaters, 

whenever there is a change in the 

location at which the vent stream is 

introduced into the flame xnrre as 

required under 8 60.702(a). 

(d) Each owner or operator subject to 

the provisions of this subpart shall keep 

up to date, readily accessible continuous 

records of die indication of flow 

specified under 8 60.703(a)(2), 

8 60.703(b)(2) and 8 60.703(c)(1). as well 

as up-to-date, readily accessible records 

of all periods when the vent stream is 

diverted from the control device or has 

no flow rate. 

(e) Each owner or operator subject to 

the provisions of tins subpart who uses 

a boiler or process heater witii a design 

heat input capacity of 44 MW or greater 

to comply with 8 60.702(a) shall keep an 

up-to-date, readily accessible record of 

all periods of operation of the boiler or 

process heater. (Examples of such 

records could include records of steam 

use, fuel use, or monitoring data 

collected pursuant to other State or 

Federal regulatory requirements.) 

(f) Each owner or operator subject to 

the provisions of this subpart shall keep 

up-to-date, readily accessible 

continuous records of die flare pilot 

flame monitoring specified under 

8 60.703(b), as well as up-to-date, 

readily accessible records of all periods 

of operations in which the pilot flame is 

absent 

(g) Each owner or operator subject to 

the provisions of this subpart shall keep 

up-to-date, readily accessible 

continuous records of die equipment 

operating parameters specified to be 

monitored under 8 60.703(d). as well as 

up-to-date, readily accessible records of 

periods of operation during which the 

parameter boundaries established 

during the most recent performance test 

are exceeded. The Administrator may at 

any time require a report of tiiese data. 

Where an owner or operator seeks to 

comply with 6 60.702(c), periods of 

operation during which die parameter 

boundaries established during the most 

recent performance test ore exceeded 

are defined as follows: 

(1) Where an absorber is die final 

recovery device in a recovery system. 

and where an organic compound 

monitoring device is not used: 

(i) All 3-hour periods of operation 

during which the average absorbing 

liquid temperature was more tiian 11 *C 

(20 *F) above die average absorbing 

liquid temperature during the most 

recent perfonnance test or 

(ii) All 3-hour periods of operation 

during which the average absorbing 
I 

Federal Risgistag / Vol. 55, No. 120 / Friday, June 29, 1990 / Proposed Rules 26979 

liquid specific gravity was more than 0.1 

unit above, or more than 0.1 unit below, 

the average absorbing liquid specific 

gravity during the most recent 

performance test (unless monitoring of 

an alternative parameter, which is a 

measure of the degree of absorbing 

liquid saturation, is approved by die 

Administrator, in which case he will 

define appropriate parameter 

boundaries and periods of operation 

during which they are exceeded). 

(2) Where a condenser is the final 

recovery device in a system, and where 

an organic compound monitoring device 

is not used, all 3-hour periods of 

operation during which the average exit 

(product side) condenser operating 

temperature was more than 8 °C (11 *F) 

above the average exit (product side) 

operating temperature during the most 

recent performance test. 

(3) Where a carbon adsorber is the 

final recovery device in a system, and 

where an organic compound monitoring 

device is not used: 

(i) All carbon bed regeneration cycles 

during which die total mass steam flow 

was more than 10 percent below die 

total mass steam flow during the most 

recent performance test, or 

(ii) All carbon bed regeneration cycles 

during which the temperature of die 

carbon bed after regeneration [and after 

completion of any cooling cycle(s)] was 

more tiian 10 percent greater than the 

carbon bed temperature (in degrees 

Celsius) during the most recent 

performance test 

(4) Where an absorber, condenser, or 

carbon adsorber is die final recovery 

device in the recovery system and 

where an organic monitoring device is 

used, all 3-hour periods of operation 

during which the average organic 

compound concentration level or 

reading of organic compounds in die 

exhaust gases is more tiian 20 percent 

greater than the exhaust gas organic 

compeund concentration level or 

reading measured by the monitoring 

device during die most recent 

performance test. 

(h) Each owner or operator of an 

affected facility subject to the provisions 

of this subpart and seeking to 

demonstrate compliance witii § 60.702(c) 

shall keep up-to-date, readily accessible 

records of: 

(1) Any changes in production 

capacity, feedstock type, or catalyst 

type, or cf any replacement, removal or 

addition of recovery equipment or 

reactors; 

(2) Any recalculation of tiie TRE index 

value performed pursuant to § 60.704(f); 

and 

(3) The results of any performance test 

performed pursuant to the methods and 

procedures required by g 60.704(d). 

