EPA-340/1 -80-008
Petroleum Refinery
Enforcement Manual
by
PEDCo Environmental, Inc.
1006 N. Bowen Road
Arlington, Texas 76012
Contract No. 68-01-4147
Task No. 88
PN 3470-2-L
EPA Project Officer: John Busik
Task Manager: Robert King
U.S. ENVIRONMENTAL PROTECTION AGENCY
Division of Stationary Source Enforcement
Washington, DC 20460
March 1980
-------
DISCLAIMER
This report was furnished to the U.S. Environmental Protec-
tion Agency (EPA) by PEDCo Environmental, Inc., in fulfillment of
Contract No. 68-01-4147, Task No. 88. The contents are as re-
ceived from the contractor. The opinions, findings, and conclu-
sions expressed are those of the authors and not necessarily
those of the U.S. Environmental Protection Agency. Mention of
company, process, or product name is not to be considered as an
endorsement by the U.S. Environmental Protection Agency.
11
-------
CONTENTS
Disclaimer ii
Figures vi
Tables x
Acknowledgments xiii
Abstract xiv
1.0 Introduction 1-1
1.1 Background 1-1
1.2 Guide To The Manual 1-2
1.3 How To Update This Manual 1-3
1.4 Legal Rights 1-4
2.0 Petroleum Refining - Overview 2-1
2.1 Introduction 2-1
2.1.1 Petroleum 2-1
2.1.2 Petroleum refining 2-2
2.2 Separation Processes 2-4
2.2.1 Desalting 2-4
2.2.2 Crude distillation 2-6
2.2.3 Deasphalting 2-8
2.3 Decomposition Processes 2-8
2.3.1 Catalytic cracking ' 2-8
2.3.2 Hydrocracking 2-10
2.3.3 Coking 2-11
2.3.4 Visbreaking 2-12
2.4 Formation Processes 2-13
2.4.1 Catalytic reforming 2-13
2.4.2 Alkylation 2-15
2.4.3 Isomerization 2-17
2.4.4 Polymerization 2-18
2.5 Treating Processes 2-18
2.5.1 Catalytic treating 2-19
2.5.2 Chemical processes 2-19
2.6 Recovery Operations 2-20
2.6.1 Sulfur recovery 2-21
2.6.2 Fuel gas recovery 2-21
2.7 Storage 2-21
2.8 Auxiliary Facilities 2-21
2.9 Characterization Of The Petroleum Refining
Industry 2-22
2.9.1 Statistical summary of the industry 2-22
2.9.2 Trends in the industry 2-24
iii
-------
CONTENTS (continued)
3.0 Regulations
3.1 Introduction
3.2 Background
3.3 New Source Performance Standards
3.4 Prevention of Significant Air Quality
Deterioration
3.4.1 TIER I Review
3.4.2 TIER II Review
3.4.3 Definitions
3.4.4 Proposed changes to PSD regulations
3.5 Reasonably Available Control Technology (RACT)
3.5.1 Process unit turnarounds
3.5.2 Storage tanks
3.5.3 Vacuum-Producing Systems
3.5.4 Wastewater Separators
3.5.5 Fugitive emissions
3.6 State Implementation Plans
4.0
4.n-
Process Operations
Process Units
1
2
3
4
4.n.5
4.n.6
4.n
4.n
4.n
4.n
,n
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
Process description
Atmospheric emissions
Emission control method
Ins trumentati on
Startup/Shutdown/Malfunctions
References
Distillation
Catalytic Cracking
Viscosity Breaking
Hydrocracking
Catalytic Reforming
Alkylation
Isomerizatipn
Polymerization
Crude and Product Treating
Hydrotreating
Wax and Grease Production
Asphalt Production
Coking
Amine Treater
Gas Processing
Sulfur Plant
Sulfuric Acid Plant
Product Blending
Crude and Product Storage
Processs Heaters and Boilers
Wastewater Treatment
Relief and Blowdown Systems for Process Units
3-1
3-1
3-1
3-2
3-4
3-5
3-5
3-8
3-10
3-12
3-14
3-15
3-16
3-16
3-17
3-18
4.0-1
4.0-2
4.0-2
4.0-2
4.0-3
4.0-6
4.0-6
4.0-6
4.1-1
4.2-1
4.3-1
4.4-1
4.5-1
6-1
7-1
4.8-1
4.9-1
10-1
11-1
4.12-1
4.13-1
4.14-1
15-1
16-1
17-1
18-1
19-1
4.20-1
4.21-1
4.22-1
4,
4,
4,
4,
IV
-------
CONTENTS (continued)
5.0 Enforcement Procedures 5-1
5.1 Introduction 5-1
5.2 Level I Inspection 5-2
5.3 Level II Inspection 5-4
5.4 Level III Inspection 5-5
5.5 Inspection Schedule 5-7
5.6 Inspection Report Form 5-10
5.7 Completion of Level I Checklist 5-10
5.8 Completion of Level I Checklist 5-14
5.9 Completion of Level I Checklist 5-14
6.0 Trends In Inspection Data 6-1
Appendices:
A Operating Refineries In The United States A-l
B Simplified Theory Of Reactors B-l
C Basic Principles Of Fractionation C-l
D Selected Physical Properties Of Common
Petrochemical Compounds D-l
E Storage Tank Inspection By Statistical Sampling E-l
F MIL-STD Tables For Use In Statistical Sampling
Of Storage Tanks F-l
G Operating Instructions For An Organic Vapor
Analyzer (OVA) G-l
H Emissions From Valves, Pump and Compressor
Seals, and Other Refinery Equipment Components H-l
I Information Checklists For PSD Review 1-1
J Level I Inspection: Blank Checklist Forms J-l
K Level I Inspection: Blank Checklist Forms K-l
L Level II Inspection: Completed Checklist Forms L-l
M Level III Inspection: Blank Checklist Forms M-l
Glossary
Bibliography
-------
LIST OF FIGURES
2-1 Typical processing steps in a petroleum refinery 2-4
4.1-1 Typical crude oil distillation unit 4.1-2
4.2-1 Reactor/regenerator portion of a fluid catalytic
cracking unit 4.2-2
4.2-2 Fractionator portion of a fluid catalytic unit
with two risers 4.2-3
4.2-4 Moving-bed (airlift) catalytic cracking unit 4.2-4
4.2-5 Points of emissions from moving-bed catalytic
cracking unit 4.2-10
4.3-1 Visbreaking process 4.3-2
4.3-2 Visbreaking unit with soaking drum 4.3-4
4.4-1 Two-stage hydrocracking unit 4.4-3
4.4-2 One-stage hydrocracking unit 4.4-6
4.5-1 Process flow diagram of Platforming unit 4.5-4
4.5-2 Process flow diagram of Magnaforming unit 4.5-7
4.6-1 Block flow diagram of hydrofluoric acid
alkylation 4.6-2
4.6-2 Process flow diagram of hydrofluoric acid
alkylation 4.6-3
4.6-3 Block flow diagram of sulfuric acid alkylation
with effluent refrigeration 4.6-6
4.6-4 Process flow diagram of sulfuric acid alkylation
with effluent refrigeration 4.6-7
4.6-5 Block flow diagram of sulfuric aic alkylation with
cascade autorefrigeration 4.6-9
4.6-6 Process flow diagram of sulfuric acid alkylation
with cascade autorefrigeration 4.6-10
4.7-1 Butane isomerization process 4.7-3
4.7-2 Pentane/Hexane isomerization process flow 4.7-6
4.8-1 Process flow of polymerization with solid
phosphoric acid catalyst 4.8-3
4.8-2 Process flow of polymerization with liquid
phosphoric acid catalyst 4.8-4
VI
-------
Figures (continued)
4.9-1 Flow diagram of desalting process 4.9-2
4.9-2 Flow diagram of Bender sweetening process 4.9-5
4.10-1 Flow diagram of Gulfing unit 4.10-2
4.10-2 Flow diagram of Hydrofing unit 4.10-4
4.11-1 Typical dewaxing process using methyl ethyl
ketone solvent 4.11-2
4.11-2 Typical grease manufacturing process 4.11-4
4.12-1 Block flow diagram of asphalt air-blowing unit 4.12-2
4.13-1 Flow diagram of delayed coking unit 4.13-2
4.13-2 Flow diagram of fluid coking unit 4.13-5
4.13-3 Flow diagram of coke calcination process 4.13-6
4.14-1 Flow diagram of a typical amine treater 4.14-2
4.15-1 Flow diagram of vapor recovery unit 4.15-2
4.16-1 Typical Glaus sulfur recovery process 4.16-4
4.16-2 Flow diagram of the Beavon process 4.16-7
4.16-3 Flow diagram of the SCOT process 4.16-10
4.16-4 Wellman-Lord SO-2 recovery process flow diagram 4.16-11
4.16-5 IFP-1500 Glaus tail-gas treatment 4.16-14
4.17-1 Flow diagram of contact-process sulfuric acid
plant burning elmental sulfur 4.17-3
4.17-2 Flow diagram of acid regeneration plant 4.17-5
4.17-3 Flow diagram of vacuum concentration process 4.17-7
4.17-4 Flow diagram of Chemico drum concentration
process 4.17-8
4.17-5 Flow diagram of acid recirculation process 4.17-9
4.19-1 Fixed roof storage tank 4.19-4
4.19-2 Singledeck pontoon-floating-roof storage tank
with nonmetallic seals 4.19-6
4.19-3 Pan-type floating-roof storage tank with
metallic seals 4.19-7
