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REGULATORY IMPACT
ANALYSIS FOR THE
PETROLEUM REFINERY
NESHAP

REVISED DRAFT

Prepared for:

Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711

Prepared by:

E.H. Pechan & Associates, Inc.
5537-C Hempstead Way
Springfield, VA

E.H. Pechan & Associates, Inc.
3500 Westgate Drive, Suite 103
Durham, NC

and

Mathtech, Inc.
210 Carnegie Center, Suite 200
Princeton, NJ 08540

April 5, 1994

EPA Contract No. 68-D1-0144
Work Assignment No. 2-11 (Option 2)
Pechan Report No. 94.03.001/1050.027
CONTENTS

Page

TABLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi

FIGURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .vii

ACRONYMS AND ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . viii

EXECUTIVE SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . ES-1
ES.1 PURPOSE AND STATUTORY AUTHORITY . . . . . . . . . . . . ES-1
ES.2 PROPOSED PETROLEUM REFINERY EMISSION STANDARD . . . . . ES-2
ES.3 NEED FOR REGULATION . . . . . . . . . . . . . . . . . . ES-3
ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES. . . . . ES-4
ES.5 COST ANALYSIS . . . . . . . . . . . . . . . . . . . . . ES-4
ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS . . . . . . . . . . . ES-6
ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONSES-8
ES.8 QUANTITATIVE ASSESSMENT OF BENEFITS . . . . . . . . . . ES-8
ES.9 COMPARISON OF BENEFITS TO COSTS . . . . . . . . . . . .ES-10

1.0 INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1PURPOSE . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2LEGAL HISTORY AND STATUTORY AUTHORITY . . . . . . . . . . . . 2

2.0 PROPOSED PETROLEUM REFINERIES EMISSION STANDARD IN BRIEF. . . . 5
2.1THE EMISSION STANDARD IN BRIEF. . . . . . . . . . . . . . . . 5
2.1.1 Applicability of the Petroleum Refinery NESHAP . . . . 6
2.1.2 Miscellaneous Process Vent Provisions. . . . . . . . . 6
2.1.3 Storage Vessel Provisions. . . . . . . . . . . . . . . 7
2.1.4 Wastewater Provisions. . . . . . . . . . . . . . . . . 8
2.1.5 Equipment Leak Provisions. . . . . . . . . . . . . . . 8
2.1.6 Recordkeeping and Reporting Provisions . . . . . . . . 9
2.1.7 Emission Averaging . . . . . . . . . . . . . . . . . . 9

3.0 NEED FOR REGULATION . . . . . . . . . . . . . . . . . . . . . . 11
3.1MARKET FAILURE. . . . . . . . . . . . . . . . . . . . . . . . 11
3.1.1 Air Pollution as an Externality. . . . . . . . . . . . 12
3.1.2 Natural Monopoly . . . . . . . . . . . . . . . . . . . 12
3.1.3 Inadequate Information . . . . . . . . . . . . . . . . 13
3.2INSUFFICIENT POLITICAL AND JUDICIAL FORCES. . . . . . . . . . 13
3.3ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATION. . . . . . 14
3.3.1 Air Emission Characterization. . . . . . . . . . . . . 14
3.3.2 Harmful Effects of HAPs. . . . . . . . . . . . . . . . 15
3.4CONSEQUENCES OF REGULATORY ACTION . . . . . . . . . . . . . . 17
3.4.1 Consequences if EPA's Emission Reduction Objectives are Met 17
3.4.2 Consequences if EPA's Emission Reduction Objectives are Not Met 20

4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES. . . . . . . . . 23
4.1CONTROL TECHNIQUES. . . . . . . . . . . . . . . . . . . . . . 24
4.1.1 Combustion Technology. . . . . . . . . . . . . . . . . 24
4.1.2 Product Recovery Devices . . . . . . . . . . . . . . . 36
4.1.3 Leak Detection and Repair. . . . . . . . . . . . . . . 52
4.1.4 Internal Floating Roofs. . . . . . . . . . . . . . . . 62
4.2DESCRIPTION OF MACT AND SUMMARY OF REGULATORY ALTERNATIVES. . 65
4.2.1 Miscellaneous Process Vents. . . . . . . . . . . . . . 66
4.2.2 Storage Vessels. . . . . . . . . . . . . . . . . . . . 66
4.2.3 Wastewater Streams . . . . . . . . . . . . . . . . . . 67
4.2.4 Equipment Leaks. . . . . . . . . . . . . . . . . . . . 68
4.2.5 Summary of Alternatives. . . . . . . . . . . . . . . . 69
4.3NO ADDITIONAL EPA REGULATION. . . . . . . . . . . . . . . . . 69
4.3.1 Judicial System. . . . . . . . . . . . . . . . . . . . 69
4.3.2 State and Local Action . . . . . . . . . . . . . . . . 71
4.4ROLE OF COST EFFECTIVENESS IN CHOOSING AMONG REGULATORY
ALTERNATIVES. . . . . . . . . . . . . . . . . . . . . . . . . 71
4.5ECONOMIC INCENTIVES: SUBSIDIES, FEES, AND MARKETABLE PERMITS 72

5.0 COST ANALYSIS AND EMISSION REDUCTION. . . . . . . . . . . . . . 75
5.1APPROACH FOR ESTIMATING REGULATORY COMPLIANCE COSTS . . . . . 75
5.1.2 Calculations for Existing Sources. . . . . . . . . . . 77
5.1.3 Calculations for New Sources . . . . . . . . . . . . . 84
5.2TOTAL COMPLIANCE COST ESTIMATES, REDUCTIONS, AND COST
EFFECTIVENESS . . . . . . . . . . . . . . . . . . . . . . . . 87
5.3MONITORING, RECORDKEEPING, AND REPORTING COSTS. . . . . . . . 91

6.0 ECONOMIC IMPACTS AND SOCIAL COSTS . . . . . . . . . . . . . . . 97
6.1 PROFILE OF THE PETROLEUM REFINING INDUSTRY. . . . . . . . . 98
6.1.1 Profile of Affected Facilities . . . . . . . . . . . . 99
6.1.2 Market Structure . . . . . . . . . . . . . . . . . . .102
6.1.3 Market Supply. . . . . . . . . . . . . . . . . . . . .106
6.1.4 Market Demand Characteristics. . . . . . . . . . . . .107
6.1.5 Market Outlook . . . . . . . . . . . . . . . . . . . .111
6.2MARKET MODEL. . . . . . . . . . . . . . . . . . . . . . . . .114
6.2.1 Market Supply and Demand . . . . . . . . . . . . . . .114
6.2.2 Market Supply Shift. . . . . . . . . . . . . . . . . .115
6.2.3 Impact of Supply Shift on Market Price and Quantity. .119
6.2.4 Trade Impacts. . . . . . . . . . . . . . . . . . . . .119
6.2.5 Changes in Economic Welfare. . . . . . . . . . . . . .120
6.2.6 Labor Market and Energy Market Impacts . . . . . . . .123
6.2.7 Baseline Inputs. . . . . . . . . . . . . . . . . . . .124
6.2.8 Price Elasticities of Demand and Supply. . . . . . . .124
6.3CAPITAL AVAILABILITY ANALYSIS . . . . . . . . . . . . . . . .127
6.4LIMITATIONS OF THE ECONOMIC MODEL . . . . . . . . . . . . . .131
6.5PRIMARY IMPACT, CAPITAL AVAILABILITY ANALYSIS, AND SECONDARY
IMPACT RESULTS. . . . . . . . . . . . . . . . . . . . . . . .133
6.5.1 Estimates of Primary Impacts . . . . . . . . . . . . .133
6.5.2 Capital Availability Analysis. . . . . . . . . . . . .136
6.5.3 Labor Market Impacts and Energy Market Impacts . . . .137
6.5.4 Foreign Trade Impacts. . . . . . . . . . . . . . . . .139
6.5.5 Regional Impacts . . . . . . . . . . . . . . . . . . .140
6.6SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . .140
6.7POTENTIAL SMALL BUSINESS IMPACTS. . . . . . . . . . . . . . .142
6.7.1 Introduction . . . . . . . . . . . . . . . . . . . . .142
6.7.2 Methodology. . . . . . . . . . . . . . . . . . . . . .142
6.7.3 Categorization of Small Businesses. . . . . . . . . .143
6.7.4 Small Business Impacts . . . . . . . . . . . . . . . .143
6.8SOCIAL COSTS OF REGULATION. . . . . . . . . . . . . . . . . .144
6.8.1 Social Cost Estimates. . . . . . . . . . . . . . . . .144

7.0 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONS . . .149
7.1IDENTIFICATION OF POTENTIAL BENEFIT CATEGORIES. . . . . . . .149
7.2QUALITATIVE DESCRIPTION OF AIR RELATED BENEFITS . . . . . . .150
7.2.1 Benefits of Decreasing HAP Emissions . . . . . . . . .150
7.2.2 Benefits of Reduced VOC Emissions. . . . . . . . . . .153

8.0 QUANTITATIVE ASSESSMENT OF BENEFITS . . . . . . . . . . . . . .157
8.1METHODOLOGY FOR DEVELOPMENT OF BENEFIT ESTIMATES. . . . . . .157
8.1.1 Benefits of Reduced Cancer Risk Associated with HAP Reductions158
8.1.2 Quantitative Benefits of VOC Reduction . . . . . . . .165

9.0 COMPARISON OF BENEFITS TO COSTS . . . . . . . . . . . . . . . .173
9.1COMPARISON OF ANNUAL BENEFITS AND COSTS . . . . . . . . . . .173
TABLES

Page
ES-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR THE PETROLEUM
REFINING INDUSTRY REGULATION. . . . . . . . . . . . . . . . ES-5
ES-2 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION. . . . . . . . . . . . . . . . . . . . . . . . . ES-7
ES-3 VOC EMISSION REDUCTIONS BY EMISSION POINT . . . . . . . . . ES-9
ES-4 BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS. . . . . . .ES-10
ES-5 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION. . . . . . . . . . .ES-11
ES-6 VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM REFINING
REGULATION. . . . . . . . . . . . . . . . . . . . . . . . .ES-11
3-1 NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION POINT . . 15
3-2 BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS . . . . 16
3-3 NATIONAL CONTROL COST IMPACTS OF PREFERRED ALTERNATIVE IN THE
FIFTH YEAR. . . . . . . . . . . . . . . . . . . . . . . . . . 19
4-1 SUMMARY OF REGULATORY ALTERNATIVES BY EMISSION POINT. . . . . 70
5-1 SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR FOR THE PETROLEUM
REFINING NESHAP . . . . . . . . . . . . . . . . . . . . . . . 88
5-2 CONTROL OPTIONS AND IMPACTS BY EMISSION POINT . . . . . . . . 89
5-3 COST, HAP EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE . . . . . . . . . . . . . . . . . . . . . . . . . 90
5-4 COST, VOC EMISSION REDUCTION, AND COST EFFECTIVENESS BY
ALTERNATIVE . . . . . . . . . . . . . . . . . . . . . . . . . 90
5-5 MISCELLANEOUS PROCESS VENTS þ MONITORING, RECORDKEEPING, AND
REPORTING REQUIREMENTS FOR COMPLYING WITH 98 WEIGHT-PERCENT
REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS
PER MILLION BY VOLUME . . . . . . . . . . . . . . . . . . . . 93
6-1 ESTIMATES OF PRICE ELASTICITY OF DEMAND . . . . . . . . . . .125
6-2 SUMMARY OF PRIMARY IMPACTS. . . . . . . . . . . . . . . . . .135
6-3 ANALYSIS OF FINANCIAL RATIOS. . . . . . . . . . . . . . . . .137
6-4 SUMMARY OF SECONDARY REGULATORY IMPACTS . . . . . . . . . . .138
6-5 FOREIGN TRADE (NET EXPORTS) IMPACTS . . . . . . . . . . . . .141
6-6 ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION. . . . . . . . . . . . . . . . . . . . . . . . . .145
7-1 POTENTIAL HEALTH AND WELFARE EFFECTS ASSOCIATED WITH EXPOSURE
TO HAZARDOUS AIR POLLUTANTS . . . . . . . . . . . . . . . . .151
8-1 HAP EMISSIONS AT PETROLEUM REFINERIES . . . . . . . . . . . .158
8-2 SOURCES OF UNCERTAINTY IN CANCER RISK ASSESSMENT. . . . . . .161
8-3 UNCERTAINTIES IN BENEFIT ANALYSIS . . . . . . . . . . . . . .161
8-4 UNIT RISK FACTORS FOR CARCINOGENIC HAPS . . . . . . . . . . .162
8-5 MAXIMUM INDIVIDUAL RISK AND ANNUAL CANCER INCIDENCE OF
CARCINOGENIC HAPs . . . . . . . . . . . . . . . . . . . . . .163
8-6 RFCS AND NUMBER OF INDIVIDUALS EXPOSED AT OR ABOVE RFC BY HAP164
8-7 VOC EMISSION REDUCTIONS BY EMISSION POINT . . . . . . . . . .169
8-8 BENEFITS OF VOC REDUCTIONS BY REGULATORY ALTERNATIVE . . . .170
8-9 VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM REFINING
REGULATION. . . . . . . . . . . . . . . . . . . . . . . . . .171
9-1 COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION. . . . . . . . . . . .175