(i) Each owner or operator of an 

affected facility that seeks to comply 

with the requirements of this subpart by 

complying with die flow rate cutoff in 

g 60.700(c)(4) shall keep up-to-date, 

readily accessible records to indicate 

that the stream flow rate is less than 

0.011 scm/min and of any change in 

equipment or process operation that 

increases the operating vent stream flow 

rate, including a measurement of the 

new vent stream flow rate. 

(j) Each owner or operator of an 

affected facility that seeks to comply 

with the requirements of tiiis subpart by 

complying with the design production 

capacity provision in g 60.700(c)(3) shall 

keep up-to-date, readily accessible 

records of any change in equipment or 

process operation that increases the 

design production capacity of the 

process unit in.which the affected 

facility is located. 

(k) Each owner and operator subject 

to the provisions of this subpart is 

exempt from the quarterly reporting 

requirements contained in § 60.7(c) of 

the General Provisions. 

(I) Each owner or operator tiiat seeks 

to comply with die requirements of this 

subpart by complying with the 

requirements of g 60.700 (c)(2), (c)(3). or 

(c)(4) or g 60.702 shall submit to the 

Administrator semiannual reports of the 

following recorded information. The 

initial report shall be submitted within 8 

months after the initial start-up date. 

(1) Exceedances of monitored 

parameters recorded under § 60.705 (c) 

and (g). 

(2) All periods recorded under 

I 60.705(d) when die vent stream is 

diverted from the control device or has 

no flow rate. 

(3) All periods recorded under 

§ 60.705(e) when die boiler or process 

heater was not operating. 

(4) All periods recorded under 

§ 60.705(f) in which the pilot flame of die 

flare was absent 

(5) Any change in equipment or 

process operation tiiat increases the 

operating vent stream flow rate above 

the low flow exemption level in 

§ 60.700(c)(4), including a measurement 

of die new vent stream flow rate, as 

recorded under § 60.705(i). These must 

be reported as soon as possible after die 

change and no later than 180 days after 

the change. A performance test must be 

completed within the same time period 

to verify die recalculated flow value and 

to obtain the vent stream characteristics 

of heating value and Eroc- The 

performance test is subject to the 

requirements of g 60.8 of die General 

Provisions. Unless the facility qualifies 

for an exemption under the low capacity 

exemption status in g 60.700(c)(3), the 

facility must begin compliance with the 

requirements set forth in g 60.702. 

(6) Any change in equipment or 

process operation, as recorded under 

g 60.705(j), that increases the design 

production capacity above the low 

capacity exemption level in 

§ 60.700(c)(3) and the new capacity 

resulting from the change for the reactor 

process unit containing the affected 

facility. These must be reported as soon 

as possible after die change and no later 

than 180 days after the change. A 

performance test must be completed 

within the same time period to obtain 

die vent stream flow rate, heating value, 

and Eroc- The performance test is 

subject to the requirements of g 60.8 of 

the General Provisions. Unless the 

facility qualifies for an exemption under 

the flow exemption in g 60.700(c)(4), the 

facility must begin compliance with the 

requirements set forth in g 60.702. 

(7) Any recalculation of the TRE index 

value, as recorded under § 60.702(h). 

(m) The requirements of § 60.705(1) 

remain in force until and unless EPA, in 

delegating enforcement authority to a 

State under section 111(c) of the Act, 

approves reporting requirements or an 

alternative means of compliance 

surveillance adopted by such State. In 

diat event affected sources witiiin the 

State will be relieved of the obligation to 

comply witii g 60.705(i), provided diat 

they comply with the requirements 

established by the State. 

(n) Each owner or operator that seeks 

to demonstrate compliance with 

g 60.700(c)(3) must submit to the 

Administrator an initial report detailing 

die design production capacity of the 

process unit 

(o) Each owner or operator diat seeks 

to demonstrate compliance with 

g 60.700(c)(4) must submit to die 

Administrator an initial report including 

a flow rate measurement using the test 

methods specified in g 60.704. 

(p) The Administrator will specify 

appropriate reporting and recordkeeping 

requirements where the owner or 

operator of an affected facility complies 

with the standards specified under 

§ 60.702 other than as provided under 

§ 60.703 (a), (b), (c), and (d). 

§ 60.703 ftoconotructtsn. 

(a) For purposes of this subpart "fixed 

capital cost of die new components." as 

used in g 60.15, includes the fixed 

capital cost of all depreciable 

components which are or will be 

replaced pursuant to all continuous 

programs of component replacement 
26980 Federal Register / Vol. 55, Ne. 126 / Friday. Jane 29, 1990 / Proposed Rules 

which are commenced within any 2-year 

period following June 29,1990. For 

purposes of this paragraph, 

"commenced" means that an- owner ar 

operator has undertaken a com*inuou# 

program of component replacement or 

that an owner or operator has entered 

into a contractual obligation to 

undertake and complete, within a 

reasonable time, a continuous program 

of component replacement 

§60.707 CtMmicals affected by subpart 

RRR. 