4.19-4 Double-deck floating roof storage tank with
nonmetallic seals 4.19-8
4.19-6 Lifter-roof storage tank with wet seal 4.19-11
4.19-7 Flexible-diaphragm storage tank 4.19-13
4.19-8 Simplified vapor recovery system 4.19-17
4.19-9 Flow diagram of vapor recovery system 4.19-19
4.19-10 Vapor recovery system with absorbtion 4.19-20
VII
-------
Figures (continued)
4.20-1 Typical vertical refinery process heater ' 4.20-4
4.20-2 Typical high pressure/high temperature boiler 4.20-6
4.21-1 Wastewater treatment flow diagram 4.21-2
4.21-2 Single-stage sour water stripper 4.21-5
4.21-3 Doulbe-stage sour water stripper 4.21-6
4.21-4 Top and side views of API separator 4.21-9
4.21-5 Corrugated plate interceptor (CPI) separator 4.21-10
4.21-6 Trickling filter 4.21-13
4.21-7 Activated sludge process 4.21-14
4.22-1 Nozzle type, spring-loaded conventional relief
valve 4.22-3
4.22-2 Wing guided, spring-loaded conventional relief
valve 4.22-4
4.22-3 Bellows-type balanced pressure relief valve 4.22-6
4.22-4 Relief valve for liquid service 4.22-7
4.22-5 Typical rupture disc installation 4.22-8
4.22-6 Lever-and-Weight Combination Pressure and
Vacuum Relief Hatch 4.22-10
4.22-7 Flow diagram of a typical flare installation
for safe disposition of flammable vapors,
including separator drum for collection of
condensation 4.22-16
4.22-8 Flow diagram of a typical blowdown drum and
stack installation 4.22-17
5-1 Flow diagram of a typical blowdown drum and
stack installation 5-4
5-2 Inspection report form 5-12
5-3 Level I inspection checklist 5-13
5-4 Example Level I inspection checklist after
file research 5-14
5-5 Example Level I inspection checklist after
inspection 5-15
E-l Typical operating characteristic curve for
sampling plan E-4
G-l Portable organic vapor analyzer (Model OVA-128) G-2
G-2 Illustration of the use of the organic vapor
analyzer G-3
H-l Gate valves H-3
H-2 Globe valves H-4
H-3 Lubricated plug valves H-5
H-4 Ball valve H-6
Vlll
-------
Figures (continued)
H-5 Butterfly valve H-6
H-6 Weir-type diaphragm valve H-7
H-7 Check valve H-7'
H-8 Spring-loaded relief valve H-8
H-9 Vertical centrifugal pump H-ll
H-10 Horizontal centrifugal pump H-ll
H-ll Simple packed seal H-13
H-12 Simple mechanical seal H-14
H-13 Doulbe mechanical seals for pumps H-15
H-14 Honeycomb labyrinth compressor seal H-16
H-15 Mechanical seals for compressors H-17
IX
-------
LIST OF TABLES
2-1 Characterization of fractions obtained from
crude oil 2-3
2-2 Major reactions occurring in catalytic
reforming 2-4
2-3 Summary of reactions occurring in alkylation 2-16
2-4 Summary of operating refineries in the United
States 2-23
2-5 Operating refineries and crude oil throughput 2-26
3-1 Sources subject to PSD review 3-6
3-2 Guidelines for significant emission rates 3-11
3-3 Guidelines for significant ambient air quality
impacts 3-13
4.0-1 Symbols used in process flow diagrams 4.0-3
4.2-1 Typical times for repair of unit malfunctions 4.2-18
4.5-1 Naptha yields under varying conditions 4.5-11
4.6-1 Ranges of operating conditions for
hydrofluoric acid 4.6-15
4.6-2 Ranges of operating conditions for sulfuric
acid alkylation 4.6-16
4.7-1 Operating conditions for sulfuric acid
alkylation 4.7-4
4.15-1 Liquefied petroleum gas yields from conversion
processes 4.15-1
4.15-2 Grading requirements for liquefied petroleum gas 4.15-5
4.16-1 Typical Glaus plant sulfur recovey at various
feed compositions 4.16-2
4.19-1 Acceptable storage tanks for petroleum liquids
of low, intermediate, and high volatility 4.19-2
4.19-2 Physical properties of hydrocarbons 4.19-3
4.22-1 Disposition of process vapors from relief
valves, blowdown valves, and drains 4.22-12
5-1 Level II leak detection program 5-7
5-2 Level III leak detection program 5-9
5-3 Example of an inspection schedule for an
individual refinery 5-10
x
-------
TABLES (continued)
6-1 Example of trend table
6-2 Summary of trends observed at Refinery A
A-l Operating petroleum refineries in the United
States
A-2 Breakdown of operating
A-3 Breakdown of operating
A-4 Breakdown of operating
A-5 Breakdown of operating
Massachusetts
A-6 Breakdown of operating
New Hampshire
A-7 Breakdown of operating
Rhode Island
A-8 Breakdown of operating
A-9 Breakdown of operating
A-10 Breakdown of operating
A-ll Breakdown of operating
A-12 Breakdown of operating
A-13 Breakdown of operating
Virgin Islands
A-14 Breakdown of operating
A-15 Breakdown of operating
A-16 Breakdown of operating
A-17 Breakdown of operating
Pennsylvania
A-18 Breakdown of operating
A-19 Breakdown of operating
West Virginia
A-20 Breakdown of operating
District of Columbia
A-21 Breakdown of operating
A-22 Breakdown of operating
A-23 Breakdown of operating
A-24 Breakdown of operating
A-25 Breakdown of operating
A-26 Breakdown of operating
A-27 Breakdown of operating
North Carolina
A-28 Breakdown of operating
South Carolina
A-29 Breakdown of operating
A-30 Breakdown of operating
A-31 Breakdown of operating
A-32 Breakdown of operating
A-33 Breakdown of operating
A-34 Breakdown of operating
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
in Region I
in Connecticut
in Maine
in
in
in
in Vermont
in Region II
in New Jersey
in New York
in Puerto Rico
in
in Region III
in Delaware
in Maryland
in
in Virginia
in
refineries in the
refineries
refineries
refineries
refineries
refineries
refineries
refineries
in Region IV
in Alabama
in Florida
in Georgia
in Kentucky
in Mississippi
in
refineries in
refineries
refineries
refineries
refineries
refineries
refineries
in Tennessee
in Region III
in Illinois
in Indiana
in Michigan
in Minnesota
6-3
6-4
A-2
A-3
A-4
A-5
A-6
A-7
A-8
A-9
A-10
A-ll
A-12
A-13
A-14
A-15
A-16
A-17
A-18
A-20
A-21
A-22
A-23
A-24
A-25
A-26
A-27
A-28
A-29
A-30
A-31
A-32
A-33
A-35
A-37
A-38
XI
-------
TABLES (continued)
A-35
A-36
A-37
A-38
A-39
A-40
A-41
A-42
A-43
A-44
A-45
A-46
A-47
A-48
A-49
A-50
A-51
A-52
A-53
A-54
A-55
A-56
A-57
A-58
A-59
A-60
A-61
A-62
A-63
A-64
A-65
A-66
D-l
E-l
F-l
F-2
F-3
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
North Dakota
Breakdown of operating
South Dakota
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
American Samoa
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
Breakdown of operating
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
in Ohio
in Wisconsin
in Region VI
in Arkansas
in Louisiana
in New Mexico
in Oklahoma
in Texas
in Region VII
in Iowa
in Kansas
in Missouri
in Nebraska
in Region VIII
in Colorado
in Montana
in
refineries in the
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
refineries
in Utah
in Wyoming
in Region IX
in Arizona
in California
in Hawaii
in Nevada
in
in Guam
in Region X
in Alaska
in Idaho
in Oregon
in Washington
Selected physical properties of common
petrochemical compounds
Refinery tank inspection plan
Sample size code letters
Single sampling plans for normal inspection
(master table)
Doubling sampling plans for normal inspection
(master table)
A-39
A-40
A-41
A-42
A-43
A-47
A-48
A-50
A-58
A-59
A-60
A-62
A-63
A-64
A-65
A-66
A-67
A-68
A-69
A-70
A-72
A-73
A-74
A-80
A-81
A-82
A-83
A-84
A-85
A-86
A-87
A-88
D-2
E-6
F-2
F-3
F-5
Xll
-------
ACKNOWLEDGMENTS
This report was prepared under the direction of
Mr. Thomas C. Ponder, Jr., and Ms. Nancy A. Kilbourn. Authors
include Ms. Jean Carruthers, Mr. Jack McClure, Mr. Dilip Mehta,
and Ms. Roberta Pollard-Cavalli. The Task Manager for the U.S.