FIGURES

Page

6-1 ILLUSTRATION OF POST-NESHAP MODEL. . . . . . . . . . . . . .118
ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute
ASM Annual Survey of Manufactures
bbl One barrel; equal to 42 gallons
bbl/d barrels per day
BCA Benefit Cost Analysis
BWON Benzene Waste Operations NESHAP (NESHAP is defined below)
CAA Clean Air Act Amendments of 1990
C/E cost effectiveness
CERA Cambridge Energy Research Associates
DOC Department of Commerce
DOE/EIA Department of Energy/Energy Information Administration
EIA economic impact analysis
EPA Environmental Protection Agency
FCCU fluidized catalytic cracking unit
HAP Hazardous Air Pollutant
HEM Human Exposure Model
HON Hazardous Organic NESHAP (NESHAP is defined below)
IARC International Agency for Research on Cancer
kPa kilopascal
LDAR leak detection and repair
LEL lower explosive limit
LPGs Liquefied Petroleum Gases
lpm liter per minute
MACT Maximum Achievable Control Technology
MIR maximum individual risk
MRR monitoring, recordkeeping, and reporting
MTBE Methyl tertiary butyl ether
Mg Megagram
NAAQS National Ambient Air Quality Standard
NESHAP National Emission Standard for Hazardous Air Pollutants
NSPS New Source Performance Standard
NOx nitrogen oxide
OGJ Oil and Gas Journal
OMB Office of Management and Budget
PADD Petroleum Administration for Defense Districts
ppmv parts per million by volume
RACT Reasonably Available Control Technology
RFA Regulatory Flexibility Act; also Regulatory Flexibility Analysis
RfC reference-dose concentration
RIA Regulatory Impact Analysis
SIC Standard Industrial Classification
SIP State Implementation Plan
SO2 sulfur dioxide
SOCMI Synthetic Organic Chemical Manufacturing industry
URF unit risk factor
VOC volatile organic compound EXECUTIVE SUMMARY

ES.1 PURPOSE AND STATUTORY AUTHORITY

This report analyzes the regulatory impacts of the Petroleum Refinery National Emission
Standard for Hazardous Air Pollutants (NESHAP), which is being promulgated under Section 112
of the Clean Air Act Amendments of 1990 (CAA). This emission standard would regulate the
emissions of certain hazardous air pollutants (HAPs) from petroleum refineries. The petroleum
refineries industry group includes any facility engaged in the production of motor gasoline,
naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel oils, lubricants, or other products
made from crude oil or unfinished petroleum derivatives. This report analyzes the impact that
regulatory action is likely to have on the petroleum refining industry, and on society as a whole.

The President issued Executive Order 12866 on October 4, 1993, which requires EPA to
prepare RIAs for all "significant" regulatory actions. EPA has determined that the petroleum
refinery NESHAP is a "significant" rule because it will have an annual effect on the economy of
more than $100 million, and is therefore subject to the requirements of Executive Order 12866.
This report satisfies the requirements of the executive order.In addition to a mandatory
assessment of benefits and costs, E.O. 12866 specifies that EPA, to the extent allowed by the
CAA and court orders, demonstrate (1) that the benefits of the NESHAP regulation will outweigh
the costs and (2) that the maximum level of net benefits (including potential economic,
environmental, public health and safety and other advantages; distributive impacts; and equity)
will be reached. EPA has chosen two regulatory options to be evaluated in this RIA. For each of
the two options, benefits and costs are quantified to the greatest extent allowed by available data.

The petroleum refinery NESHAP would require sources to achieve emission limits reflecting
the application of the maximum achievable control technology (MACT), consistent with
sections 112(d) and 112(h) of the CAA. Section 112 of the CAA provides a list of 189 HAPs and
directs the EPA to develop rules to control HAP emissions. For the Petroleum Refinery NESHAP,
EPA chose regulatory options based on control options on an emission point basis. An emission
point is defined as a point within a refinery which emits one or more HAPs. The emission points
to be regulated under the source category for this standard are: equipment leaks, storage vessels,
miscellaneous process vents, and wastewater collection and treatment systems.

ES.2 PROPOSED PETROLEUM REFINERY EMISSION STANDARD

The proposed rule, the Petroleum Refinery NESHAP, would require sources to achieve
emission limits reflecting the application of MACT. The definition of source in the proposed
standard is "the collection of emission points in HAP-emitting petroleum refining processes
within the source category." The source comprises all miscellaneous process vents, storage
vessels, wastewater collection and treatment systems, and equipment leaks associated with
petroleum refining process units that are located at a single plant site covering a contiguous area
under common control. The definition of source is an important element of this NESHAP
because it describes the specific grouping of emission points within the source category to which
each standard applies. The rule is made up of seven different subjects: applicability, definitions,
and general standards; miscellaneous process vent provisions; storage vessel provisions;
wastewater provisions; equipment leak provisions; recordkeeping and reporting provisions; and
emissions averaging. The proposed rule outlines the chosen option for controlling HAP
emissions from each of the four emission points within a refinery source, given existing control
technology.

The applicability of the rule refers to the definition of the source within the petroleum
refinery source category. The emission standard applies to petroleum refining process units that
are part of a major source as defined in Section 112 of the CAA. EPA's initial source category
list (57 FR 31576, July 16, 1992), required by section 112(c) of the Act, identifies categories of
sources for which NESHAP are to be established. Two categories of sources are listed in the
initial source category list for petroleum refineries: (1) catalytic cracking (fluid and other) units,
catalytic reforming units, and sulfur plant units and (2) other sources not distinctly listed. Based
on an EPA review of information on petroleum refineries during development of the proposed
standards, it was determined that some of the emissions points from the two listed categories of
sources have similar characteristics and can be controlled by the same control techniques. EPA
determined that it is most effective to regulate these emission points in a single regulation.

Data analyses conducted in developing the MACT floor for miscellaneous process vents
determined that combustion controls can achieve 98 percent organic HAP reduction or an outlet
organic HAP concentration of 20 ppmv or less for all vent streams. The storage vessel provision
specifies the control systems which represent the MACT floor to be applied to storage vessels.
The wastewater provisions of this rule are based on the benzene waste operations NESHAP
(BWON), which controls 75 percent of the benzene in refinery wastewater. The wastewater
streams subject to this rule include water, raw material, intermediate product, by-product,
co-product, or waste material that contains HAPs and is discharged into an individual drain
system. The equipment leak provisions
of the proposed rule are based on the negotiated equipment leak regulation included in the
Hazardous Organics NESHAP (HON) (40 CFR 63 subpart H).

The rule specifies the necessary recordkeeping and reporting requirements to verify
compliance with the MACT floor for each of the four emission points. EPA is also proposing that
emission averaging be allowed among existing miscellaneous process vents, storage tanks, and
wastewater streams within a refinery. Under emission averaging, a system of emission "credits"
and "debits" would be used to determine whether the source is achieving the required emission
reductions. If emissions averaging is accepted as part
of the standard, the rule would contain specific equations and procedures for calculating credits
and debits.

ES.3 NEED FOR REGULATION

One of the concerns about potential threats to human health and the environment from
petroleum refineries is the emission of HAPs. Health risks from emissions of HAPs into the air
include increases in cancer incidences and other toxic effects. The U.S. Office of Management
and Budget (OMB) directs regulatory agencies to demonstrate the need for an economically
significant rule. The RIA must show that a market failure exists and that it cannot be resolved by
measures other than Federal regulation. Externality is one type of market failure. HAP emissions
represent an externality in that refinery operation imposes costs on others outside of the
marketplace. In the case of this type of negative externality, the market price of goods and
services does not reflect the costs borne by receptors of the HAPs generated in the refining
process. With the NESHAP in effect, the amount that refiners must incur to refine petroleum
products will more closely approximate the full social costs of production. The necessity for a
uniform national standard is based on the determination that air pollution crosses jurisdictional
lines, and uniform national standards, unlike potentially piecemeal local standards, will be more
efficient to both industry and government.

ES.4 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES

Based on the determination of the MACT floor for each of the four emission points, EPA
developed two regulatory alternatives. Alternative 1 is a hybrid option, referred to as the
preferred alternative, which incorporates MACT floor level control for wastewater collection and
treatment systems, storage vessels, and miscellaneous process vents, and an option above the
floor for equipment leaks. Alternative 2 includes control levels above the floor for equipment
leaks and storage vessels.

ES.5 COST ANALYSIS

The annualized compliance costs by emission point are shown in Table ES-1 for the
preferred alternative (Alternative 1) and the more stringent alternative (Alternative 2). The total
national cost of Alternative 1 in the fifth year is $81 million, compared with a cost of $97 million
for Alternative 2. The difference between the two alternatives are the TABLE ES-1. SUMMARY OF TOTAL COSTS IN THE FIFTH YEAR
FOR THE PETROLEUM REFINING INDUSTRY REGULATION

Annual Fifth Year Costs (1000$/yr)4
(1992 Dollars)
Emission Point
OptionExisting SourcesNew
Construction
Total
Alternative 1
Alternative 2Equipment Leaks

Miscellaneous Process Vents

Wastewater Systems

Storage VesselsFloor
Option 11
Option 22

Floor3

Floor1
Option 1

Floor1
Option 12$69,000
$66,000
$78,000

$11,000

$ 0
$120,000

$3,700
$6,200$ 0
$(210)
$840

$370

$ 0
$18,000

$98
$550$69,000
$65,790
$78,840

$11,370

$ 0
$138,000

$3,798
$6,750
$65,790

$11,370

$ 0

$3,798

$78,840

$11,370

$ 0

$6,750TOTAL COST$80,958$96,960
NOTES: 1Alternative 1.
2Alternative 2.
3EPA did not choose an option above the MACT floor for miscellaneous process vents.
4Monitoring, recordkeeping, and reporting costs are not incorporated in the cost estimates in the table.increased costs associated with more stringent control techniques for equipment leaks and
storage vessels. In addition to provisions for the installation of control equipment, the proposed
regulation includes provisions for monitoring, recordkeeping, and reporting (MRR). EPA
estimates that the total annual cost for refineries to comply with the MRR requirements is $30
million. The MRR requirements are outlined separately in the proposed regulation for each
emission point.

ES.6 ECONOMIC IMPACTS AND SOCIAL COSTS

An economic impact analysis (EIA) was conducted to evaluate the effect of increased
compliance costs for emission control equipment on the domestic petroleum refining market.
The partial equilibrium model used in the EIA utilized the costs for Alternative 1 which were
presented in Table ES-1 to estimate primary market impacts including increases in price of
refined petroleum products, decreases in output levels, changes in the value of domestic
shipments, and possible refinery closures. Estimated secondary effects include labor market
adjustments, energy input market changes, and foreign trade effects. Welfare changes for
consumers, producers, and society at large or the social costs of the proposed emission controls
were also evaluated. The estimated market changes from the proposed emission controls were
relatively small.

The social costs of regulation incorporate costs borne by society for pollution abatement.
The social costs reflect the opportunity cost or economic cost of resources used in emission
control. Consumers, producers, and all of society bear the costs of pollution controls in the form
of higher prices, lower quantities produced, and possible tax revenues that may be gained or lost.
The annual social cost estimates for the preferred alternative and the more stringent alternative
are shown in Table ES-2. The social costs are used later in the RIA to conduct a benefit cost
analysis.TABLE ES-2. ANNUAL SOCIAL COST ESTIMATES FOR THE PETROLEUM REFINING
REGULATION
(Millions of 1992 dollars)

Social Cost Category
Net Costs1Surplus Losses for Preferred Alternative:
Change in Consumer Surplus
Change in Producer Surplus
Change in Residual Surplus to Society2
$476.19
$(242.11)
$(101.73)Total Social Cost of Alternative 13 $132.35Total Social Cost of Alternative 24$148.35
NOTES: 1Brackets indicate negative surplus losses or surplus gains.
2Residual surplus loss to society includes adjustments necessary to equate the relevant discount rate to the social
cost of capital and to consider appropriate tax effect adjustments.
3Alternative 1 includes floor controls for all emission points except equipment leaks. Option 1 is preferred to the
floor for equipment leaks because it is a less costly option than the floor.
4Alternative 2 includes Option 2 for Equipment Leaks, Option 1 for Storage Tanks, and the Floor for Miscellaneous
process vents. Emission controls at other emission points were not considered. Social costs were calculated by
adding incremental compliance costs for Alternative 2 to the social costs of Alternative 1.
ES.7 QUALITATIVE ASSESSMENT OF BENEFITS OF EMISSION REDUCTIONS

This RIA presents the results of an examination of the potential health and welfare benefits
associated with air emission reductions projected as a result of implementation of the petroleum
refinery NESHAP. The proposed regulation is expected to reduce emissions of HAPs emitted
from storage tanks, process vents, equipment leaks, and wastewater emission points at refining
sites. Of the HAPs emitted by petroleum refineries, some areclassified as VOCs, which are
ozone precursors. HAP benefits are presented separately from the benefits associated specifically
with VOC emission reductions.

The predicted emissions of a few HAPs associated with this regulation have been classified
as probable or known human carcinogens. As a result, one of the benefits of the proposed
regulation is a reduction in the risk of cancer mortality. Other benefit categories include reduced
exposure to noncarcinogenic HAPs, and reduced exposure to VOCs.