Chemical name 

Acetaldehyde.. 

Acetic aad. -

Acetic anhydride 

Acetone . 

Acetone cyanohydrin.. 

Acetylene _ 

Acrylic acid — 

AcrytonitriteAdipic acid.. 

Adipofiitiilo. 

Alcohols, C-11 or lower, mixture* 

Alcohotoa, C-12 or higher, mixture*. 

Alcohols, C-12 or higher, unmixed..-

Allyl chloride _.... 

Amylene.... 

Amytenes, mixed.. 

Aniline 

Benzene 

Benzenesulfonic acid _ _ 

Benzenesulfonic acid C,0 >.-atkyt derivatives, aodkim salts. 

Benzyl chloride 

Bisphenol A 

Brometone 

1.3-Butadiene ._ _.. 

Butadiene and butene tractions .-. 

n-Butane 

1.4-Butanediol.. 

Butanes, mixed... 

1-Butene 

2-Butene 

Butenes. mixed... 

n-Butyl acetate... 

Butyl acrylate... 

n-Butyt alcohol _ 

sec-Butyl alcohol 

ten-Butyl alcohol 

Butyloenzyt phthalate.. 

tert-Butyl hydroperoxide.. 

2-Butyne-1.4«*ol 

ButyraldehydT. 

Butyric anhydride 

Caproiactam 

Carbon disulfide 

Carbon tetrachloride 

Crttoroacetic acid 

Chlorobenxene 

Chlorodif luoromethane... 

Chlufuf(ovm_ - .... 

p-Chlofonrtrobenzen* 

Citric acid 

Cumene 

Cumene hydroperoxide.. 

Cyanuric chloride 

Cyctohexane 

Cydohexane, oxkfesd.... 

CASNa' 

75-07-0 

64-10-7 

108-24-7 

67-64-1 

75-66-5 

74-86-2 

76-10-7 

107-19-1 

124-04-6 

T11-68-3 

107-05-1 

513-35-8 

62-53-3 

71-43-2 

98-11-3 

66081-61-2 

100-44-7 

80-05-7 

76-08-4 

106-96-0 

106-87-6 

110-63-4 

106-96-6 

25167-67-3 

123-86-4 

141-32-2 

71-36-3 

78-93-2 

75-65-0 

85-86-7 

75-61-2 

110-65-6 

123-72-6 

106-31-0 

105-60-2 

75-15-0 

56-23-5 

76-11-6 

108-60-7 

75-»5-6 

67-66-3 

100-00-5 

77-92-6 

98-82-8 

60-15-6 

108-77-0 

110-62-0 

66512-15-2 

Chen ricar name 

Cyclohexanot 

Cydohexanono 

Cydohoxanone oxsno>» 

Cydohaxene 

Cyclopropane -

Diacetone alcohol 

1,4-OtcrttorooutBne 

3,4-Dichloro-t-butena 

Dichlorodifluoromethano... 

Dichlorodimethytstlane 

Dichlorofluoroniethane 

Oiethanolamina 

Diethylbonzono ,.._.._.. _ 

Diethylene glycolDi-isodecyt phthalate 

Dimethyl terephthalate 

2,4-(and 2,6HJtnitrotoluene_ 

Dtoctyt phthalate.. 

Dodocono*.. 

Dodecylbenzewe.. wow linear— 

Dodecytbenzeneaultonlc acidDodecytbenzenesulfonic 

sodium sett 

Epichlorohydrtn 

Ethanol 

EthanolartWn*.. 

Ethyl acetateEthyl acrylate.. 

Ethylbenzene.. 

Ethyl chloride.. 

Ethylene . 

acid. 

Ethylene dibromideEthylene dichloride ..... 

Ethylene glycol.. 

Ethylene glycol monbutyl ether 

Ethylene glycol monethyl ether acetate. 

Ethylene glycol monomethyl ether — 

Ethylene oxide _ 

2-Ethylhexyl alcohol 

(2-EthylhexyQ amine 

6-EthyM ,2,3.4-tetrahydro 9.10-entracenedkme. 

Formaldehyde 

Glycerol—-..-........». -

n-Heptane..__ »__._._ 

Heptanes (mixed) 

Hexamethylene diamine.-

Hexamethytene diamine adipate 

Hexamethylenetetramine 

Hexane -

Isobutane.... 

Isobutanol _ 

Isobutylene 

laobytyraldehyde 

Ii 

Isopropanol— 

Ketsne 

Linear alcohol*, ethoxylated, mixedLinear alcohols, ethoxylated, and 

sulfated, sodium salt, mixed. 