Environmental Protection Agency was Mr. Robert L. King.
Kill
-------
ABSTRACT
Petroleum refining involves a wide variety of processes
which are used to convert crude oil into many different, market-
able products. The environmental regulations which govern the
refining industry cover a multitude of sources and pollutants.
Like the industry itself, these regulations are in a dynamic
state of change. The complexity of refining processes and the
regulations applicable to refineries created a need for a refin-
ery enforcement manual. The manual has been developed to assist
enforcement personnel in understanding the refining industry, as
well as to aid them in making inspections and determining compli-
ance with emission regulations. The manual includes detailed
process descriptions; a glossary of refinery terms; a discussion
of current regulations applicable to refineries; a discussion of
enforcement procedures, including checklists which can be used
during inspections; a list of all the refineries in the United
States; discussions on refining theories; and a bibliography.
xiv
-------
INTRODUCTION
-------
SECTION 1
INTRODUCTION
1.1 BACKGROUND
Numerous earlier EPA publications give suggestions regarding
methods of inspection of petroleum refineries. With the advent
of revised State Implementation Plans (SIP's) in early 1979,
emphasis on control of hydrocarbons from refineries has increased
greatly. The SIP revisions include provisions for control of
hydrocarbons from vacuum producing systems, wastewater treatment
systems, process turnarounds, and fugitive emissions. In the
long term, additional guidelines will be promulgated that will
affect controls for process heaters and boilers and for handling
of waste sludge. Consequently, the inspector is faced with a
large number of separate regulations covering control of a multi-
tude of sources and pollutants. Compounding this problem is the
dynamic state of change of the various regulations.
The changing status of regulations applicable to refineries
and the complexity of refining processes create a need for a
refinery enforcement manual. This manual has been developed to
meet that need and is prepared in such a way that information on
changes in regulations or technology can be easily incorporated.
It presents ample background information on the petroleum refin-
ing industry to aid enforcement personnel in inspections. The
primary purpose of this manual is to assist enforcement personnel
in making inspections and determining compliance with emission
regulations.
Petroleum Refinery Enforcement Manual Introduction
3/80 1-1
-------
1.2 GUIDE TO THE MANUAL
This manual is presented as a loose-leaf style notebook to
allow easy updating (Section 1.3). The notebook style also makes
possible the simple addition or deletion of material as appropri-
ate for an individual inspector.
The manual contains six sections. This introduction, the
first section, explains how to use and update the manual, and
discusses the inspector's legal right of entry.
Section 2 is an overview of the refining industry, describ-
ing the various process units contained in a refinery. Review of
this section acquaints the inspector with the basic operation of
the process units.
Section 3 summarizes the applicable regulations that the
inspector will be enforcing.
Section 4 presents detailed process descriptions, monitoring
and inspection procedures, and related descriptive material
concerning many of the common refinery processes. The inspector
can gain an understanding of the entire refining operation by
studying these process descriptions.
Section 5 describes the three levels of inspection and the
process units inspected at each level. The first-level inspec-
tion requires approximately 2 hours; the second level, approxi-
mately 2 days; and, the third level, approximately 2 weeks. The
specific units to be inspected at each level are listed in this
section. The inspector is to be well acquainted with the infor-
mation in Section 4, concerning the units to be inspected, before
performing the inspection.
Section 6 tabulates checklist data from previous inspections
for each process unit, so that the inspector can monitor the
changing compliance status at a refinery.
The appendixes provide additional information for the in-
spector including assumptions of the basic refining theory de-
scribed in this manual, instructions on monitoring equipment
leaks, and use of the organic vapor analyzer. A glossary and a
Petroleum Refinery Enforcement Manual Introduction
3/80 1-2
-------
bibliography are presented after the appendices. Primary refer-
ences are given at the end of each section or subsection.
1.3 HOW TO UPDATE THIS MANUAL
This manual is designed to be revised or updated as new data
become available. The page numbering system allows for easy
insertion of new pages or the updating of existing pages. The
system has four parts and is printed across the bottom of each
page as below:
Title Section Title
Issue Date Page Number
An actual example of the page numbering system is as follows:
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-1
Pages are numbered consecutively within each major section
(or appendix), except Section 4. Pages in Section 4 are numbered
within each subsection: for example, 4.0-1, 4.6-1. New and
revised pages will be added as necessary. Examples of updating
the manual follow.
New Page
When a new page containing additional data is sent to the
user, it will be numbered as follows:
Petroleum Refinery Enforcement Manual Alkylation
1/81 4.6-1.1
This page is to be inserted between pages 4.6-1 and 4.6-2.
Revised page
If page 4.6-1 is revised, it will be reissued with the same
page number and the issue date of the revision:
Petroleum Refinery Enforcement Manual Alkylation
1/81-R1 4.6-1
This page is to be inserted in place of the superseded
page 4.6-1 that was issued 3/80.
Petroleum Refinery Enforcement Manual Introduction
3/80 1-3
-------
1.4 LEGAL RIGHTS
Credentials
The inspector is authorized to conduct official inspections
under the provisions of Section 114 of the Clean Air Act, as
amended, 42 U.S.C. 74 I4(a)(l) and (2). With respect to the
inspector's authority, Section 114(a)(2) states as follows:
The Administrator or his authorized representative upon
presentation of his credentials -
(A) shall have a right of entry to, upon, or through
any premises in which an emission source is lo-
cated or in which any records required to be
maintained (under paragraph (1) of this section)
are located, and
(B) may at reasonable times have access to copy any
records, inspect any monitoring equipment or
method [required under paragraph (1)], and sample
any emissions which the owner or operator of such
source is required to sample [under paragraph (1)]
(parentheses added).
Denial of Entry
If the inspector is refused entry to a facility, the events
leading to the denial should be documented in writing. These
records are valuable for future enforcement proceedings. Visible
emission measurements or estimates should be obtained after
leaving the facility premises and included with the written
record of events. When refused entry to a plant, the inspector
may obtain a search warrant if necessary. Guideline S-12 pro-
vides a model affidavit in support of an application for a war-
rant.
Waivers
Most refineries maintain a sign-in sheet intended for plant
records and containing spaces for the name and affiliation of the
signers. There is no reason that the inspector should not sign
this log sheet upon request. Under no circumstances, however,
should an inspector sign a release from liability (waiver) upon
Petroleum Refinery Enforcement Manual Introduction
3/80 1-4
-------
entering a facility under authority of Section 114. Such a
signature could waive the right to collect damages for injury
while on company property. If asked to sign a waiver, the in-
spector should mark through the language of the waiver before
signing the sheet, or write "no waiver" next to the signature.
Secrecy and Confidentiality
An inspector should never sign a pledge or statement of
secrecy regarding information obtained during the inspection,
unless an earlier agreement provides for disclosure under condi-
tions that satisfy 40 CFR Part 2 (41 FR 36902 et seq.), Septem-
ber 1, 1976. The EPA is required under Section 114 to make
inspection information available to the public, except that trade
secrets are not to be disclosed.
A refiner's claim of confidentiality in refusing the release
of emission data to an inspector is unjustified. Confidentiality
applies only to the release of proprietary data to the public; it
does not apply to information obtained by an inspector performing
duties under Section 114 of the Clean Air Act. Therefore, if
refinery personnel claim that emission data are confidential, the
inspector should explain that confidentiality applies only to
release of proprietary information to the public. A copy of
Section 114(s) should be shown to plant personnel and the provi-
sions explained, if necessary.
In the event that plant officials continue to refuse to
provide emission information, the inspector should record the
names of these individuals. The enforcement agency can then send
them a letter requesting the information, accompanied by a de-
tailed discussion of the confidentiality provision of the Clean
Air Act.
Reference
1. U.S. Environmental Protection Agency. Office of Enforce-
ment. EPA Visible Emissions Inspection Procedures. Sta-
tionary Source Inspection Series. February 1979.