Emissions of VOCs have been associated with a variety of health and welfare impacts. VOC
emissions, together with NOx, are precursors to the formation of tropospheric ozone. Exposure
to ambient ozone is most directly responsible for a series of respiratory related adverse impacts.

ES.8 QUANTITATIVE ASSESSMENT OF BENEFITS

Based on existing data, the benefits associated with reduced HAP and VOC emissions were
quantified. The quantification of dollar benefits for all benefit categories is not possible at this
time because of limitations in both data and available methodologies. Although an estimate of
the total reduction in HAP emissions for various control options has been developed for this RIA,
it has not been possible to identify the speciation of the HAP emission reductions for each type
of emission point. However, an estimate of HAP speciation for equipment leaks has been made.
Using emissions data for equipment leaks and the Human Exposure Model (HEM), the annual
cancer risk caused by HAP emissions from petroleum refineries was estimated. Generally, this
benefit category is calculated as the difference in estimated annual cancer incidence before and
after implementation of each regulatory alternative. Since the annual cancer incidence associated
with baseline conditions was less than one life per year, the benefits associated with the
petroleum refinery NESHAP were determined to be small. Therefore, these benefits are not
incorporated into this benefit analysis.

The benefits of reduced emissions of VOC from a MACT regulation of petroleum refineries
were quantified using the technique of "benefits transfer." Because there is an assumption
incorporated into a report completed by the Office of Technology Assessment (OTA) from which
benefits transfer values were obtained that no health benefits are experienced in attainment areas,
the VOC emission reductions used in this analysis are defined in terms of reductions occurring
only in non-attainment areas. (Nonattainment areas are geographical locations in which the
Federal ambient air quality standard (NAAQS) for ozone has been violated.) Table ES-3 presents
the VOC emission reductions for refineries in nonattainment and attainment areas associated with
each alternative.

TABLE ES-3. VOC EMISSION REDUCTIONS BY EMISSION POINT

VOC Emission Reductions by Regulatory Alternative (Mg/yr)3Alternative 1Alternative 2Emission Point2Nonattainment1AttainmentNonattainment1AttainmentEquipment Leaks77,53580,26681,62683,471Miscellaneous Process Vents104,69355,161104,69355,161Storage Vessels3,0901,4086,0562,760TOTAL REDUCTION BY
ATTAINMENT STATUS
185,318
136,835
192,375
141,392TOTAL REDUCTION BY
ALTERNATIVE
322,153
333,767

NOTES: 1VOC emission reductions include only those associated with control of the 87 refineries located in ozone
nonattainment areas.
2No further control is assumed for wastewater streams, and therefore, emission reductions associated with this
emission point is zero.
3Emission reduction estimates do not incorporate reductions occurring at new sources.
The benefit transfer ratio range for acute health impacts used in this analysis is presented in
Table ES-4. In order to quantify VOC emission reductions, these ratios were multiplied by VOC
emission reductions from petroleum refineries located in ozone non-attainment areas. Estimated
benefits for VOC reductions are $148.3 million for Alternative 1 and $153.9 million for
Alternative 2.

TABLE ES-4. BENEFIT PER MEGAGRAM VALUES FOR VOC REDUCTIONS

Benefits Transfer Value11992 Dollars/Megagram2Average$800Range$25 - $1,574
NOTES: 1The benefits transfer value in the table quantifies only the benefits attributable to acute health impacts.
2Values are in first quarter 1992 dollars.
ES.9 COMPARISON OF BENEFITS TO COSTS

Table ES-5 depicts a comparison of the benefits of the alternative proposals to the
compliance and social costs. A comparison of the net benefits for the alternatives and the
incremental difference in net benefits between the alternatives provides an economic basis for
rational environmental policymaking. The benefits exceed costs for each of the alternatives.
Thus, either alternative is viable and warrants consideration. However, a comparison of the
incremental difference in the two alternatives indicates that the incremental net benefits are
negative for Alternative 2. Thus, Alternative 1 provides the greatest net benefits to society.

Based on the monetary estimates of the benefits associated with the Petroleum Refinery
NESHAP, incremental VOC cost-effectiveness values were calculated. The results of these
calculations are presented in Table ES-6. Alternative 1 can be justified as a desirable option
since the incremental VOC cost-effectiveness of implementing Alternative 2 is significantly
higher.

TABLE ES-5. COMPARISON OF ANNUAL BENEFITS TO COSTS FOR THE NATIONAL
PETROLEUM REFINING INDUSTRY REGULATION
(MILLIONS OF 1992 DOLLARS PER YEAR)

Alternative 1
Alternative 2Incremental
Difference1Benefits$148.3$153.9$5.6Social Costs$(132.35)$(148.35)2$(16.0)Benefits Less Social Costs$15.95$5.55$(10.4)
NOTES: ( ) represent costs or negative values.
1The incremental difference represents the difference between Alternative 1 and Alternative 2.
2Social costs for Alternative 2 are calculated by adding incremental compliance costs to social costs of
Alternative 1.

TABLE ES-6. VOC INCREMENTAL COST-EFFECTIVENESS OF PETROLEUM REFINING
REGULATION

Alternative 1Alternative 2Incremental Cost (Million $ 1992)1$132.35$16.0Incremental Emission Reduction (Mg)185,3187,057Incremental Cost Effectiveness ($/Mg)$714/Mg$2,267/Mg
NOTES: 1The cost estimates of each alternative reflect the total social cost of emission control. 1.0 INTRODUCTION

The regulation under analysis in this report, which is being promulgated under Section 112
of the Clean Air Act Amendments of 1990 (CAA), is the Petroleum Refinery National Emission
Standard for Hazardous Air Pollutants (NESHAP). This emission standard would regulate the
emissions of certain hazardous air pollutants (HAPs) from petroleum refineries. The petroleum
refineries industry group includes any facility engaged in producing motor gasoline, naphthas,
kerosene, jet fuels, distillate fuel oils, residual fuel oils, lubricants, or other products made from
crude oil or unfinished petroleum derivatives. This report analyzes the impact that regulatory
action is likely to have on the petroleum refining industry, and on society as a whole. Included
in this chapter is a summary of the purpose of this regulatory impact analysis (RIA), the statutory
history which preceded this regulation, and a description of the content of this report.

1.1 PURPOSE

The President issued Executive Order 12866 on October 4, 1993. It requires EPA to prepare
RIAs for all "significant" regulatory actions. The criteria set forth in Section 1 of the Order for
determining whether a regulation is a significant rule are that the rule: (1) is likely to have an
annual effect on the economy of $100 million or more, or adversely and materially affect a
sector of the economy, productivity, competition, jobs, the environment, public health or safety,
or State, local, or tribal governments or communities; (2) is likely to create a serious
inconsistency or otherwise interfere with an action taken or planned by another agency; (3) is
likely to materially alter the budgetary impact of entitlements, grants, user fees, or loan programs
or the rights and obligation of recipients thereof; or (4) is likely to raise novel legal or policy
issues arising out of legal mandates, the President's priorities, or the principles set forth in the
Executive Order. EPA has determined that the petroleum refinery NESHAP is a "significant" rule
because it will have an annual effect on the economy of more than $100 million, and is
therefore subject to the requirements of Executive Order 12866.

Along with requiring an assessment of benefits and costs, E.O. 12866 specifies that EPA, to
the extent allowed by the CAA and court orders, demonstrate (1) that the benefits of the NESHAP
regulation will outweigh the costs and (2) that the maximum level of net benefits (including
potential economic, environmental, public health and safety and other advantages; distributive
impacts; and equity) will be reached. EPA has chosen two regulatory options to be evaluated in
this RIA. For each of the two options, benefits and costs are quantified to the greatest extent
allowed by available data. As stipulated in E.O. 12866, in deciding whether and how to
regulate, EPA is required to assess all costs and benefits of available regulatory alternatives,
including the alternative of not regulating. Accordingly, the cost benefit analysis in this report is
measured against the baseline, which represents industry conditions in the absence of regulation.

1.2 LEGAL HISTORY AND STATUTORY AUTHORITY

The petroleum refinery NESHAP would require sources to achieve emission limits reflecting
the application of the maximum achievable control technology (MACT), consistent with
sections 112(d) and 112(h) of the CAA. This section provides a brief history of Section 112 of
the Act and background regarding the definition of source categories and emission points for
Section 112 standards.

Section 112 of the Act provides a list of 189 HAPs and directs the EPA to develop rules to
control HAP emissions. The CAA requires that the rules be established for categories of sources
of the emissions, rather than being set by pollutant. In addition, the CAA establishes specific
criteria for establishing a minimum level of control and criteria to be considered in evaluating
control options more stringent than the minimum control level. Assessment and control of any
remaining unacceptable health or environmental risk is to occur 8 years after the rules are
promulgated.

For the subject NESHAP, EPA chose regulatory options based on control options on an
emission point basis. The petroleum refinery NESHAP regulates emissions of all HAPs emitted
from all emission points at both new and existing petroleum refinery sources. An emission point
is defined as a point within a refinery which emits one or more HAPs. The emission points to be
regulated under the source category for this standard are: equipment leaks, storage vessels,
miscellaneous process vents, and wastewater collection and treatment systems.

1.3 REPORT ORGANIZATION

Chapter 2 presents a summary of the proposed regulation for the Petroleum Refinery
NESHAP. Executive Order 12866 requires EPA to prove that regulation is necessary due to a
compelling public need, such as material failures of private markets to protect or improve the
health and safety of the public, the environment, or the well-being of the public. In order to
satisfy this requirement, Chapter 3 presents the market conditions which necessitate regulatory
action. A characterization of the air emissions associated with the petroleum refining process,
and the significance of the environmental problem which EPA intends to address through
regulation are assessed. An explanation of how the regulation is consistent with the CAA is also
presented.

Chapter 4 identifies the control techniques and regulatory alternatives which were
considered for the standard. EPA's designation of control options reflects the best control
technology available to refineries, given existing technology levels. Chapter 5 presents the
approach for estimating regulatory compliance costs, the quantitative estimates of each control
option under analysis, and the issues and assumptions upon which the estimates were based.
The associated emission reductions and cost effectiveness of the regulatory options are also
presented.

Chapter 6 provides an economic profile of the petroleum refining industry, and describes the
methodology used to estimate the economic effects of a chosen hybrid option on the industry.
Predicted price, output, employment, and closure impacts are presented as well as a
quantification of the social costs of the regulatory option.

Chapter 7 provides a qualitative description of the benefits associated with the regulatory
action. As explained in this chapter, some benefits are nonquantifiable and therefore cannot be
usefully estimated. Qualitative measures of the air related benefits associated with a decrease in
HAP emissions are presented separately from those associated with a decrease in volatile organic
compound (VOC) emissions. Benefits which are difficult to quantify, but nevertheless essential to
consider, are also identified in this chapter.

Chapter 8 provides a quantitative assessment of those benefits which were identified in
Chapter 7. The methodology used to arrive at these estimates is outlined and any limitations are
identified. The quantitative estimates of benefits associated with risk reductions and human
health effects are presented separately.

The Executive Order requires EPA to assess both the costs and the benefits of the intended
regulation and, recognizing that some costs and benefits are difficult to quantify, adopt a
regulation only on a determination that the benefits of the regulation justify the costs. Chapter 9
compares the annualized costs to the annualized benefits for each of the two regulatory options
in this RIA. Economic efficiency is considered within the context of a welfare analysis, using the
social costs of regulation. 2.0 PROPOSED PETROLEUM REFINERIES EMISSION STANDARD
IN BRIEF

The discussion in this chapter briefly summarizes the requirements of the rule, without
accounting for how the provisions were selected or how emission cutoffs were determined. The
proposed rule, the NESHAP for petroleum refineries, would require sources to achieve emission
limits reflecting the application of MACT, consistent with sections 112(d) and 112(h) of the CAA.
The proposed rule would regulate the emissions of the organic HAPs identified on the list of
189 HAPs in the CAA at both new and existing petroleum refinery sources.

The proposed standard defines source as the collection of emission points in HAP-emitting
petroleum refining processes within the source category. The source comprises all miscellaneous
process vents, storage vessels, wastewater streams, and equipment leaks associated with
petroleum refining process units that are located at a single plant site covering a contiguous area
under common control. The definition of source is an important element of this NESHAP
because it describes the specific grouping of emission points within the source category to which
each standard applies.

2.1 THE EMISSION STANDARD IN BRIEF

The rule is made up of seven different subjects: applicability, definitions, and general
standards; miscellaneous process vent provisions; storage vessel provisions; wastewater
provisions; equipment leak provisions; recordkeeping and reporting provisions; and emissions
averaging. Each of these sections is summarized below.

2.1.1 Applicability of the Petroleum Refinery NESHAP

The applicability of the rule refers to the definition of the source within the petroleum
refinery source category. Petroleum refineries are defined as facilities engaged in producing
motor gasoline, naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel oils, or other
transportation fuels, heating fuels, or lubricants from crude oil or unfinished petroleum
derivatives. The emission standard applies to petroleum refining process units that are part of a
major source as defined in Section 112 of the CAA. EPA's initial source category list
(57 FR 31576, July 16, 1992), required by section 112(c) of the Act, identifies categories of
sources for which NESHAP are to be established. This list includes all categories of major
sources of HAPs known to the EPA at this time, and all area source categories for which findings
of adverse effects warranting regulation have been made. Two categories of sources are listed in
the initial source category list for petroleum refineries: (1) catalytic cracking (fluid and other)
units, catalytic reforming units, and sulfur plant units and (2) other sources not distinctly listed.