Linear afcytbenzene — 

Maleic anhydride 

Mesityl oxide 

CAS NO.1 

10&-93-0 

108>-94-1 

100-64-1 

t10-83-6 

75-16-4 

123-42-2 

110-57-6 

64037-54-3 

75-71-6 

75-78-5 

75-43-4 

111-42-2 

25340-17-4 

Methanol.. 

Methylamine -

ar-Methytbenzenediamine.. 

Methyl chloride 

Methylene chloride 

Methyl ethyl ketone 

Methyl isobutyl ketone 

Methyl methacrylate -

m-46- » 

26761-40-0 

120-61-6 

121-14-2 

606-20-2 

117-61-7 

25376-22-7 

27176-87-0 

25155-30-0 

106-66-6 

64-17-6 

141-43-5 

U1-78-6 

140-66-6 

100-41-4 

75-00-3 

74-85-1 

106-93-4 

107-06-2 

107-21-1 

111-76-2 

H1-15-9 

109-66-4 

75-21-6 

104-76-7 

104-75-6 

15547-17-6 

50-00-0 

56-61-6 

142-82-5 

124-06-4 

3323-63-3 

100-97-0 

110-54-3 

75-26-6 

78-63-1 

115-11-7 

78-84-2 

78-76-4 

78-79-6 

67-63-0 

463-51-4 

123-01-3 

106-31-6 

141-79-7 

67-56-1 

74-39-5 

25376-45-8 

74-87-3 

75-09-2 

78-93-3 

106-10-1 

60-62-6 

Chemical name 

1 -Methyl-2-pynoltiJono... 

Methyl tert-butyl ether _ 

Naphthalene 

1-Nonene 

Nonyi alcohol.. 

NonytpbonoJ 

Nonylphenol. ethoxylated 

Octene 

Oil-soluable petroleum sulfonate, 

calcium salt 

Pentaerythritoi 

3-Pentenenitrile 

Pentenes, mixed _ 

Perchchkxoethytene 

1-Phenytethyi hydroperoxide. 

Phenytpropane __ 

Phthalic anhydride. 

Proplonaldohyde.. 

Propyl alcohoL—, 

CAS No.' 

Propylene glycol.. 

Propylene oxide. 

Sorbitol 

Styrene. 

Terephthalic acid .-— 

Tetraethyt lead -

Tetrahydrofuran .'. — — 

Tetra (methyl ethyf) lead.. 

Tetramethyl lead - -

Toluene „ .__ 

Toluen».2.4-dnvnine 

Tokjene-2,4-(and, 2.6HMsocyanate 

(80/20 mixture). 

itTtt-TficntofO*jMn6yw>M*>«>»<-R—~»~.>H*.. 

1,1 ^-Tnchtoi*o*Vittna> .„„..„.—..«....««, 

TrrcNoroethy(«n« 

TncMorofluoconwthsno —* ..... 

1.1 A-Trichloro-1 A2-trtlluoroethane... 

Triethanolejnine.-* ..—....— . 

Trlethylono glycol—.—_...--—.—-. 

Vinyl acetate __ 

Vmyl chloride _... 

Vinylidene chloride 

m-Xylene 

o-Xylene 

p-Xylene.. 

Xylenes (mixed)-

672-50-4 

61-20-3 

68-95-3 

27215-95-8 

143-08-08 

25154-52-3 

9016-45-6 

25377-63-7 

115-77-6 

4635-67-4 

109-67-1 

127-16-4 

106-95-2 

3071-32-7 

103-65-1 

75-44-5 

65-44-6 

74-66-6 

123-36-6 

71-23-6 

115-07-1 

57-65-6 

75-56-9 

50-70-4 

100-42-5 

100-21-0 

76-00-2 

109-69-9 

75-74-1 

106-66-3 

95-60-7 

26471-62-5 

71-56-6 

7640-5 

79-01-6 

75-69-4 

76-13-1 

102-71-6 

112-27-6 

108-05-4 

75-01-4 

75-35-4 

106-36-3 

95-47-6 

106-42-3 

1330-20-7 

'CAS numbers refer to the Chemical Abstract* 

Registry numbers assigned to specific chemicals, 

isomers, or mixture* of chemicals. Some ieofners or 

mixtures that are covered by the standards do not 

have CAS numbers assigned to them. The standards 

apply to a l of the chemicals listed, whether CAS 

numbers have been assigned or not 

860.708 Delegation of authority. 

(a) In delegating implementation and 

enforcement authority to a State under 

section 111(c) of die Act, the authorities 

contained in paragraph (b) of this 

section shall be retained by the 

Administrator and not transferred to a 

State. 

(b) Authorities which will not be 

delegated to States: i 60.703(e). 

[FR Doc 90-14266 Filed 6-28-90: 6:45 amj 

BILUNO COOf 4M0-6O-W