Petroleum Refinery Enforcement Manual Introduction
3/80 1-5
-------
John Quarles1 memo of November 8, 1972, which was included
as an appendix to EPA Guideline S-12, specifically instructs
EPA employees to refuse to sign a release (waiver) upon
entering a source under the authority of Section 114. These
instructions also apply to EPA contractors in pursuit of
their authorized duties if the contractor has been designa-
ted an "authorized representative" of EPA. (OGC must author-
ize these contractors by letter.)
Under no conditions should a visitor's release for liability
be signed by an inspector while on the plant premises. To
do so could waive the right to obtain damages for injury as
explained in Mr. Quarles1 memo. State and local agency
inspectors should also be aware of the risk of signing a
release for liabilty.
Petroleum Refinery Enforcement Manual Introduction
3/80 1-6
-------
OVERVIEW
-------
SECTION 2
PETROLEUM REFINING - OVERVIEW
2.1 INTRODUCTION
2.1.1 Petroleum
Petroleum, usually called crude oil, is a complex mixture of
hydrocarbons, with small amounts of other substances, that occurs
as an oily liquid in many places in the upper strata of the
earth. Many crude oils, such as those from Arabia and Iraq, have
a strong odor of hydrogen sulfide and sulfur compounds; others,
such as those from Nigeria and Indonesia, contain very little
sulfur and do not have any unpleasant odor. The color of crude
oil ranges from clear to black.
Crude oil in the ground is associated with hydrocarbon
gases, of which substantial quantities are dissolved in the oil
under pressure. Methane and ethane constitute by far the great-
est proportion of the gases associated with crude oil.
It has been estimated that crude oil contains over 3000
different chemical compounds, and the chemical composition varies
with the source. Hydrocarbons are the predominant components;
the remainder consists chiefly of organic compounds containing
oxygen, nitrogen, sulfur, and traces of inorganic compounds
containing iron, nickel, vanadium, and arsenic.
The molecular weight of the hydrocarbons in crude oil varies
widely because they contain different numbers of carbon atoms per
molecule. The chemical structure of these hydrocarbons also dif-
fers greatly. The types of hydrocarbons present in crude oil are
paraffins (alkanes), naphthenes (cycloparaffins), and aromatics.
Petroleum Refinery Enforcement Manual Overview
3/80 2-1
-------
Crude oil is separated by distillation into fractions desig-
nated as (1) light ends; (2) straight-run gasolines, with boiling
points that range up to about 204°C (400°F); (3) middle distil-
lates, boiling at about 185° to 343°C (365° to 650°F), from which
are obtained kerosene, heating oils, and fuels for diesel, jet,
rocket, and gas turbine engines; (4) wide-cut gas oil, boiling at
343° to 538°C (650° to 1000°F), from which are obtained waxes,
lubricating oils, and feedstock for catalytic cracking operations
that produce gasoline; and (5) residual oil, from which asphalt,
coke, and tar may be obtained.
2.1.2 Petroleum Refining
The refining sector of the petroleum industry converts crude
oils, various semifinished petroleum fractions, and hydrocarbon
gases into useful products. These products are refined by vari-
ous physical, thermal, catalytic, and chemical processes, into
the wide range of products mentioned earlier. Refinery products
generally are not pure chemical compunds but are mixtures of
chemical compounds. Table 2-1 characterizes many of these prod-
ucts. In each case the boiling range, rather than a single boil-
ing point, is due to the fractions being a mixture of chemical
compounds.
Because refining processes are complex and are specific to
each refinery, intermediate storage may be needed for certain
fractions that will be returned to various units for further
processing. Since each refinery is designed, engineered, and
constructed to handle specific crude oils and to produce specific
refined or semirefined products, there is no "typical" refinery.
Additionally, the processing parameters change with the type of
crude oil to be refined. For example, an increase in the refin-
ing of Alaska's North Slope crude has led to expanded use of
catalytic reformers and fluid-bed catalytic cracking units.
Even though there is no typical refinery, most U.S. refiner-
ies are designed to maximize the production of light distillates,
i.e., gasoline. The following operations (Figure 2-1) are basic:
Petroleum Refinery Enforcement Manual Overview
3/80 2-2
-------
TABLE 2-1. CHARACTERIZATION OF FRACTIONS OBTAINED FROM CRUDE OIL
Fraction
Gas
Gasoline
Jet fuel
Gas oil
Lube oil
Residuum
Carbon
atoms
1 to 4
5 to 12
10 to 16
15 to 22
19 to 35
36 to 90
Molecular
weight
16 to 58
72 to 170
156 to 226
212 to 294
268 to 492
492 to 1262
API
gravity
58 to 62
40 to 46
34 to 38
24 to 30
8 to 18
Boilinga
range, °F
-259 to 31
31 to 400
356 to 525
500 to 700
640 to 875
875+
'F = 5/9 (°C) + 32
Petroleum Refinery Enforcement Manual
3/80 2-3
Overview
-------
to
00 ft
Oil
o
CD
HI
H-
M
hj
O
0)
n>
tog
tkp
0>
TO HYDROTREATERS
AND
HYDROCRACKER
••GAS
GASOLINE
LUBES
• AND
WAXES
*• ASPHALT
O
a>
<
H-
(D
Figure 2-1. Typical processing steps in a petroleum refinery.
-------
(1) separation processes, separating the crude oils to isolate
the desired products (e.g., distillation); (2) decomposition
processes, breaking large hydrocarbon chains into smaller ones by
cracking (e.g., catalytic cracking, coking); (3) formation pro-
cesses, building the products by chemical reaction (e.g., reform-
ing, alkylation, isomerization); (4) treating processes, removing
impurities or compounds that are detrimental to operation of the
refinery; (5) recovery operations (e.g., sulfur recovery, fuel
gas recovery); (6) storage; and (7) auxiliary facilities. Figure
2-1 shows the interrelationships of these processes, which are
described in the following subsections.
2.2 SEPARATION PROCESSES
2.2.1 Desalting
Crude oil is a mixture of hydrocarbon compounds contaminated
by water, salt, and sand. Although most of the water and sand
settle out and separate during storage, the crude is saturated
with water, dissolved salts, and minerals. Crude oil desalting
is a combination separation/reaction operation, in which an
impressed electrical current field and/or chemical additives are
used to coalesce the salt particles, which are then washed away
with water.
Electrical desalting, the most common technique, involves
the addition of water to crude under pressure and at 71° to 149°C
(160° to 300°F). This mixture is emulsified and introduced into
a high-potential electrostatic field, which causes the impurities
to associate with the water phase and at the same time causes the
water phase to agglomerate so that it can be removed. The de-
salted crude proceeds to the distillation units.
Chemical desalting of crude is accomplished by adding water
to the heated [93° to 149°C (200° to 300°F)] and pressurized oil.
The pressure must be high enough to prevent vaporization of the
water. The mixture is emulsified, and the salt enters the water
phase. Chemical additives may be used to break the emulsion and
Petroleum Refinery Enforcement Manual Overview
3/80 2-5
-------
allow the water phase to settle. The water containing the salt
is discharged from the system.
2.2.2 Crude Distillation
The first major separation operation in refining is crude
oil distillation. In distillation towers (columns) various
constant-boiling-range fractions are separated, the lowest boil-
ing fraction leaving the top of the tower and the highest boiling
fraction leaving the bottom. Products may be withdrawn as side-
streams at appropriate points on the tower. The sidestreams are
further processed in small towers called strippers, in which
steam is used to free the sidestream (cut) from its more volatile
components so that the boiling point of the product can be ad-
justed to a specified value. There are three major types of
distillation systems: single-stage, two-stage, and two-stage
with a vacuum tower.
Single-stage Distillation—
The crude feed is preheated by outgoing streams before
entering a direct-fired, furnace-type heater, from which it goes
to a distillation column for separation into gas, gasoline,
naphtha, kerosene, gas oil, fuel oil, and residuum. These side-
streams are steam-stripped and then routed to storage. Topping
plants use single-stage distillation, usually separating the
crude into five or six sidestreams. Very little additional
treating is performed at these plants. The number and type of
fractions that result from distillation depend on the crude base
and on operating conditions.
Two-Stage Distillation—
Two-stage distillation provides more cuts than the single-
stage system. The process includes a primary tower (preflash
tower), which operates at above atmospheric pressure, and a sec-
ondary tower (atmospheric tower), which operates at atmospheric
pressure. These units, together with a stabilizer (stabilizing
Petroleum Refinery Enforcement Manual Overview
3/80 2-6
-------
tower), are used to separate the crude into light ends, depropa-
nized light gasoline, light kerosene, naphtha, kerosene, light
diesel, heavy diesel, and residuum.
The preflash overhead is fed to the stabilizer for removal
of the lighter hydrocarbons (usually dissolved gaseous hydrocar-
bons such as propane). In the stabilizer, the light hydrocarbons
are removed overhead, and the stabilized product is removed at
the bottom.