Based on an EPA review of information on petroleum refineries during development of the
proposed standards, it was determined that some of the emissions points from the two listed
categories of sources have similar characteristics and can be controlled by the same control
techniques. In particular, miscellaneous process vents emitting organic HAPs, storage vessels,
wastewater streams, and leaks from equipment in organic HAP service within catalytic cracking
units, catalytic reforming units, and sulfur plant units are similar to emission points from the other
process units at petroleum refineries. EPA determined that it is most effective to regulate these
emission points in a single regulation. (The EPA intends to amend the source category list when
the NESHAP under analysis is promulgated.) Upon revision, all emission points regulated by the
subject NESHAP will be in a single source category.

2.1.2 Miscellaneous Process Vent Provisions

Miscellaneous process vents are defined to include streams containing greater than 20 parts
per million by volume (ppmv) of organic HAP that are continuously or periodically discharged
from petroleum refining process units. This emission point excludes vents that are routed to the
refinery fuel gas system and vents from fluidized catalytic cracking unit (FCCU) catalyst
regeneration, catalytic reformer catalyst regeneration, and sulfur plants. The miscellaneous
process vent provisions require the owner or operator of a miscellaneous process vent to reduce
emissions of organic HAP by 98 percent or to 20 ppmv of HAP, or to reduce emissions using a
flare meeting the requirements of 63.11(b) of the NESHAP General Provisions (40 CFR 63
subpart A). Data analyses conducted in developing the MACT floor for miscellaneous process
vents determined that combustion controls can achieve 98 percent organic HAP reduction or an
outlet organic HAP concentration of 20 ppmv or less for all vent streams.

2.1.3 Storage Vessel Provisions

A storage vessel is defined as a tank or other vessel storing feed or product for a petroleum
refining process unit that contains organic HAPs. The storage vessel provisions do not apply to
the following: (1) vessels permanently attached to motor vehicles, (2) pressure vessels designed
to operate in excess of 204.9 kPa (29.7 psia), (3) vessels with capacities smaller than 40 m3
(10,500 gal), and (4) wastewater tanks. The storage provisions define two groups of vessels:
Group 1 vessels are vessels with a design storage capacity and a maximum true vapor pressure
above the specified values (see definitions section); Group 2 vessels are all vessels that are not
Group 1 vessels.

The proposed rule specifies the control systems to be applied to each of the two types of
storage vessels. The storage provisions require that one of the following control systems be
applied to Group 1 storage vessels: (1) an internal floating roof with proper seals; (2) an external
floating roof with proper seals; (3) an external floating roof converted to an internal floating roof
with proper seals; or (4) a closed vent system with a 95-percent efficient control device. Details
are provided in the proposed rule on the types of seals required. Vessels at new sources are also
required to meet specifications for fittings. Monitoring and compliance provisions for Group 1
vessels include periodic visual inspections of vessels and roof seals, as well as internal
inspections. No controls or inspections are required for Group 2 storage vessels.

2.1.4 Wastewater Provisions

The wastewater provisions of this rule are based on the benzene waste operations NESHAP
(BWON), using benzene as a surrogate for all HAPs from wastewater in petroleum refineries.
EPA research concluded that benzene is a good indicator of the presence of other HAPs. The
wastewater streams subject to this rule include water, raw material, intermediate product,
by-product, co-product, or waste material that contains HAPs and is discharged into an individual
drain system. The wastewater provisions define two groups of wastewater streams. Group 1
streams are those that contain a concentration of at least 10 parts per million in water (ppmw) of
benzene, have a flow rate of at least 0.02 liter per minute (lpm), are located at a refinery with a
total annual benzene loading of at least 10 megagrams per year and are not exempt from control
requirements under 40 CFR 61 subpart FF (the BWON). Group 2 streams are wastewater streams
that are not Group 1.

The wastewater provisions of the rule refer to the BWON, which requires owners or
operators of a Group 1 wastewater stream to reduce benzene mass by 99 percent using
suppression followed by steam stripping, biotreatment, or other treatment processes. The
performance tests required for wastewater streams and treatment operations to verify that the
control devices achieve the desired performance are included in the BWON, as are the
monitoring, reporting, and recordkeeping provisions necessary to demonstrate compliance. No
controls or monitoring are required for Group 2 wastewater streams.

2.1.5 Equipment Leak Provisions

The equipment leak standards for the petroleum refinery NESHAP refer to the negotiated
equipment leak regulation included in the Hazardous Organics NESHAP (HON) (40 CFR 63
subpart H). The standards for the petroleum refinery NESHAP differ from the HON in the
following ways: only one leak definition for pumps in phase III; leak definition for pumps is
equal to or greater than 2,000 ppmv; leak definitions for valves in phases II and III; monitoring
frequencies for valves; connectors are not required to be monitored, but sources may choose to
monitor valves less frequently in exchange for monitoring of connectors.

2.1.6 Recordkeeping and Reporting Provisions

The rule requires petroleum refineries to keep records of information necessary to document
compliance for five years and submit the following four types of reports to the Administrator:
(1) an initial notification, (2) a notification of compliance status, (3) periodic reports, and (4) other
reports. There are no requirements for reporting compliance with wastewater provisions other
than the reports already required by the BWON. The initial notification report must list the
petroleum refining process units that are subject to the rule. The notification of compliance
status report contains the information necessary to demonstrate that compliance has been
achieved. Periodic reports must include information required to be reported under the
recordkeeping and reporting provisions for each emission point. Other reports must be
submitted as required by the provisions for each kind of emission point, including requests for
extensions of time for repair of storage vessels and notifications of storage vessel inspections.

2.1.7 Emission Averaging

The EPA is proposing that emission averaging be allowed among existing miscellaneous
process vents, storage tanks, and wastewater streams within a refinery. EPA decided against
allowing equipment leaks to be included in emissions averaging because of the complexity and
cost of developing a scheme to include equipment leaks in emissions averaging and the
likelihood of a high compliance determination burden for both the industry and enforcement
agencies. Under emission averaging, a system of emission "credits" and "debits" would be used
to determine whether the source is achieving the required emission reductions. An owner or
operator who generates an emission debit must control other emission points to a level more
stringent than is required by the regulation to generate an emission credit. Annual emission
credits must exceed emission debits for a source to be in compliance. The rule would contain
specific equations and procedures for calculating credits and debits.
3.0 NEED FOR REGULATION

Section 3.1 presents the conditions of market failure which necessitate government
intervention. Section 3.2 identifies the insufficiency of political and judicial forces to control the
release of toxic air pollutants from petroleum refineries. Section 3.3 provides a characterization
of the HAP and VOC emissions from petroleum refineries. These values represent the baseline
against which the emission reductions associated with the regulatory options will be compared in
the cost effectiveness calculations presented in Chapter 5 of this report. Section 3.3 also
provides more detail on the health risks of these pollutants. Lastly, Section 3.4 identifies the
consequences of regulating versus the option of not regulating.

3.1 MARKET FAILURE

The U.S. Office of Management and Budget (OMB) directs regulatory agencies to
demonstrate the need for a major rule.1 The RIA must show that a market failure exists and that
it cannot be resolved by measures other than Federal regulation. Market failures are categorized
by OMB as externalities, natural monopolies, or inadequate information. The following
paragraphs address the three categories of market failure.

3.1.1 Air Pollution as an Externality

Air pollution is an example of a negative externality. This means that, in the absence of
government regulation, the decisions of generators of air pollution do not fully reflect the costs
associated with that pollution. For a petroleum refiner, air pollution from the refinery is a
product or by-product that can be disposed of cheaply by venting it to the atmosphere. Left to
their own devices, many refiners treat air as a free good and do not fully "internalize" the
damage caused by emissions. This damage is born by society, and the receptors þ the people
who are adversely affected by the pollution þ are not able to collect compensation to offset their
costs. They cannot collect compensation because the adverse effects, like increased risks of
morbidity and mortality, are non-market goods, that is, goods that are not explicitly and routinely
traded in organized free markets.

HAP emissions represent an externality in that refinery operation imposes costs on others
outside of the marketplace. In the case of this type of negative externality, the market price of
goods and services does not reflect the costs, borne by receptors of the HAPs, generated in the
refining process. Government regulation can be used to improve the situation. For example, the
NESHAP will force petroleum refiners to reduce the quantity of HAPs that they emit. With the
NESHAP in effect, the amount that refiners must incur to refine petroleum products will more
closely approximate the full social costs of production. In the long run, refiners will be forced to
increase prices of the petroleum products sold in order to cover total production costs. Thus,
prices will rise, consumers accordingly will reduce their demand for petroleum products, and as
a result, fewer petroleum products will be provided to the market. The more the costs of
pollution are internalized by the petroleum refiners, the greater the improvement in the way the
market functions.

3.1.2 Natural Monopoly

Natural monopoly exists where a market can be served at lowest cost only if production is
limited to a single producer. The refining industry is characterized by some of the same
attributes which define monopolistic markets, including economies of scale, and barriers to entry
due to the heavy up-front capital needed for refinery construction. Because of the wide diversity
in the size and number of petroleum refineries, however, conditions of natural monopoly do not
represent a market failure for this industry.

3.1.3 Inadequate Information

The third category of potential market failure that sometimes is used to justify government
regulation is inadequate information. Some petroleum refineries can reduce costs by installing
air pollution control devices, or reducing leaks. Due to lack of information, some of these
refineries do not install such systems. The NESHAP will require the collection of information
that may give a particular petroleum refiner enough data to make an informed decision on
whether or not control devices are the best option.

3.2 INSUFFICIENT POLITICAL AND JUDICIAL FORCES

There are a variety of reasons why many emission sources, in EPA's judgment, should be
subject to reasonably uniform national standards. The principal reasons are:

þ Air pollution crosses jurisdictional lines.

þ The people who breathe the air pollution travel freely, sometimes coming in contact
with air pollution outside their home jurisdiction.

þ Harmful effects of air pollution detract from the nation's health and welfare regardless of
whether the air pollution and harmful effects are localized.

þ Uniform national standards, unlike potentially piecemeal local standards, are not likely
to create artificial incentives or artificial disincentives for economic development in any
particular locality.

þ One uniform set of requirements and procedures can reduce paperwork and frustration
for firms that must comply with emission regulations across the country.

None of these reasons, by itself, provides overriding justification for Federal action in the
case at hand. Collectively, however, the reasons argue against reliance on State and local action
to control HAP emissions from petroleum refineries.

Citizens, as well as EPA, may sue State and local governments to force them to control HAP
emissions from petroleum refineries. Litigation under both the CAA and RCRA is possible.
However, EPA has not explored ways of improving the judicial route so that it might serve as a
substitute for action under Section 112 of the CAA.

3.3 ENVIRONMENTAL FACTORS WHICH NECESSITATE REGULATION

Regulation of the petroleum refining industry is necessary because of the adverse health
effects caused by human exposure to HAP emissions. This section characterizes the emissions
attributable to petroleum refining and summarizes the adverse health effects associated with
human exposure to HAP emissions.

3.3.1 Air Emission Characterization

The HAP emissions from the emission points that comprise the source in this source category
are all organic HAPs. Therefore, given the source and source category definitions, the provisions
of this NESHAP apply to organic HAPs listed in section 112(b) of the CAA. HAP emissions from
refineries are composed of a few chemicals, including benzene, toluene, xylenes, ethylbenzene,
and hexane. There is a narrower range of variation in emission stream composition among
petroleum refinery emission points than there is in some other source categories (e.g., Synthetic
Organic Chemical Manufacturing Industry (SOCMI) emission points regulated by the HON).
However, the different HAPs emitted have different toxicities, and there are some variations in
the concentrations of individual HAPs and the emission release characteristics of different
emission points.

Baseline emissions from petroleum refineries were estimated using information published in
the Oil and Gas Journal (OGJ) and provided by petroleum refineries in response to information
collection requests and questionnaires sent out under section 114 of the CAA. Table 3-1
presents the baseline HAP and VOC emissions for each of the four kinds of emission points
controlled by this proposed rule. Emission levels of other air pollutants (CO, NOx, and SO2)
were not quantified. Baseline emissions include emissions from both new and existing sources.
Baseline HAP and VOC emissions take into account the current estimated level of emissions
control, based on questionnaire responses submitted by refineries, and on related regulations
which have already been promulgated. (These regulations are summarized later in this chapter.)
As a result, baseline HAP and VOC emissions reflect the level of control that would be achieved
in the absence of the proposed rule.

TABLE 3-1. NATIONAL BASELINE VOC AND HAP EMISSIONS BY EMISSION POINT

Baseline Emissions (Mg/yr)Emission PointHAPVOCMiscellaneous Process Vents9,800190,000Equipment Leaks52,000190,000Storage Vessels9,300111,000Wastewater Collection and Treatment10,00010,000TOTAL81,100501,000

Given available data, it has not been possible to identify individual HAP emissions for each
type of emission point. Speciated HAP emissions were available only for equipment leaks.
Since HAP emissions from equipment leaks account for nearly 65 percent of total HAP emissions
at petroleum refineries, however, this speciation is valuable for approximating the minimum level
of cancer risk related to refinery emissions. Speciated HAP emissions for equipment leaks are
presented in Table 3-2.

3.3.2 Harmful Effects of HAPs

Exposure to HAPs has been associated with a variety of adverse health effects. Direct
exposure to HAPs can occur through inhalation, soil ingestion, the food chain, and dermal
contact. Only health effects associated with HAP emissions are addressed in these NESHAPs.
Many HAPs are classified as known human carcinogens. Other HAPs have not been classified as
known human carcinogens. Exposure to these pollutants, however, may still result in adverse
health and welfare impacts to human populations.TABLE 3-2. BASELINE SPECIATED HAP EMISSIONS FROM EQUIPMENT LEAKS

Hazardous Air PollutantBaseline Emissions
(Mg/yr)2, 2, 4-Trimethylpentane5,660Benzene1,904Ethyl Benzene2,377Hexane5,486Naphthalene1,539Toluene8,049Xylenes7,597Hydrogen Fluoride2,764Phenol1,243Cresols603MTBE5,840Hydrogen Chloride199Methyl Ethyl Ketone2,117TOTAL45,380

EPA has devised a system, which was adapted from one developed by the International
Agency for Research on Cancer (IARC), for classifying chemicals based on the weight-of-
evidence.2 Of the HAPs listed in Table 3-2, only benzene is classified as group A, or a known
human carcinogen. This means that there is sufficient evidence to support that the chemical
causes an increased risk of cancer in humans. Benzene is a concern to the EPA because long
term exposure to this chemical has been known to cause leukemia in humans. While this is the
most well known effect, benzene exposure is also associated with aplastic anemia, multiple
myeloma, lymphomas, pancytopenia, chromosomal breakages, and weakening of bone marrow
(53 FR 28504; July 28, 1988).

Cresols and naphthalene are considered to be group C or possible human carcinogens. For
these chemicals, there is either inadequate data or no data on human carcinogenicity, and there
is limited data on animal carcinogenicity. Therefore, while cancer risk is possible, there is not
sufficient evidence to support that these chemicals will cause increased cancer risks in humans.
The remaining HAPs in Table 3-2 are noncarcinogens. Though they do not cause cancer, they
are considered hazardous because of the other significant adverse health effects with which they
are associated.

Emissions of VOC have been associated with a variety of health impacts. VOCs, together
with NOx, are precursors to the formation of tropospheric ozone. It is exposure to ozone that is
responsible for adverse respiratory impacts, including coughing and difficulty in breathing.
Repeated exposure to elevated concentrations of ozone over long periods of time may also lead
to chronic, structural damage to the lungs.

3.4 CONSEQUENCES OF REGULATORY ACTION

This section provides a preliminary assessment of the consequences of the attainment of EPA
emission reduction objectives, and the likely consequences if these objectives are not met.

3.4.1 Consequences if EPA's Emission Reduction Objectives are Met

This section presents the environmental, cost, and energy use impacts resulting from the
control of HAP emissions under the proposed rule. (Economic impacts will be presented in
Chapter 6.) It is estimated that approximately 192 petroleum refineries would be required to
apply controls by the proposed standards. Throughout this report, impacts are presented relative
to the baseline, which represents the level of control in the absence of the proposed rule. The
estimates include the impacts of applying control to: (1) existing process units and (2) additional
process units that are expected to begin operation over a 5-year period. Thus, the estimates
represent annual impacts occurring in the fifth year. Based on a review of annual construction
projects over the years 1988 to 1992 listed in the Oil and Gas Journal, it was assumed that
34 new process units would be constructed each year over a 5-year period.

3.4.1.1 Allocation of Resources. There will be improved allocation of resources associated
with petroleum refining. Specifically, more of the costs of the harmful effects of the refining
process will be internalized by the producers. This, in turn, will affect consumers' purchasing
decisions. To the extent these newly-internalized costs are then passed along to the end users of
refined petroleum products, and to the extent that these end users are free to buy as much or as
little of the petroleum products as they wish, they will purchase less (relative to their purchases
of other competing services). If this same process of internalizing negative externalities occurs
throughout the entire petroleum refining industry, an economically optimal situation is
approached. This is the situation in which the marginal cost of resources devoted to petroleum
refining equals the marginal value of the products to the end users of the products. Although
there are uncertainties in this progression of impacts, in the aggregate and in the long run, the
NESHAP will move society toward this economically optimal situation.

3.4.1.2 Emissions Reductions. The environmental impact of the rule includes the reduction
of HAP and VOC emissions. Under the proposed rule, it is estimated that the emissions of HAP
from refineries would be reduced by 53,000 Mg/yr, and the emissions of VOC would be reduced
by 350,000 Mg/yr. Emission levels of other air pollutants (CO, NOx, and SO2) were not
quantified. It is important to note that the possibility exists for slight increases above existing
emission levels would result from the combustion of fossil fuel as part of control device
operations. Additional emissions of these pollutants would be attributable to the additional fuel
burned to generate energy for operation of compressors for ducting miscellaneous process vent
streams to control devices.

3.4.1.3 Costs and Benefits. The cost impact of the rule includes the capital cost of new
control equipment, and the associated operation and maintenance cost. Generally, the cost
impact also includes any cost savings generated by reducing the loss of valuable product in the
form of emissions. Under the proposed rule, it is estimated that total capital costs would be
$188 million (first quarter 1992 dollars) and total annual costs would be $81 million (first
quarter 1992 dollars). Table 3-3 presents the capital and annual cost impact of the regulation for
each of the four emission points as well as the national totals.

TABLE 3-3. NATIONAL CONTROL COST IMPACTS OF PREFERRED ALTERNATIVE IN THE
FIFTH YEAR

Emission PointTotal Capital Costs
(Million Dollars)Total Annual Costs
(Million Dollars)Miscellaneous Process Vents$ 31.0$ 11.4Equipment Leaks$ 130.0$ 65.8Storage Vessels$ 27.0$ 3.8Wastewater Collection and TreatmentbbTOTAL$ 188.0$ 81.0
NOTES: bThe MACT level of control is no additional control.

3.4.1.4 Energy Impacts. Increases in energy use were estimated for operating control
equipment that would be required by the proposed standards (compressors for ducting
miscellaneous process vent streams to control devices). The estimated energy use increase in the
fifth year would be 13 million kw-hr/yr of electricity or 10 barrels of oil equivalent.3

3.4.1.5 State Regulation and New Source Review. State regulatory programs will be
strengthened. Some components of the petroleum refining industry have already been subject to
various Federal, State, and local air pollution control rules. Although these existing rules will
remain in effect, the petroleum refinery NESHAP will provide comprehensive coverage of the
petroleum refinery sources not covered by the existing rules. Recognition that the NESHAP is
effectively reducing emissions will expedite the State process of reviewing applications for new
petroleum refineries and issuing permits for their construction and operation. State regulations
will also be uniform, and the disadvantages of the piecemeal approach to emission regulation
will be avoided.

3.4.1.6Other Federal Programs. The regulations which affect the petroleum refining
industry which have already been promulgated include a number of NSPS, (40 CFR 60):
subpart J þ Standards of Performance for Petroleum Refineries; subparts K, Ka, and Kb þ various
standards of performance for storage vessels for petroleum liquids; subpart GGG þ Standards of
Performance for Equipment Leaks of VOC in Petroleum Refineries, and the Standards of
Performance for VOC Emissions from Petroleum Refinery Wastewater Systems. The regulations
that have already been promulgated also include a number of NESHAPs, (40 CFR 61): subpart J
þ NESHAP for Equipment Leaks (Fugitive Emission Sources) of Benzene; subpart Y þ NESHAP for
Benzene Emissions from Benzene Storage Vessels; and subpart FF þ NESHAP for Benzene Waste
Operations (BWON).

This petroleum refinery NESHAP generally covers refinery processes that produce petroleum
liquids (such as motor gasoline, naphthas, and kerosene) for use as fuels. Often, products of
refinery processes are used to make synthetic organic chemicals other than fuels. The petroleum
refinery NESHAP will not cover chemical manufacturing process units that are covered under the
SOCMI source category, even if these units are located at a refinery site. A SOCMI chemical
manufacturing process unit that is located at a refinery and produces one or more of the
chemicals listed in the HON (40 CFR 63 subpart F, table 1) as a single chemical product or as a
mixed chemical used to produce other chemicals would be considered a SOCMI process and
would be subject to the HON rather than to the petroleum refinery NESHAP.

3.4.2 Consequences if EPA's Emission Reduction Objectives are Not Met

The most obvious consequence of failure to meet EPA's emission reduction objectives would
be emissions reductions and benefits that are not as large as is projected in this report. However,
costs are not likely to be as large either. Whether it is noncompliance from ignorance or error,
or from willful intent, or simply slow compliance due to owners and/or operators exercising legal
delays, poor compliance can save some refineries money. Unless States respond by allocating
more resources into enforcement, then poor compliance could bring with it smaller aggregate
nationwide control costs. EPA has not included an allowance for poor compliance in its
estimates of emissions reductions, due to the fact that poor compliance is unlikely. Also, if the
emission control devices degraded rapidly over time or in some other way did not function as
expected, there could be a misallocation of resources. This situation is very unlikely, given that
the NESHAP is based on demonstrated technology.
REFERENCES

1. U.S. Office of Management and Budget. Regulatory Impact Guidance. Appendix V of
Regulatory Program of the United States Government. April 1, 1991 þ March 31, 1992.

2. U.S. Environmental Protection Agency. The Risk Assessment Guidelines of 1986. Office of
Health and Environmental Assessment. Washington, DC. August 1987.

3. U.S. Environmental Protection Agency. National Emission Standards for Hazardous Air
Pollutants for Source Categories: Petroleum Refineries. Proposed Rule and Notice of Public
Hearing. Draft. Section IV. February 1994.
4.0 CONTROL TECHNIQUES AND REGULATORY ALTERNATIVES

The proposed regulation would require a broad range of control techniques as options for
compliance with the standard. Combustion technology, internal floating roofs, and product
recovery devices, including internal floating roofs and vapor recovery tanks, are all part of the
technology requirements for the Petroleum Refinery NESHAP. Leak detection and repair (LDAR)
programs will be used to control equipment leaks. This chapter does not attempt to be
comprehensive in explaining the technology and techniques used to control air toxics emissions
under this proposed regulation; it does attempt to survey what technologies and techniques are
being used and how effective they are.

Petroleum refineries differ in the number, combination, and design of their process units; the
production capacities of their refining processes; the type and characteristics of crude oil they
use; and the control equipment they use. Consequently, actual emissions and characteristics of
petroleum refinery facilities vary widely from refinery to refinery. This diversity affected the
approach used to define the MACT floor for existing and new sources.

This chapter briefly explains the control technologies which are available to refineries to
comply with the proposed regulation. At the end of this chapter, a summary of the two
regulatory alternatives is provided.

4.1 CONTROL TECHNIQUES

This section presents a summary of the control equipment available for combustion
technology, product recovery devices, LDAR programs, and internal floating roofs. Each type of
control is presented separately.

4.1.1 Combustion Technology

Combustion control devices, unlike noncombustion control devices, alter the chemical
structure of the VOC. Destruction of the VOC by combustion is complete if all VOCs are
converted to CO2 and water. Incomplete combustion results in some of the VOC remaining
unaltered or being converted to other organic compounds such as aldehydes or acids. If
chlorinated or sulfur-containing compounds are present in the mixture, the products of complete
combustion include the acid components HCl or SO2, respectively, in addition to water and
carbon dioxide. Available combustion technology options include incinerators, flares, and
boilers and process heaters. The process and applicability of each control type are summarized
in the following sections.

4.1.1.1 Incinerators. Incineration is one of the best known methods of industrial gas waste
disposal. It is a method of ultimate disposal, that is, the constituents to be controlled in the
waste gas stream are converted rather than collected. Provided proper engineering design is
used, incineration can eliminate the desired organic chemicals in a gas stream safely and cleanly.

The heart of an incinerator is a combustion chamber in which the VOC-containing waste
stream is burned. The temperature required for combustion is much higher than the temperature
of the inlet gas, so energy is usually supplied to the incinerator to raise the waste gas
temperature. This is accomplished by adding auxiliary fuel (usually natural gas).

The amount of auxiliary fuel required can be decreased and energy efficiency increased by
providing heat exchange between the inlet stream and the effluent stream. The effluent stream
containing the products of combustion, along with any inerts that may have been present in or
added to the inlet stream, can be used to preheat the incoming waste stream, auxiliary air, or
both via a "primary", or recuperative, heat exchanger.

Auxiliary air may be required for combustion if the requisite oxygen is not available in the
inlet gas stream. Most industrial gases that contain VOCs are dilute mixtures of combustible
gases in air. During the air oxidation reactor and distillation processes, the waste gas stream is
deficient in air.

Important in the design and operation of incinerators is the concentration of combustible gas
in the waste gas stream. Having a large amount of excess air (i.e., in excess of the required
stoichiometric amounts) may be costly, but any mixture within the flammability limits, on either
the fuel-rich or fuel-lean side of the stoichiometric mixture, is considered a fire hazard as a feed
stream to the incinerator. Therefore, some waste gas streams are diluted with air before
incineration, even though this requires more fuel in the incinerator. There are two types of
incinerators: thermal and catalytic. While much of what was discussed above applies to both,
there are important differences in their design and operation.