The preflash bottoms feed the atmospheric tower, where again
side cuts are taken and steam stripped to remove the light ends.
Two-Stage Distillation with Vacuum Tower—
This system incorporates the two-stage arrangement and adds
to it a vacuum tower. The bottoms from the atmospheric tower
feed the vacuum distillation tower, which operates at below
atmospheric pressure. Operation under a vacuum allows the reduc-
tion of operating temperatures and thus prevents coking in the
heater tubes or on trays and thermal degradation, which may occur
in high-temperature operations.
The petroleum refinery uses vacuum distillation to produce
light and heavy gas oils, heavy fuel oil, vacuum gas oil, lubri-
cating oil fractions, and vacuum bottoms. A refinery that prod-
uces lubricating oils may use two separate vacuum towers, one
especially designed to recover lube oil fractions and the other
designed for fuel oil fractions.
Although steam is not usually injected into the vacuum unit,
in some wet vacuum units steam is added to the distillation
column operating under a vacuum. The dry vacuum process has the
advantage of using smaller towers and smaller condensing equip-
ment for a given throughput and also is more economical and
energy efficient than the wet process.
A vacuum is usually created by steam jet ejectors discharg-
ing to surface condensers (shell and tube), which limits air
pollution. Alternatively, direct contact condensers are used, in
which case, water, steam, and hydrocarbon vapors are mixed. This
type of condenser can generate air pollutants; however, the
Petroleum Refinery Enforcement Manual Overview
3/80 2-7
-------
noncondensables from these units usually are vented to the re-
finery flare system as a means of controlling hydrocarbon emis-
sions.
Appendix C provides more details of the principles of frac-
tionation. Literature references and definition of terms are
given in the Bibliography and Glossary at the end of this manual.
2.2.3 Deasphalting
Deasphalting separates asphalts or resins from more viscous
fractions. Refineries and chemical plants commonly accomplish
such separation by liquid-liquid extraction. In this operation,
a mixture is separated into two components by means of a selec-
tive solvent, the separation being due to differences in solu-
bility. For ease of separation, the solvent must yield a two-
phase mixture with appreciable difference in densities of the two
phases.
In deasphalting, residuum from the vacuum tower and liquid
propane are heated to a controlled temperature and mixed at a
controlled ratio as feed to the deasphalting tower. The two
phases that result are separated, and propane is removed from the
deasphalted oil phase by a two-stage evaporation process and
steam stripping. The asphalt phase is heated and steam stripped
for removal of residual propane. The propane is then condensed
and recycled. Overhead from both strippers is water washed, com-
pressed, and condensed before being recycled as propane extract-
ant.
2.3 DECOMPOSITION PROCESSES
2.3.1 Catalytic Cracking
Catalytic cracking is a relatively inexpensive method of
breaking down heavier distillate fractions into lighter gasoline
material and thus increasing the overall gasoline yield from
crude oil. The variety of catalysts and system designs provide a
Petroleum Refinery Enforcement Manual Overview
3/80 2-8
-------
wide range of operating flexibility for the catalytic cracking
process.
Two well-known catalytic processes are in use today—the
fluid catalytic cracker (FCC) and the Thermofor catalytic cracker
(TCC). The FCC uses a powdered catalyst and the TCC or Houdri-
flow, no longer7 generally manufactured, uses a bead catalyst.
In the FCC, finely powdered catalyst is lifted into the
reaction zone by the incoming oil, which vaporizes immediately
upon contact with the hot catalyst. When the reaction is com-
plete, the product and catalyst are lifted into a regeneration
zone by air. In the reaction and regeneration zones, the cata-
lyst powder is held in a suspended state by the passage of gases
through it, and a small amount of catalyst is moved from the
reactor to the regenerator and vice versa. Oil tends to saturate
the enormous volume of pulverized catalyst in the reactor, and
hence the catalyst must be steam stripped before it enters the
regenerator.
The TCC is a moving-bed system with catalyst in the form of
beads or pellets. The catalyst is lifted by air, or in old
plants by bucket elevators, to a high position so that it can
flow downward by the force of gravity. It moves through the oil
zone, causing reaction, and then through a regeneration zone.
In both the FCC and TCC processes the catalyst must be re-
generated. Coke that forms on the catalyst particles during the
reaction must be continuously removed to maintain catalyst acti-
vity. In the regenerator, a controlled stream of air is added to
burn off the coke. The resulting combustion gases flow through a
series of cyclones for removal of the entrained catalyst. The
regenerator gases (often rich in carbon monoxide, CO) may be
burned as fuel in a CO boiler to generate refinery steam and
eliminate CO emissions.
Reactor products are condensed and stabilized in a large
distillation tower, where several streams are taken off. The
lightest streams are sent to a gas recovery unit, and the heavi-
est streams are recycled to the catalytic cracker. The recycle
Petroleum Refinery Enforcement Manual Overview
3/80 2-9
-------
ratio and the ratio of catalyst to oil depend on the type of
feedstock and the desired product.
More detailed explanations of the fluid unit are given in
Section 4.2 and Appendix B.
2.3.2 Hydrocracking
Hydrocracking units perform both cracking and hydrogenation.
Products from hydrocracking are essentially saturated materials
with high concentrations of isoparaffins and naphthenes.
The hydrocracker functions in a manner similar to the cata-
lytic cracker but operates over a wider range of feedstock boil-
ing points. Because of their great flexibility, hydrocracking
processes may be operated to produce high-quality motor gasoline,
petrochemical naphtha, jet fuel, and diesel oils. With the new
catalysts available, a single hydrocracking unit can be used to
convert feedstocks as heavy as vacuum gas oils into either naph-
tha or high yields of middle distillates, simply by regulation of
the fractionation cut points and reactor temperatures. Hydro-
cracking is also used to desulfurize high-sulfur crude oils while
upgrading the heavier fractions into lighter fuel oils. The
inherent flexibility of the process will allow a gradual increase
in yield of motor gasoline to meet current market demand.
The fixed-bed hydrocracking catalysts maintain high activity
in the presence of nitrogen and sulfur compounds. Various pro-
cess configurations and catalyst systems can be combined to yield
the optimum product spectrum for a particular feedstock.
The feedstock undergoes heat exchange with the second reac-
tor product, combined with preheated recycle and makeup hydrogen,
and introduced into the first reactor. The first reactor product
is combined with preheated recycle and additional liquid recycle
and introduced into the second reactor. The product is exchanged
with feedstock, condensed, and separated to recover recycle
hydrogen. A second flash stage removes gases, and the liquid
product enters the fractionator, from which various product
streams are taken for blending or further processing. The bottom
Petroleum Refinery Enforcement Manual Overview
3/80 2-10
-------
product is recycled to the second reactor. Because this process
consumes hydrogen (200 to 350 volumes of hydrogen per volume of
feedstock), refineries often operate a hydrogen production facil-
ity onsite.
In the United States, about one-third of the hydrocracking
capacity is on the West Coast, where it is used to upgrade heavy
fuels to motor gasoline and jet fuel. Another one-third is on
the Gulf Coast, where it is used to alternate production of motor
gasoline and light distillates according to market demands.
2.3.3 Coking
Coking is a severe form of thermal cracking; it is an ulti-
mate-yield destructive distillation process that produces gas,
distillate, and coke from residuals that may resist cracking by
other methods. Although coke was earlier considered a low-value
byproduct, it is now used in electrode manufacture when sulfur
and metals contents are low enough. Coke with intermediate-range
sulfur content may be used as fuel for steam generator boilers.
There are two principal coking processes, delayed and fluid.
Delayed coking is the more widely used, and very few fluid coking
units are in service.
In the delayed coking process, the feedstock goes directly
to the fractionator. The lighter material is vaporized and
leaves the fractionator overhead. It is cooled and separated,
and the vapor phase is sent to the refinery fuel gas system.
Various sidestreams from the fractionator include naphtha and
light and heavy gas oils, which may be further processed. The
bottoms from the fractionator are pumped through a furnace to the
coking drums. Overhead from the coking drums flows back to the
fractionator and is recycled.
Coke forms on the coking drum walls and eventually fills the
drum. After a purging with steam, the drum is isolated and
opened; coke is broken free by high-pressure water jets. At
least two coking drums are provided so that one may be mechani-
cally or hydraulically decoked while the other is filling. These
Petroleum Refinery Enforcement Manual Overview
3/80 2-11
-------
drums are usually sized so that they can be decoked and returned
to service during one work shift. The coke particles are washed
out with water and separated from the water on vibrating screens.