4.1.1.1.1 Thermal Incinerators. As is true of other combustion control devices, thermal
incinerators operate on the principle that any VOC heated to a high enough temperature in the
presence of sufficient oxygen will be oxidized to CO2 and water. The theoretical temperature
for thermal oxidation depends on the properties of the VOC to be combusted. There is great
variation in theoretical combustion temperatures among different VOCs.

There are three requirements that must be met for a thermal incinerator to be considered
efficient: 1) a high enough temperature within the combustion chamber to enable oxidation of
the organic compounds to proceed rapidly to completion; 2) enough turbulence for good mixing
of the hot combustion products from the burner, the combustion air, and the organic
compounds; and 3) sufficient residence time for oxidation to reach completion.

A typical thermal incinerator is a refractory-lined chamber containing a burner or set of
burners at one end. Entering gases are mixed with the process vent streams and the inlet air in a
premixing chamber. Then the stream of gases passes into the main combustion chamber. This
chamber is designed to allow the mixture enough time at the required combustion temperature
for complete oxidation (usually from 0.3 to 1.0 second). A heat recovery section is often added
to increase energy efficiency. Often, inlet combustion air is preheated; if this occurs, insurance
regulations require the VOC concentration must be maintained below 25 percent of the lower
explosive limit (LEL) to minimize the possibility of explosions. Concentrations from 25 to 50
percent are permitted given continuous monitoring by LEL monitors.

The required level of VOC control of the waste gas that must be achieved within the time it
spends in the thermal combustion chamber dictates the reactor temperature. The shorter the
residence time, the higher the reactor temperature must be. Once the unit is designed and built,
the residence time is not easily changed, so that the required reaction temperature becomes a
function of the particular gaseous species and the desired level of control. These required
combustion reaction temperatures cannot be calculated a priori, although incinerator vendors can
provide guidelines based on their extensive experience. Predictions of these temperatures are
further complicated by the fact that most process vent streams are mixtures of compounds.

Good mixing is also important, particularly in determining destruction efficiency. Even
though it cannot be measured, mixing is a factor of equal or even greater importance than other
parameters such as temperature. The most feasible and efficient way to improve the mixing in
an incinerator is to adjust it after start-up.

Other parameters affecting thermal incinerator performance are the heat content of the vent
stream, the water content of the stream, and the amount of excess combustion air (the amount of
air above the stoichiometric air needed for combustion). Combustion of a vent stream with a
heat content less than 1.9 MJ/m3 (52 BTU/scf) usually requires burning supplemental fuel to
maintain the desired combustion temperature.

The maximum achievable VOC destruction efficiency decreases with decreasing inlet VOC
concentration because combustion is slower at lower inlet concentrations. Therefore, a VOC
weight percentage reduction based on the mass rate of VOC exiting the control device versus the
mass rate of VOC entering the device is appropriate for vent streams with VOC concentrations
above approximately 2,000 ppmv (which corresponds to 1,000 ppmv VOC in the incinerator
inlet stream since air dilution is typically 1:1).

Thermal incinerators are technically feasible control devices for most vent streams. They are
not recommended, however, for vent streams with potentially excessive fluctuations in flow rate
(process upsets, for example), and for vent streams containing halogens. The former case would
require a flare (see Section 4.1.1.2) and the latter case would require additional equipment such
as acid gas scrubbers (see Section 4.1.2).

4.1.1.1.2 Types of Thermal Incinerators. The very simplest type of thermal incinerator
is the direct flame incinerator, which is made up of only the combustion chamber. Energy
recovery devices such as a waste gas preheater and a heat exchanger are not included with this
type of incinerator.

A second type of thermal incinerator is the recuperative model. Recuperative incinerators
use the exit (product) gas to preheat the incoming feed stream, combustion air, or both via a heat
exchanger. These heat exchangers can recover up to 70 percent of the energy (or enthalpy) in
the product gas. The two types of heat exchangers commonly used for this purpose and many
others are plate-to-plate and shell-and-tube. Plate-to-plate exchangers can be built to achieve a
variety of efficiencies and offer high efficiency energy recovery at lower cost than shell-and-tube
designs. But when gas temperatures exceed 520 degrees Celsius, shell-and-tube exchangers
usually have lower purchase costs than plate-to-plate designs. Moreover, shell-and-tube
exchangers offer better long-term structural reliability than plate-to-plate units.

Occasionally it is desired to recover some of the energy added by auxiliary fuel in the
traditional thermal units (but not recovered in preheating the feed stream). Additional heat
exchangers can be added to provide process heat in the form of low pressure steam or hot water
for on-site application. The need for this higher level of energy recovery will be dependent upon
the plant site. The additional heat exchanger is often provided by the incineration unit vendor.

A third type of thermal incinerator is the regenerative incinerator. This type of incinerator
uses direct contact heat exchangers constructed of a ceramic material that can tolerate the high
temperatures needed to achieve ignition of the waste stream. The concept behind this
incinerator type is that the traditional approach to energy recovery in thermal units still requires a
significant amount of auxiliary fuel to be burned in the combustion chamber when waste gas
heating values are too low to sustain the desired reaction temperature at the moderate preheat
temperature employed. Under these conditions, additional fuel savings can be realized in units
with more complete transfer of exit stream energy. The regenerative incinerator serves this
purpose.

In this type of incinerator, the inlet gas first passes through a hot ceramic bed thereby
heating the steam to its ignition temperature. After the hot gases react and release energy in the
combustion chamber, the gases pass through another ceramic bed, thereby heating it to the
levels of the combustion chamber outlet temperature. The process flows are then switched, now
feeding the inlet stream to the hot bed. This cyclic process affords very high energy recovery (up
to 95 percent).

4.1.1.1.3 Catalytic Incinerators. A catalyst promotes oxidation of some VOCs at a
lower temperature than that required for thermal incineration. The catalyst increases the rate of
the chemical reaction without becoming permanently altered itself. Catalysts typically used for
VOC incineration include platinum and palladium. These catalysts work well for most organic
streams, but are not tolerant of compounds containing halogens such as chlorine and sulfur.
Among the catalysts that have been developed that are effective in the presence of these
halogens are chromia/alumina, cobalt oxide, and copper oxide/manganese oxide. Inert substrates
are coated with thin layers of these materials to provide maximum surface area for contact with
the VOC in the vent stream. Compounds containing elements such as lead, arsenic, and
phosphorus should, in general, be considered poisons for most oxidation catalysts. In addition,
particulate matter, including dissolved minerals in aerosols, can rapidly blind (deactivate) the
pores of catalysts and deactivate them over time. Because essentially all the active surface of the
catalyst is contained in relatively small pores, the particulate matter need not be large to blind
the catalyst.

For optimal operation, the volumetric gas flow rate and the concentration of combustibles (in
this case, VOCs) should be constant. Large fluctuations in the flow rate will cause the
conversion of the VOCs to fluctuate also. Changes in the concentration or type of organic
compounds in the gas stream can also affect the overall conversion of the VOC contaminants.
Most changes in flow rate, organic concentration, and chemical composition are generally the
result of upsets in the manufacturing process generating the waste gas stream.

Applicability of catalytic incinerators for control of VOCs is limited by the catalyst
deactivation sensitivity to the characteristics of the inlet gas stream. The vent stream to be
combusted should not contain materials that can poison the catalyst or deposit on and block the
reactive sites on the catalyst surface. In addition, catalytic incinerators are unable to handle high
inlet concentrations of VOC or very high flow rates. Catalytic incineration is generally useful for
concentrations of 50 to 10,000 ppmv, if the total concentration is less than 25 percent of the LEL
and for flow rates of less than 2,820 m3/min (100,000 scfm).

4.1.1.1.4 Types of Catalytic Incinerators. One type of catalytic incinerator is fixed-bed.
Fixed-bed incinerators come in two varieties, depending on the type of catalyst used: the
monolith and packed-bed. The monolith catalyst is the most widespread method of contacting
the VOC-containing stream with the catalyst. In this scheme, the catalyst is a porous solid block
containing parallel, non-intersecting channels aligned in the direction of the gas flow. Monolith
catalysts offer the advantages of minimal attrition due to thermal expansion/contraction during
startup/shutdown and low overall pressure drop.

A second contacting scheme is a simple packed-bed in which catalyst particles are supported
either in a tube or in shallow trays through which the gases pass. The tray type arrangement is
the more common packed-bed scheme due to the use of pelletized catalysts. This tray
arrangement is preferred because pelletized catalysts can handle inlet streams containing
contaminants such as phosphorus or silicon. The tube arrangement is not used widely due to its
inherently high pressure drop compared with a monolith, and the breaking of catalyst particles
due to thermal expansion when the confined catalyst bed is heated/cooled during
startup/shutdown.

A third contacting pattern between the gas and catalyst is a fluid-bed. Fluid-beds have the
advantage of very high mass transfer rates, although the overall pressure drop is somewhat higher
than for a monolith. Fluid-beds also possess the advantage of high bed-side heat transfer
compared with a normal gas heat transfer coefficient. This higher heat transfer rate to heat
transfer tubes immersed in the bed allows higher heat release rates per unit volume of gas
processed and therefore may allow waste gases with higher heating values to be processed
without exceeding maximum permissible temperatures in the catalyst bed. The catalyst
temperatures depend on the rate of reaction occurring at the catalyst surface and the rate of heat
exchange between the catalyst and imbedded heat transfer surfaces.

In general, fluid-bed systems are more tolerant of particulates in the gas stream than fixed-
bed or packed-bed systems. This results from the constant abrasion of the fluidized catalyst
pellets, which helps remove these particulates from the exterior of the catalysts in a continuous
manner.

4.1.1.2 Flares. Flaring is an open combustion process in which the oxygen necessary for
combustion is provided by the air around the flame. The organic compounds to be combusted
are piped to a remote, usually elevated, location and burned in an open flame in the open air
using a specially designed burner tip, auxiliary fuel, and sometimes steam or air to promote
mixing for nearly complete (98 percent minimum) destruction of combustibles. Good
combustion in a flare is governed by flame temperature, residence time of organic species in the
combustion zone, turbulent mixing of the organic species to complete the oxidation reaction,
and the amount of oxygen available for free radical formation. Combustion is complete if all
combustibles (i.e., VOCs) are converted to CO2 and water, while incomplete combustion results
in some of the VOCs being unaltered or converted to other organic compounds such as
aldehydes or acids.

Flares are generally categorized in two ways: 1) by the height of the flare tip (i.e., ground-
level or elevated), and 2) by the method of enhancing mixing at the flare tip (i.e., steam-assisted,
air-assisted, pressure-assisted, or unassisted). Elevating the flare can prevent potentially
dangerous conditions at ground level where the open flame is located near a process unit.
Further, the products of combustion can be dispersed above working areas to reduce the effects
of noise, heat radiation, smoke, and objectionable odors.

In most flares, combustion occurs by means of a diffusion flame. A diffusion flame is one in
which air diffuses across the boundary of the fuel/combustion product stream toward the center
of the fuel flow, forming the envelope of a combustible gas mixture around a core of fuel gas.
This mixture, on ignition, establishes a stable flame zone around the gas core above the burner
tip. This inner gas core is heated by diffusion of hot combustion products from the flame zone.

Cracking can occur with the formation of small hot particles of carbon that give the flame its
characteristic luminosity. If there is an oxygen deficiency and if the carbon particles are cooled
to below their ignition temperature, smoking occurs. In large diffusion flames, combustion
product vortices can form around burning portions of the gas and shut off the supply of oxygen.
This localized instability causes flame flickering, which can be accompanied by soot formation.

Flares can be dedicated to almost any VOC stream, and can handle fluctuations in VOC
concentration, flow rate, heating value, and inerts content. Flaring is appropriate for continuous,
batch, and variable flow vent stream applications.

Some streams, such as those containing halogenated or sulfur-containing compounds, are
usually not flared because they corrode the flare tip or cause formation of secondary pollutants
(such as acid gases or sulfur dioxide). If these vent types are to be controlled by combustion,
thermal incineration, followed by scrubbing to remove the acid gases, is the preferred method.

The majority of refineries have existing flare systems designed to relieve emergency process
upsets that might contain large gas volumes. Often, large diameter flares designed to handle
emergency releases are also used to control continuous vent streams from various process
operations. Typically in refineries, many vent streams are combined in a common gas header to
fuel boilers and process heaters. However, excess gases, fluctuations in flow rate in the fuel gas
line, and emergency releases are sometimes sent to a flare. Five factors affecting flare
combustion efficiency are vent gas flammability, auto-ignition temperature, heat content of the
vent stream, density, and flame zone mixing.

The flammability limits of the vent stream influence ignition stability and flame extinction.
Flammability limits are the stoichiometric composition limits (maximum and minimum) of an
oxygen-fuel mixture that will burn indefinitely at given conditions of temperature and pressure
without further ignition. In other words, gases must be within their flammability limits to burn.
If these limits are narrow, the interior of the flame may have insufficient air for the mixture to
burn. Fuels, such as hydrogen, with wide limits of flammability are therefore easier to combust.

The auto-ignition temperature of a vent stream affects combustion because gas mixtures must
be at a sufficient temperature and concentration to burn. A gas with a low auto-ignition
temperature will ignite more easily than a gas with a high auto-ignition temperature.