In the fluid coking process, the feedstock enters the reac-
tor, where it is mixed with a fluidized bed of preheated recycled
coke particles. The hydrocarbons in the liquid feed crack and
vaporize, while the nonvolatile material is deposited on the
suspended coke particles. The coke particles thus grow larger,
sink to the bottom of the reactor, and flow to the burner. In the
burner, the particles are fluidized with air, partially burned,
and recycled to the reactor. A portion of the coke produced in
the reactor is withdrawn as product. The overhead vapor can be
desulfurized to yield fuel gas suitable for process heaters or
steam/power generation.
2.3.4 Visbreaking
Viscosity breaking, or "visbreaking," is a milder form of
thermal cracking than coking; it is used to reduce the viscosity
of some residual fractions so that they may be blended into fuel
oils. It is applied when the demand for middle distillates ex-
ceeds that for motor gasoline.
The atmospheric or vacuum-reduced crude is preheated by heat
exchange with visbroken fuel oil and fed to a furnace. Mild
cracking in furnace tubes produces a mixture of residual oil,
naphtha, and gas. The reaction products are quenched with a
recycle stream and sent to a fractionator, in which the vis-
breaker bottoms accumulate in the lower portion. A simple pump
system in the tower allows fractionation of the flashed vapors
into gas, gasoline, and light and heavy gas oils. The gas oil
sidestream normally flows through a steam-stripping tower for
separation of the motor gasoline fraction.
Petroleum Refinery Enforcement Manual Overview
3/80 2-12
-------
2.4 FORMATION PROCESSES
2.4.1 Catalytic Reforming
Catalytic reforming is used to alter the structure of satu-
rated straight-chain paraffins, which have very low octane num-
bers, to yield a different kind of molecule with much higher
octane characteristics. The process converts straight-carbon-
chain naphtha to a ring or branch-structured gasoline. Catalytic
reforming is also called platforming (when a platinum catalyst is
used), ultraforming, or magnaforming.
Catalytic reforming is a high-temperature, low-pressure,
fixed-bed process using a bimetallic catalyst. The most impor-
tant property of the catalyst is that which causes ring formation
and permits ring preservation in molecules that have just under-
gone partial dehydrogenation (aromatization). As would be ex-
pected with a substance as complex as crude oil, the process
reactions are numerous and complex. (A basic organic chemistry
text will explain these reactions in detail.) Table 2-2 presents
the major types of reactions that occur in catalytic reforming
units. Naphthene dehydrogenation, naphthene dehydroisomeriza-
tion, and paraffin isomerization are the predominant reactions.
The other reactions may become significant at high temperatures,
high pressures, and low-space velocities. Avoidance of hydro-
cracking is particularly important since it can lead to excessive
coke deposition, which deactivates the catalyst.
Compared with the feed, the final product contains a high
percentage of aromatic compounds and a small quantity of ali-
phatic hydrocarbons. Some of the aromatics (benzene, toluene,
and xylenes) may be isolated to become petrochemical feedstock,
but the major portion becomes motor gasoline blending stock.
Catalytic reforming units are regenerative or nonregenera-
tive. Regenerative reformers are the most common since they
operate at the low pressures that produce larger yields of high-
octane gasoline and also produce more hydrogen.
Petroleum Refinery Enforcement Manual Overview
3/80 2-13
-------
TABLE 2-2. MAJOR REACTIONS OCCURRING IN CATALYTIC REFORMING
NAPHTHENE DEHYDROGENATION
H,
CYCLOHEXANE
NAPHTHENE DEHYDROISOMERIZATION
H CH,
Hn
3H-
H'^f"H
H
BENZENE
H CH,
CH,
H
H
3H,
H'^f^H
H
"2 "2
1,2-DIMETHYLCYCLOPENTANE METHYLCYCLOHEXANE TOLUENE
PARAFFIN ISOMERIZATION CHO CH,
CH7-CH-CH-CH, + CH,-C-CH,-CH,
•J -J 3
,-,
L. J
CH,
CH,
n-HEXANE
2,3-DIMETHYLBUTANE NEOHEXANE
(2,2-DIMETHYLBUTANE)
PARAFFIN DEHYDROCYCLIZATION
CH3-CH2-CH2-CH2-CH2-CH3
n-HEXANE
PARAFFIN HYDROCRACKING
C10H22 + H2
n-DECANE
OLEFIN HYDROGENATION
H /L H
4Hn
H" ^Y "H
H
BENZENE
CH3-CH2-CH2-CH2-CH3
PENTANE
CH
ISOPENTANE
C5H10 + H2
PENTENE
HYDRODESULFURIZATION
nr fit
HU Ln
11 II
H H
ur ru + AU
rlL. Ln ~ *tn«
THIOPHENE
-* C5H12
PENTANE
» r H + ii c
• L4H1() + H2S
BUTANE
Petroleum Refinery Enforcement Manual
3/80 2-14
Overview
-------
Before entering the reforming unit, the naphtha feed is
hydrotreated to remove elements that may poison the reforming
catalyst. The hydrotreated naphtha is mixed with hydrogen from
the reformate stabilizer, exchanged with product streams, and
heated in a furnace. This feed mixture then passes through
several reactors. The charge is heated before entering each
reactor to compensate for the endothermic reactions that occur.
The final reactor effluent is cooled, and the gases are separated
from the liquid products. The gases may be recycled, sent to the
hydrogen recovery system, or sent to the plant fuel system.
The liquid products are sent to a stabilizer (tower). The
noncondensable overhead from the stabilizer goes to the fuel gas
system, and the condensable liquids are treated for recovery of
light ends. Bottoms from the stabilizer are the reformate prod-
uct, which is usually sent to gasoline blending.
So that a reactor may be regenerated, most reforming units
contain a spare ("swing") reactor, which is periodically placed
in service during the regeneration cycle. During regeneration,
the coke deposited on the catalyst is burned off by a carefully
controlled stream of inert gases and a limited amount of air.
The nonregenerative systems do not have a spare reactor;
instead, the unit is shut down when the catalyst is deactivated,
and the catalyst is replaced. In other respects operation of
these units is similar to that of regenerative reformers.
2.4.2 Alkylation
The alkylation process for production of high-octane gaso-
line resulted from the discovery that isoparaffin hydrocarbons
unite with olefins in the presence of a catalyst. The process
may involve isobutane and olefins, which produce high-octane
dimers or trimers. Table 2-3 summarizes some of the alkylation
reactions.
Sulfuric acids or hydrofluoric acid is used to catalyze the
alkylation reaction. The reactants are combined with rapid and
violent mixing into refrigerated liquid acid. The resultant
vapors are separated from the acid mixture, caustic washed, water
Petroleum Refinery Enforcement Manual Overview
3/80 2-15
-------
TABLE 2-3. SUMMARY OF REACTIONS OCCURRING IN ALKYLATION
CH3
CH3-CH-CH3
ETHYLENE ISOBUTANE
CH3 CH3
—* CH3-C-CH2-CH3 + CH3-CH-CH-CH3
CH3 CH3
NEOHEXANE 2,3-DIMETHYLBUTANE
(2,2-DIMETHYLBUTANE)
CH3-CH=CH-CH3
CH3
CH3-CH-CH3
CH, CH,
i J | J
-*• CH3-C-CH2-CH-CH3
CH,
2-BUTENE ISOBUTANE
(sym-DIMETHYLETHYLENE)
2,2,4-TRIMETHYLPENTANE
CH3-CH2-CH=CH3 +
1-BUTENE
(ETHYLETHYLENE)
CH3
i"u f"u Cu
CH,-CH-CH3
ISOBUTANE
2
CH3 CH3
*- CH,-C-CH,-CH-CH,
3 i e. J
CH,
2,2,4-TRIMETHYLPENTANE
CH3-CH-CH3
CH,-CH=CH,, + Yl
H'S^H
H
PROPYLENE BENZENE
H
H JL H
CH2=CH2 + X5 "
H
ETHYLENE BENZENE
H-v^yH
H'S^H
H
CUMENE
(ISOPROPYLBENZENE)
— xc
H
ETHYLBENZENE
Petroleum Refinery Enforcement Manual
1/XQ 2-16
•overview
-------
washed, and stabilized in a fractionation tower (debutanizer).
The tower bottoms are taken as alkylate, and the overhead vapors
are condensed and recycled. The tower also yields a normal
butane fraction.
2.4.3 Isomerization
As in catalytic reforming, the isomerization processes
rearrange the molecular structure of the feedstock while reducing
losses that normally occur in cracking or condensation reactions.
In the isomerization reactions nothing is added to or taken away
from the material. Formation of branched-chain compounds from
straight-chain compounds increases the octane number. The main
types of isomerization are butane, pentane, hexane, and xylene
isomerization.
Butane isomerization is closely linked with alkylation when
alkylate is required and isobutane is in short supply. Isobutane
is produced to provide feedstock for the alkylation unit. Build-
ing alkylation and isomerization units together permits sharing
of common distillation equipment. Isomerization of butanes is
increasing as a means of supplying petrochemical feedstock.