The heat content of the vent stream is a measure of the heat available from the combustion
of the VOC in the vent stream. The heat content of the vent stream affects the flame structure
and stability. A gas with a lower heat content produces a cooler flame that does not favor
combustion kinetics and is more easily extinguished. The lower flame temperature will also
reduce buoyant forces, which reduces mixing.

The density of the vent stream also affects the structure and stability of the flame through the
effect on buoyancy and mixing. By design, the velocity in many flares is very low; therefore,
most of the flame structure is developed through buoyant forces as a result of combustion.
Lighter gases therefore tend to burn better. In addition to burner tip design, the density also
affects the minimum purge gas required to prevent flashback, with lighter gases requiring more
purge.

Poor mixing at the flare tip or poor flare maintenance can cause smoking (particulate matter
release). Vent streams with high carbon-to-hydrogen ratios (> 0.35) have a greater tendency to
smoke and require better mixing to burn smokelessly. For this reason, one generic steam-to-vent-
stream ratio is not appropriate for all vent streams. The steam required depends on the vent
stream carbon-to-hydrogen ratio. A high ratio requires more steam to prevent a smoking flare.

The efficiency of a flare in reducing VOC emissions can be variable. For example, smoking
flares are far less efficient than properly operated and maintained flares. Flares have been shown
to have high VOC destruction efficiencies, under proper operating conditions. Up to 99.7
percent combustion efficiency can be achieved.

4.1.1.2.1 Steam-Assisted Flares. Steam-assisted flares are single burner tips, elevated
above ground level for safety reasons, that burn the vented gas in essentially a diffusion flame.
They reportedly account for the majority of the flames installed and are the predominant flare
type found in refineries. To ensure an adequate air supply and good mixing, this type of flare
system injects steam into the combustion zone to promote turbulence for mixing and to induce
air into the flame.

4.1.1.2.2 Air-Assisted Flares. Air-assisted flares use forced air to provide the
combustion air and the mixing required for smokeless operation. These flares are built with a
spider-shaped burner (with many small gas orifices) located inside but near the top of a steel
cylinder two feet or more in diameter. Combustion air is provided by a fan in the bottom of the
cylinder, and the amount of combustion air can be varied by changing the fan speed. The
primary advantage air-assisted flares provide is that they can be used without steam.

4.1.1.2.3 Non-Assisted Flares. The non-assisted flare is just a flare tip without any
auxiliary provision for enhancing the mixing of air into its flame. Its use is limited essentially to
gas streams that have a low heat content and a low carbon/hydrogen ratio that burn readily
without producing smoke. These streams require less air for complete combustion, have lower
combustion temperatures that minimize cracking reactions, and are more resistant to cracking.

4.1.1.2.4 Pressure-Assisted Flares. This type of flare uses vent stream pressure to
promote mixing at the burner tip. If sufficient vent stream pressure is available, these flares can
be applied to streams previously requiring steam or air assist for smokeless operation. Pressure-
assisted flares generally have the burner arrangement at ground level, and consequently, must be
located in a remote area of the plant where there is plenty of space available. They have
multiple burner heads that are staged to operate based on the quantity of gas being released.
The size, design, number, and group arrangement of the burner heads depend on the vent gas
characteristics.

4.1.1.2.5 Enclosed Ground Flares. The burner heads of an enclosed flare are inside an
insulated shell. This shell reduces noise, luminosity, and heat radiation and provides wind
protection. A high nozzle pressure drop is usually adequate to provide the mixing necessary for
smokeless operation and air or steam assist is not required. In this context, enclosed flares can
be considered a special class of pressure-assisted or non-assisted flares. Enclosed flares are
always at ground level.

Enclosed flares generally have less capacity than open flares and are used to combust
continuous, constant flow vent streams, although reliable and efficient operation can be attained
over a wide range of design capacity. Stable combustion can be obtained with lower heat
content vent gases than is possible with open flare designs, probably due to their isolation from
wind effects.

4.1.1.3 Boilers and Process Heaters. Industrial boilers are combustion units that boil water
to produce high and low pressure steam. Industrial boilers can also combust various vent
streams containing VOCs, including vent streams from distillation operations, reactor processes,
and other general operations. The majority of industrial boilers used in the refining industry are
of watertube design, and over half of these boilers use natural gas as a fuel. In a watertube
boiler, hot combustion gases contact the outside of heat transfer tubes which contain hot water
and steam. These tubes are interconnected by a set of drums that collect and store the heated
water and steam. Energy transfer from the hot flue gases to the water in the furnace watertube
and drum system can be better than 85 percent efficient. Additional energy can be recovered
from the flue gas by preheating combustion air in an air preheater or by preheating incoming
boiler feed water in an economizer unit.

When firing natural gas, forced- or natural-draft burners thoroughly mix the incoming fuel
and combustion air. A VOC-containing vent stream can be added to this mixture or it can be fed
into the boiler through a separate burner. In general, burner design depends on the
characteristics of the fuel þ either the combined VOC-containing vent stream and fuel, or the
vent stream alone (when a separate burner is used).

A process heater is similar to an industrial boiler in that heat liberated by the combustion of
fuels is transferred by radiation and convection to fluids contained in tubular coils. It is different
from an industrial boiler in that process heaters raise the temperature of process streams instead
of producing high temperature steam. Process heaters are used in many chemical manufacturing
operations to drive endothermic reactions. They are also used as feed preheaters and as reboilers
for some distillation operations. The fuels used in process heaters include natural gas, refinery
offgases, and various grades of fuel oil.

A typical process heater design consists of the burner(s), the firebox, and a row of tubular
coils containing the process fluid. Most heaters also contain a convective section in which heat
is recovered from hot combustion gases by convective heat transfer to the process fluid.

4.1.1.3.1 Efficiency of Boilers and Process Heaters. Average furnace temperature and
residence time determine the combustion efficiency of boilers and process heaters, just as they
do for incinerators. When a vent gas is injected as a fuel into the flame zone of a boiler or
process heater, the required residence time is reduced because of the relatively high temperature
and turbulence of the flame zone.

Residence time and temperature profiles in boilers and process heaters are determined by
factors such as overall configuration, fuel type, heat input, and excess air level. A mathematical
model developed to estimate furnace residence time and temperature profiles for a variety of
industrial boilers predicts mean furnace residence times ranging 0.25 to 0.83 second for natural
gas-fired watertube boilers that range in size from 4.4 to 44 MW (15 to 150 x 106 Btu/hr).
Boilers with a 44-MW capacity or greater generally have residence times and operating
temperatures that would ensure a 98 percent VOC destruction efficiency. The required
temperatures for these size boilers are at least 1,200 degrees Celsius.

Firebox temperatures for process heaters can show wide variations depending on the
application. Firebox temperatures can range from 400 degrees Celsius for preheaters and
reboilers to 1,260 degrees Celsius for pyrolysis furnaces. Tests conducted by EPA on process
heaters using a mixture of benzene offgas and natural gas showed greater than 98 percent
destruction efficiency for C1 to C6 hydrocarbons.

4.1.1.3.2 Applicability of Boilers and Process Heaters. Both of these devices are used
throughout petroleum refineries to provide steam and heat input essential to the refining process.
Most of these devices possess sufficient size to provide the necessary temperature and residence
time for VOC destruction. Furthermore, boilers and process heaters have proved effective in
destroying compounds that are difficult to combust, such as PCBs (polychlorinated biphenyls).
Boilers and process heaters are thus effective in reducing VOC emissions from any vent streams
that are certain not to reduce the performance or reliability of the boiler or process heater.

Ducting some vent streams to a boiler or process heater can present potential safety and
operating problems. The varying flow rate and organic content of some vent streams can lead to
explosive mixtures or flame instability within the furnace. In addition, vent streams with
halogenated or sulfur-containing compounds are usually not combusted in boilers or process
heaters due to the possibility of corrosion.

Boilers and process heaters are most applicable where the potential exists for heat recovery
from the combustion of the vent stream. Vent streams with a high enough VOC concentration
and high flow rate can provide enough equivalent heat value to act as a substitute for fuel that
would otherwise be needed. Because boilers and process heaters cannot tolerate wide
fluctuations or interruptions in the fuel supply, they are not widely used to reduce VOC
emissions from batch operations or other noncontinuous vent streams.

4.1.2 Product Recovery Devices

4.1.2.1 Absorbers. In absorption, a soluble vapor is absorbed from its mixture with an inert
gas by means of a liquid in which the solute gas is more or less soluble. For any given solvent,
solute, and operating conditions, there exists an equilibrium ratio of solute concentration in the
gas mixture to solute concentration in the solvent. The driving force for mass transfer at a given
point in an operating absorber is the difference between the concentration of solute in the gas
and the equilibrium concentration of solute in the liquid.

Devices based on absorption principles include spray towers, venturi and wet impingement
scrubbers, acid gas scrubbers, packed columns, and plate columns. Spray towers have the least
effective mass transfer capability due to their high atomization pressure requirement, and are
generally restricted to particulate matter removal and control of high-solubility gases such as SO2
and NH3 (ammonia). Venturi scrubbers have a high degree of gas/liquid mixing and provide
high particulate matter removal efficiency. They also require high pressure drops (i.e. high
energy requirements) and have relatively short contact times. Their use is also restricted to high-
solubility gases. Acid gas scrubbers are used with thermal incinerators to remove corrosive
combustion products. Acid gas is formed upon the contact of halogenated or sulfur-containing
VOCs with intense heat during incineration. This gas is quenched to lower its temperature and
is then scrubbed in an absorber. In most cases, the type of absorber used is packed or plate
columns, the two most commonly used absorbers for VOC control.

Packed towers are vertical columns containing inert packing, manufactured from materials
such as porcelain, metal, or plastic, that provides the surface area for contact between the liquid
and gas phases in the absorber. Packed towers are used mainly for corrosive materials and
liquids with tendencies to foam or plug. They are less expensive than plate columns for small-
scale or pilot plant operations where the column diameter is less than 0.6 m. They are also
suitable where the use of plate columns would result in excessive pressure drops.

Plate columns contain a series of trays on which contact between the gas and liquid phases
in a stepwise fashion. The liquid phase flows down tray to tray as the gas phase moves up
through openings in the tray (usually perforations or bubble caps), passing through the liquid on
the way.

The major design parameters for absorbing any substance are column diameter and height,
system pressure drop, and required liquid flow rate. Deriving these parameters is accomplished
by considering the solubility, viscosity, density, and concentration of the VOC in the inlet vent
stream (all of which depend on column temperature); the total surface area provided by the
packing material; and the mass flow rate of the gases to be treated.

4.1.2.1.1 Absorber Efficiency. Control efficiencies for absorbers can vary widely
depending on the solvent selected, design parameters, and operating practices. Solvents are
chosen for high solubility for the specific VOC and include liquids such as water, mineral oils,
kerosenes, nonvolatile hydrocarbon oils, and aqueous solutions of oxidizing agents, sodium
carbonate, and sodium carbonate. An increase in absorber size (i.e., contact surface area) or a
decrease in the operating temperature can increase the VOC removal efficiency of the system for
a given solvent and solute. It is sometimes possible to increase VOC removal efficiency by
changing the solvent.

4.1.2.1.2 Applicability. The primary determinant of absorption applicability for
controlling VOC emissions is the availability of a suitable solvent. Water is a suitable solvent for
absorption of organic chemicals with relatively high water solubilities (e.g., most alcohols,
organic acids, aldehydes, glycols). For organic compounds with low water solubilities, other
solvents (usually organic liquids with low vapor pressures) are used.

Other important factors influencing absorption applicability include absorptive capacity and
strippability of VOC in the solvent. Absorptive capacity is a measure of the solubility of VOC in
the solvent. The solubility limits the total quantity of VOC that could be absorbed in the system,
while strippability describes the ease with which the VOC can be removed from the solvent. If
strippability is low, then absorption is less viable as a VOC control technique.

The concentration of VOC in the inlet vent stream also determines the applicability of
absorption. Absorption is usually considered only when the VOC concentration is above 200 to
300 ppm. Below these gas-phase concentrations, the rate of mass transfer of VOC to solvent is
decreased enough to make reasonable designs infeasible.

4.1.2.2 Steam Stripping. Steam stripping can be used as initial treatment of a process
wastewater stream to reduce the VOC loading of that steam before it is sent to the facility-wide
wastewater treatment system. There are several components in a steam stripping system: a feed
tank, heat exchanger, steam stripping column, condenser, overhead receiver, and a destruction
device (if necessary).

Steam stripping involves the fractional distillation of wastewater to remove VOCs. The basic
operating principle of steam stripping is the direct transfer of heat through contact of steam with
wastewater. This heat transfer vaporizes the more volatile organic compounds. The overhead
vapor contains water and organic compounds, and it is condensed and separated to recover the
organic fraction. Recovered organic compounds are either recycled for reuse in the process or
incinerated in an on-site combustion device for heat recovery.