Isomerization of pentane and hexane yields products more suited
for motor gasoline blending stocks because they have desirable
antiknock properties. If a refinery is extracting paraxylene
from the catalytic reformate, the remaining orthoxylene and
metaxylene may be fed to an isomerization unit to produce para-
xylene. (Details of this type of isomerization are given in
Reference 2).
The butane isomerization process converts normal butane into
isobutane over a catalyst in the presence of hydrogen. A mixed
butane feedstock is fed into the deisobutanizer tower (distilla-
tion tower) from which isobutane product is taken overhead. The
bottoms undergo heat exchange with the reactor product after
recycle, and makeup hydrogen is added. The mixture is heated to
the reaction temperature in a furnace. Vaporized butanes enter
the fixed-bed catalytic reactor, undergo heat exchange with the
Petroleum Refinery Enforcement Manual Overview
3/80 2-17
-------
reactor feed, and are condensed; the reactor effluent flows to
the separator for recovery of recycle hydrogen. Separator liquid
is sent to the stabilizer, where overheads are condensed and
noncondensables flow to the refinery gas system. Stabilizer
bottoms go to the deisobutanizer, where the overhead is the
product isobutane.
2.4.4 Polymerization
Polymerization is the combining of monomers. In a refinery
operation, propylene (olefin; monomer) would be polymerized to
yield dimer (2-propylenes), trimer (3-propylenes), tetramer (4-
propylenes) and perhaps higher order polymers.
This process is used very rarely in refineries today. It
was first introduced to provide a motor gasoline blending stock
when octane levels were very low. The octane gain from blending
of polymer (poly) gasoline was soon replaced by blending of
alkylate from alkylation units. Polymers are valuable in some
applications, however, such as additives for motor oil.
A refinery stream of propylene and butylenes is mixed with
recycle propane and water, subjected to heat exchange with reac-
tor product, preheated, and introduced into the top of a multi-
ple-fixed-bed reactor. Solid phosphoric acid deposited on an
inert carrier is the catalyst. Water is injected between the
several fixed beds for temperature control. The reactor product
is cooled by heat exchange with feed and sent to the depropanizer
(distillation tower). The overhead product is recycled to the
reactor feed. Bottom material is debutanized in a distillation
tower, from which butane goes overhead and polymer gasoline is
taken as bottoms.
2.5 TREATING PROCESSES
The objective of all petroleum refinery treatment of inter-
mediate fractions or products is to remove or render inactive
Petroleum Refinery Enforcement Manual Overview
3/80 2-18
-------
compounds that would otherwise reduce the quality of these frac-
tions or products. Treating is particularly important for remov-
ing sulfur, nitrogen, and metal compounds from feed for a cata-
lytic cracker or catalytic reformer. If these compounds were not
removed, they would attack the catalyst. Therefore, this treat-
ment both improves performance and lengthens catalyst life.
Refinery treating processes can be classified as catalytic
or chemical. Several processes can be applied, depending upon
the content of undesirable compounds and the required severity of
the treatment. The vent or waste gas streams from the treating
processes usually contain the hydrogenated form of the undesir-
able compound. These streams can be sent to the sulfur recovery
process or the refinery fuel system.
2.5.1 Catalytic Treating
Hydrotreating is the most widely used process for all types
of petroleum products. With the appropriate catalyst and operat-
ing conditions, hydrotreating can desulfurize, eliminate other
impurities such as nitrogen and oxygen, decolorize and stabilize,
and correct odor problems and many other product deficiencies.
Hydrodesulfurization processes convert the sulfur in sulfur
compounds into more easily removed hydrogen sulfide (H2S) by use
of rugged catalysts and hydrogen. The processes also convert
some nitrogen compounds into ammonia.
Other hydrogenation or hydrotreating processes (not intended
primarily to attack sulfur) saturate olefinic materials, which
are undesirable in many refinery products. For example, certain
cracked gasoline stocks contain hydrocarbons that tend to poly-
merize (form gums) upon exposure to air. These can be stabilized
by a mild catalytic hydrotreating process.
2.5.2 Chemical Processes
Chemical treating processes scrub fractions with inorganic
acids such as sulfuric acid (H2S04) and bases such as sodium
hydroxide (NaOH) to remove undesirable acids and sulfur com-
pounds. Certain chemical treating processes use proprietary
Petroleum Refinery Enforcement Manual Overview
3/80 2-19
-------
chemicals to remove specific impurities and improve the quality
and/or performance of petroleum products.
Acid gas removal processes bring feed streams into contact
with a selective solvent or absorbent. These materials absorb
the acid gases (normally hydrogen sulfide); they are regenerated
by stripping and then recycled. The stripped acid gases are
disposed of either in the sulfur recovery unit or by incinera-
tion. The sulfur recovery process (Claus unit) is preferred
because it minimizes emissions.
Many processes are commercially available to perform all
types of treating operations. The Bibliography gives literature
references in the categories of acid gas removal, chemical sweet-
ening, hydrotreating, and hydrodesulfurization processes.
2.6 RECOVERY OPERATIONS
2.6.1 Sulfur Recovery
Sulfur compounds in petroleum fractions are converted into
H2S by treating processes. This H2S is collected and sent to the
sulfur recovery plant (Claus unit).
In the Claus unit, H2S is burned with air to form elemental
sulfur. The overall chemical reaction is:
2H2S + 02 -» 2S + 2H20
The reaction is normally conducted in stages in which part of the
H2S is oxidized with air to form S0?, as follows:
H2S + 3/2 02 -»• S02 + H20
This S02 is combined with the remaining H~S over a fixed-bed
catalyst to complete the reaction:
S02 + 2H2S -» 3S + 2H20
A number of catalytic stages can be used to increase the sulfur
recovery and reduce S02 emissions.
Final exhaust gases may contain sulfur carbonyls, carbon
disulfide (CS2), H2S, and some elemental sulfur. These are
Petroleum Refinery Enforcement Manual Overview
3/80 2-20
-------
normally incinerated at high temperature in a tail gas unit, and
the exhaust gas contains only small quantities of SO-.
2.6.2 Fuel Gas Recovery
The fuel gas plant incorporates a system of operations for
recovering useful hydrocarbon vapor mixtures from the crude oil
distillation unit and other refinery processes. While adding
value to the overall refinery process, the recovery process also
prevents hydrocarbon losses and emissions. A well-operated gas
recovery system is essential to the overall economics of petro-
leum refining.
Vapors (noncondensable gases) from the crude distillation
towers, the reformers, and the catalytic cracking units are
collected and sent to the gas processing unit for light-ends
recovery. The gases are compressed, condensed, and distilled
(separated) into various mixtures having constant vapor pressure.
These mixtures may be used as refinery fuel (burned in fired
heaters and boilers), sold as liquefied petroluem gases, used as
feedstock for hydrogen production, used as alkylation feedstock,
or sold as petrochemical feedstock.
2.7 STORAGE
All refineries use tanks and vessels for storage of feed-
stocks (crude oil, pressurized liquid hydrocarbons, etc.) and of
intermediate products awaiting further processing and/or blend-
ing. A certain amount of lower volume storage within the pro-
cessing area is referred to as "rundown tankage." Tankage is
also provided for finished products awaiting shipment and for use
in loading and unloading operations.
2.8 AUXILIARY FACILITIES
A refinery requires many auxiliary facilities, which can
include those for steam generation, production of electrical
power, wastewater treatment, and hydrogen production, as well as
Petroleum Refinery Enforcement Manual Overview
3/80 2-21
-------
cooling towers and blowdown systems (including flares and liquid
incineration).
Many large refineries now generate some of their own elec-
trical power. Steam leaving turbines goes into refinery steam
systems at various pressure levels.
Wastewater treatment systems can range from a simple API
separator to very elaborate biological treatment systems. All
water streams are treated to meet environmental standards as well
as to recover various products.
Process water is recirculated and cooled to the specified
temperatures in cooling towers. Air coolers are being used with
increasing frequency to reduce requirements for cooling water.
Because product treating processes require hydrogen, the
hydrogen production facilities are often considered as auxiliary
or utility systems.
Blowdown systems receive releases of liquid and gaseous
streams from emergency vents and safety valves. These systems
entail collection, separation, and disposition by a flare or
incinerator.
2.9 CHARACTERIZATION OF THE PETROLEUM REFINING INDUSTRY
2.9.1 Statistical Summary of the Industry
A tabulation of the refineries in the United States (current
as of January 1979) is given in Appendix A. The tables in this
appendix indicate refinery capacity; location, including the
number of the U.S. EPA Air Quality Control Region (AQCR); and the
attainment status for photochemical oxidants of the area in which
each refinery is located. The tables are arranged by state
according to EPA region. The appendix includes a table for each
region, summarizing the total number of refineries and their
combined capacity in each state in the region.