Steam stripper systems may be operated in batch or continuous mode. Batch steam strippers
are more prevalent when the wastewater feed is generated by batch processes, when feed
characteristics are highly variable, or when small volumes of wastewater are generated. They
may also be used if wastewater contains relatively high concentrations of solids, resins, or tars.
In batch stripping, wastewater is charged to the receiver, or pot, and brought to the boiling
temperature of the mixture. Solids and other residues remaining in the bottom of the pot (hence
the term "bottoms") at the completion of the batch are nonvolatile, heavy compounds that are
removed for disposal. By varying the heat input and fraction of the initial charge boiled
overhead, a batch stripper can be used to treat wastewater mixtures with widely varying
characteristics.

In contrast to batch strippers, continuous steam strippers are designed to treat wastewater
streams with relatively consistent characteristics. Continuous strippers can have several stages
and achieve greater efficiencies of VOC removal than batch strippers. Other advantages offered
by continuous strippers include more consistent effluent quality, more automated operation, and
lower annual operating costs.

Typically, wastewater steams continuously discharged from process equipment are usually
consistent in composition. A continuous steam stripper system would thus be indicated for
treating the wastewater. However, batch wastewater streams can also be controlled by
continuous steam strippers by incorporating a feed tank with adequate residence time to provide
a consistent outlet composition.

4.1.2.2.1 Collecting, Conditioning, and Recovery. The controlled sewer system or
hard piping from the point of wastewater generation to the feed tank controls emissions before
steam stripping. The feed tank collects and conditions the wastewater fed to the steam stripper.
If the feed tank is adequately designed, a continuous steam stripper can treat wastewater
generated by some batch processes. In these cases, the feed tank serves as a buffer between the
batch process and the continuous steam stripper. During periods of no wastewater flow from the
batch process, wastewater stored in the feed tank is fed to the stripper at a relatively constant
rate.

Often present in the feed tank are aqueous and organic phases. The feed tank provides the
retention time necessary for these phases to separate. The organic phase is recycled to the
process for recovery of organic compounds or disposed by incineration. The water phase is fed
to the stripper to remove the soluble organic compounds. Solids are also separated in the
stripper feed tank; the separation efficiency depends on the density of the solids dissolved in the
process wastewater. The more dense solids, which settle to the bottom of the tank, are removed
periodically from the feed tank and are usually landfilled or landfarmed.

After this conditioning of the wastewater, it is pumped through the feed/bottoms heat
exchanger where it is preheated and then pumped into the steam stripping column. Steam is
sparged into the stripper at the bottom of the column, and the wastewater feed enters at the top.
The wastewater flowing down the column contacts the flowing countercurrently up the column.
Both latent and sensible heat is transferred from the steam to the organic compounds in the
wastewater, vaporizing them into the vapor stream. These constituents flow out the top of the
column with any uncondensed steam.

The wastewater effluent leaving the bottom of the stripper is pumped through the
feed/bottoms heat exchanger which heats the feed stream and cools the bottoms before
discharge. After leaving the exchanger, the bottoms stream is usually either routed to an on-site
wastewater treatment plant and discharged to an NPDES-permitted outfall, or sent to a publicly
owned treatment works (POTW).

Recovery of both VOCs and water vapors from the gaseous overheads stream from the steam
stripper is usually accomplished with a condenser. The condensed stream is fed to an overhead
receiver, and the recovered VOCs are usually either pumped to storage and recycled to the
process unit or combusted for their fuel value in an incinerator, boiler, or process heater (all
discussed earlier in this chapter). If an aqueous phase is generated, it is returned to the feed tank
and recycled through the steam stripper system.

4.1.2.2.2 Efficiency of Control. The degree of contact between the steam and the
wastewater is the primary variable affecting the ability of a steam stripper to remove VOCs. In
turn, this variable is affected by five factors: 1) column dimensions (height and diameter); 2) the
contacting media (packing or trays); and 3) operating parameters such as the steam-to-feed ratio,
column temperature, and wastewater pH.

Control efficiency increases as column height increases since there is greater opportunity for
contact between the steam and the wastewater. The column height is determined by the number
of theoretical stages required to achieve the desired removal efficiency. The number of
theoretical stages is a function of the equilibrium coefficient of the pollutants and the efficiency
of mass transfer in the column, and this number can be computed by either the McCabe-Thiele
graphical method or the Kremser analytical method.

The column diameter determines the required cross-sectional area for liquid and vapor flow
through the column. The smaller the cross-sectional area, the higher the superficial gas velocity,
which increase turbulence and mixing resulting in high column efficiencies. However, the
column cross-sectional area must be sufficient to prevent flooding from excessive liquid loading
or liquid entrainment. This area also affects the liquid retention time, with higher retention times
resulting in higher efficiencies. These factors have to be weighed in selecting the column
diameter and the design velocities.

The contacting media in the column also play an important role in determining the mass
transfer efficiency. Packing or trays are used to provide contact between liquid and vapor
phases. Packing provides for continuous contact while trays provide staged contact. Trays are
usually more effective for wastewater containing dispersed solids because of the plugging and
cleaning problems encountered with packing. Tray towers can also operate over a wider range
of liquid flow rates than packed towers. Packed towers, on the other hand, are often more cost
effective to install and operate when treating highly corrosive wastewater since corrosion resistant
ceramic packing can be used. Also, the pressure drop through packed towers may be less than
through tray towers.

The steam-to-feed ratio required for high removal efficiencies is affected by the wastewater
temperature as it enters the column. If the feed temperature is lower than the operating
temperature at the top of the column, part of the steam is required to heat the feed. With good
column design, sufficient steam flow is provided to heat the feed as well as volatilize the organic
constituents. Any steam in excess of this flow rate helps carry VOCs out of the top of the
column with the overheads stream. Also, increasing the steam-to-feed ratio will increase the ratio
of the vapor to liquid flow through the column, which increases the stripping of VOCs into the
vapor phase.

Two other influences on VOC removal are the column temperature and wastewater pH.
Temperature influences the solubility and equilibrium coefficients of the organic compounds.
pH has an effect on the vapor liquid equilibrium characteristics of VOCs. To ensure steam
stripping is successful, columns are operated at pressures slightly exceeding atmospheric, and
operating temperatures are usually slightly higher than the normal boiling point of water.
Wastewater pH is controlled by adding caustic to the feed.

4.1.2.2.3 Applicability. Steam stripping is most applicable to treating wastewaters with
organic compounds that are highly volatile and have a low solubility in water. The VOCs that
have low volatility tend not to volatilize and thus are not easily stripped out of the wastewater by
the steam. Similarly, VOCs that are very soluble in water tend to remain in the wastewater and
are not easily stripped by steam. Oil, grease, solids content and pH of wastewater also affect
applicability. High oil, grease, and solids levels can cause operating problems for steam
strippers, and extremes in pH may prove to be corrosive to equipment. Design or wastewater
preconditioning techniques can be used to mitigate these problems.

4.1.2.3 Carbon Adsorbers. Adsorption is a mass-transfer operation involving interaction
between gas- or liquid-phase components and solid-phase components. In this operation, certain
components of a gas- or liquid-phase (or adsorbate) are transferred to the surface of a solid
adsorbent. The transfer is accomplished by physical or chemical adsorption mechanisms.
Physical adsorption takes place when intermolecular (van der Waals) forces attract and hold the
gas molecules to the solid surface. Chemisorption occurs when a chemical bond forms between
the gaseous- and solid-phase molecules. A physically adsorbed molecule can be removed readily
from the adsorbent (under suitable temperature and pressure conditions); the removal of a
chemisorbed component is much more difficult.

Most industrial adsorption systems use activated carbon as the adsorbent. Activated carbon
effectively captures certain organic vapors by physical adsorption. The vapors can then be
released for recovery by regenerating the adsorption bed with steam or nitrogen. Oxygenated
adsorbents such as silica gels or diatomaceous earth exhibit a greater selectivity for capturing
water vapor than organic gases compared to activated carbon. They thus are of little use for
high-moisture vent streams characteristic of some VOC-containing vent streams.

Among the factors influencing the design of a carbon adsorption system are the chemical
characteristics of the VOC being recovered, the physical properties of the inlet stream
(temperature, pressure, and volumetric flow rate), and the physical properties of the adsorbent.
The mass of VOC that adheres to the adsorbent surface is directly proportional to the difference
in VOC concentration between the gas phase and the solid surface. In addition, the quantity of
VOC adsorbed depends on the adsorbent bed volume, the surface area of adsorbent available to
capture VOC, and the rate of diffusion of VOC through the gas film at the gas- and solid-phase
interface (the mass transfer coefficient). It should be noted that physical adsorption is an
exothermic operation that is most efficient within a narrow range of temperature and pressure.

4.1.2.3.1 Types of Adsorbers. There are five types of adsorption equipment used in
gas collection: 1) fixed regenerable beds; 2) disposable/rechargeable canisters; 3) traveling bed
adsorbers; 4) fluid bed adsorbers; and 5) chromatographic baghouses. The fixed-bed type is the
one most commonly used for control of VOCs, so this section addresses this type only.

Fixed-bed units can be sized for controlling continuous, VOC-containing streams over a wide
range of flow rates, ranging up to several thousand cubic meters per minute (100,000 scfm).
VOC concentrations in streams that can be treated by fixed-bed units can range from several
parts per billion by volume (ppbv) to 10,000 ppmv.

Fixed-bed adsorbers can be operated in two modes: intermittent or continuous. In
intermittent mode, the adsorber removes VOCs for a specified time (called "the adsorption
time"), which corresponds to the time during which the controlled source is emitting VOCs. In
continuous mode, a regenerated carbon bed is always available for adsorption, so that the
controlled source can operate continuously without shutting down. While continuous operation
allows for more adsorption over the same period of time because it does not need to be shut
down, more carbon must be provided. This is necessary since a bed for desorbing must be
provided along with the adsorbing bed in order to recover the captured VOC from the carbon.

4.1.2.3.2 Control Efficiency. Well designed and operated carbon adsorption systems
can achieve control efficiencies of 95 to 99 percent for a variety of solvents including ketones
such as methyl ethyl ketone and cyclohexanone. The VOC control efficiency depends on factors
such as inlet vent stream characteristics (temperature, pressure, and velocity), the physical
properties of the compounds present in the vent stream, the physical properties of the adsorbent,
and the condition of the regenerated carbon bed.

The adsorption capacity of the carbon and the resulting outlet concentration are dependent
upon the temperature of the inlet vent stream. High vent stream temperatures increase the
kinetic energy of the gas molecules, causing them to overcome van der Waals forces and release
from the surface of the carbon. At vent stream temperatures above 38 degrees Celsius, both
adsorption capacity and outlet concentration may be adversely affected.

Increasing vent stream pressure improves VOC removal efficiency. Increased stream
pressure results in higher VOC concentrations in the vapor phase and increased driving force for
mass transfer to the carbon surface. Decreased stream pressure, on the other hand, is often used
to regenerate carbon beds. Reduced pressure in the carbon bed effectively lowers the
concentration of VOCs in the vapor phase, desorbing the VOCs from the carbon surface to the
vapor phase.

Vent stream velocity entering the carbon bed must be quite low to allow time for diffusion
and adsorption. Typical inlet vent stream velocities range from 15 to 30 meters per minute (50
to 100 feet per minute). If inlet VOC concentrations are low, the bed area required for the
volume needed usually permits a velocity at the high end of this range. The required depth of
the bed for a given compound is directly proportional to the carbon granule size and porosity
and to the inlet vent stream velocity. For a given carbon type, bed depth must increase as the
vent stream velocity increases. Generally, carbon adsorber bed depths range from 0.40 to 0.95
meter (1.5 to 3.0 feet). The condition of the regenerated carbon bed will change with use. After
repeated regeneration, the carbon bed loses activity, resulting in reduced VOC removal
efficiency.

4.1.2.3.3 Applicability. Carbon adsorption cannot be used universally for distillation
or process vent streams. It is not recommended under the following conditions, common with
many VOC-containing vent streams: 1) high VOC concentrations, 2) very high or low molecular
weight compounds, 3) mixtures of high and low boiling point VOCs, and 4) high moisture
content.

Absorbing vent streams with VOC concentrations above 10,000 ppmv may result in
excessive temperature rise in the carbon bed due to the accumulated heat of adsorption resulting
from the VOC loading. If flammable vapors are present, insurance company requirements may
limit inlet concentrations to less than 25 percent of the LEL.

The molecular weight of the compounds to be adsorbed should be in the range of 45 to 130
gm/gm-mole for effective adsorption. High molecular weight compounds that are characterized
by low volatility are strongly adsorbed on carbon. The affinity of carbon for these compounds
makes it difficult to remove them during regeneration of the carbon bed. Conversely, highly
volatile materials (i.e., molecular weight less than about 45 gm) do not adsorb readily on carbon,
thus adsorption is not typically used for controlling streams containing such compounds.

Adsorption systems can be very effective with homogeneous vent streams but much less so
with streams containing a mixture of light and heavy hydrocarbons. The lighter organic
compounds tend to be displaced by the heavier compounds, greatly reducing system efficiency.

Humidity is not a factor in adsorption at adsorbate concentrations above 1,000 ppmv.
Below this level, however, water vapor competes with VOCs in the vent stream for adsorption
sites on the carbon surface. In these cases, vent stream humidity levels exceeding 50 percent
(relative humidity) are not desirable.

4.1.2.4 Condensers. Condensation is a separation technique in which one or more volatile
components of a vapor mixture are separated from the remaining vapors through saturation
followed by a phase change. The phase change from gas to liquid can be achieved in two ways:
1) by increasing the system pressure