Table 2-4 lists the total number of refineries, the number
of refineries in photochemical oxidant nonattainment areas, and
Petroleum Refinery Enforcement Manual Overview
3/80 2-22
-------
co
\
oo
o
TABLE 2-4. SUMMARY OF OPERATING REFINERIES IN THE UNITED STATES1
EPA
Region
I
II
III
IV
V
VI
VII
VIII
IX
X
Total
Number of
refineries
1
11
16
21
40
108
13
34
46
12
302
Total capacities,
bbl/day
13,400
1,790,820
1,028,660
699,800
2,841,398
7,541,560
571,339
642,898
2,537,420
477,500
18,144,795
Refineries in
attainment
areas
0
4
3
14
10
54
11
25
5
7
133
Refineries in
nonattainment
areas
1
7
13
7
30
54
2
9
41
5
169
CD
»
fD
H-
3
fD
M
3
Hi
O
fD
fD
MS
o
As of January 1979
^Attainment of standards for photochemical oxidants.
H-
(D
-------
the combined refining capacities for each EPA region and for the
country as a whole.
There are 302 refineries operating in the United States, 169
of which are located in nonattainment areas for photochemical
oxidants. The total national refining capacity is estimated at
18,144,795 barrels per day (BPD). Approximately half of the
refineries in Region VI are in oxidant nonattainment areas.
Region IX ranks second in number of refineries, most of which are
in California and all of which are in oxidant nonattainment
areas. The other regions in decreasing order of number of refin-
eries in oxidant nonattainment areas are Regions V, III, VIII,
IV, II, X, VII, and I.
The Standard Industrial Classification (SIC) code 2911,
"Petroleum Refineries," is the criterion for inclusion in this
tabulation.
2.9.2 Trends In The Industry
During collection of information for this manual some
trends, or potential trends, related to corporate structure in
the refining industry were noted.
One trend is the diversification in ownership of refineries,
which is done for various reasons. As an example, operators of a
relatively complex refinery may wish to increase the capacity for
crude distillation by installing a new atmospheric distillation
column. To avoid being subject to a Prevention of Significant
Deterioration (PSD) review, the refinery officials may form a new
company to build the unit, because small refineries are exempt
from some PSD conditions. The new company buys property on or
near the site of the larger original refinery and constructs the
new atmospheric distillation unit and perhaps accessory storage
tanks. This constitutes a new refinery, which will sell most or
all of its products to the neighboring, larger refinery. In
essence this increases the capacity of the larger refinery, but
the small refinery is exempt from certain regulations. Personnel
Petroleum Refinery Enforcement Manual Overview
3/80 2-24
-------
of the larger refinery may actually operate units and equipment
of the newly created, smaller refinery.
Financial advantages other than those involved in circum-
venting regulations also encourage diversification of ownership.
Such advantages relate primarily to income tax, depreciation of
equipment, and financing. As an example, a company may need a
new, expensive item of equipment but prefer not to increase its
liabilities because doing so will lower the bond rating. The
owners then form a second company, which purchases the needed
equipment and leases it to the original company. Thus, the bond
rating is not affected.
Another form of diversification is the formation within a
large petroleum corporation of a specialized company whose busi-
ness is the treatment and disposal of refinery and petrochemical
wastes. A similar potential trend is the hiring of outside
companies to undertake wastewater disposal or wastewater treat-
ment. This trend is significant in enforcement of requirements
for reasonably available control technology (RACT) for wastewater
separators. Even though the refineries that engage wastewater
treatment companies remove their oily water from the refinery
premises, the volatile organic compounds (VOC) in the water still
must be controlled. Some refineries have partially divorced
themselves from responsibility for some emissions by using dis-
posal companies. Such practices of diversification in ownership
are followed in several regions of the United States.
Another trend is the addition of distillation columns to
bulk storage terminals. This results in a change in classifica-
tion from petroleum storage to petroleum refining. All of these
trends are significant, because EPA personnel must keep abreast
of and maintain files on these new, small refineries in order to
enforce regulations. Changes in classification of facilities
that have been diversified must be identified and recorded.
Trends in the total number and average size of refineries in
the United States are noted in Table 2-5. The total throughput
of crude oil has increased yearly since 1965 and average capacity
Petroleum Refinery Enforcement Manual Overview
3/80 2-25
-------
TABLE 2-5. OPERATING REFINERIES AND CRUDE OIL THROUGHPUT'
Year
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Number of
operating
refineries
265
261
269
263
262
253
247
247
247
259
256
266
285
289
Crude oil throughput,
barrels per stream day
10,721,550
10,952,495
11,657,975
12,079,201
12,651,375
13,284,985
13,709,442
13,991,580
14,876,650
15,463,650
15,687,321
16,912,596
17,618,955
17,169,909
Average capacity,
barrels per stream day
40,459
41,964
43,338
45,929
48,288
52,510
55,504
56,646
60,229
59,705
61,289
63,581
61,821
59,411
Petroleum Refinery Enforcement Manual
3/80 2-26
Overview
-------
increased from 1965 through 1973. The total number of refiner-
ies, however, decreased during the same period. This decrease
apparently was caused by the inability of independent refiners to
compete with the expanding major oil companies. ("Major" and
"independent" are arbitrary designations for the 20 or so largest
and all smaller petroleum refining companies, respectively.) The
entitlements program of the U.S. Department of Energy (DOE)
(instituted in 1973 by the Federal Energy Administration) was
established to help reverse this trend.
The entitlements program has resulted in a tendency toward
construction of smaller refineries. The purpose of the program
is to protect independent, small refiners by ensuring that large
refiners having access to cheaper, domestic crude do not gain an
advantage over small refiners not having the same access. Refin-
ers processing less than 10,000 barrels per day of crude oil are
the most heavily subsidized group in the entitlements program.
The effect of this program can be seen by the sharp increase in
the number of new, small refiners coming onstream in 1974 and
A.
after.
The average capacity per refinery did not rise as sharply
from the end of 1973 through 1977 as it had during other 4-year
time periods, an indication that the recent trend is toward
building refineries of low capacity. The addition of many small
refineries does not account for all of the increases in total
crude throughput since 1974. Expansion of existing refineries
has continued, and not all oil companies are diversifying and
establishing new, smaller companies for each expansion. Nonethe-
less, the declining rate of increases in average capacities and
the increasing number of refineries demonstrate an industrywide
tendency to construct small refineries.
2.10 REFERENCES
1. Petrochemical Handbook Issue. Petroleum Refiner, 38(11),
November 1960.
Petroleum Refinery Enforcement Manual Overview
3/80 2-27
-------
2. 1977 Petrochemical Handbook Issue. Hydrocarbon Processing,
56(11):237-239, November 1977.
3. R. F. Boland, et al. Screening Study for Miscellaneous
Sources of Hydrocarbon Emissions in Petroleum Refineries.
EPA-450/3-76-041, December 1976.
4. Prescott, J. H. Small Is In, Big Is Out in Oil-Refining
World. Chemical Engineering, October 10, 1977, pp. 80-84.
Petroleum Refinery Enforcement Manual Overview
3/80 2-28
-------
REGULATION
-------
SECTION 3
REGULATIONS
3.1 INTRODUCTION
This section of the manual discusses some of the regulations
that the inspector will enforce. The inspector should obtain a
copy of all applicable regulations and become familiar with them
before any enforcement inspection.
3.2 BACKGROUND
The Clean Air Act of 1970 is based on a two-component air
resource management strategy. The first component consists of
the national ambient air quality standards (NAAQS), which were
established for a number of pollutants and were to be implemented
over the whole Nation. The standards were set on two levels:
primary standards established the maximum allowable concentra-
tions of pollutants in the atmosphere to protect public health;
secondary standards set the safety margin concentration level.
The concentration levels were established to protect the public
"from any known or anticipated adverse effects."
The second component of the Clean Air Act set emission
standards. These standards were established so that emissions
throughout the United States would be reduced enough to meet at
least the primary NAAQS by 1975. The emission standards were set
nationally by EPA and locally by each state for new sources, and
were set by each state for existing sources.
Congress began preparing new legislation in 1975 when the
primary NAAQS had not been met and evidently would not be met by
1977, when the 2-year extension elapsed. The new legislation,
the Clean Air Act Amendments of 1977 (CAAA), was based on the
Petroleum Refinery Enforcement Manual Regulations
3/80 3-1
-------
two-component system of the original act; however, it placed new
emphasis on the regulation concerning new or expanding plants.
The CAAA substantially changed the criteria for obtaining permits
for new or expanding plants. In setting these standards, known
as the New Source Performance Standards (NSPS), the Act required
EPA to impose strict standards without forcing massive shutdowns
in existing facilities.
3.3 NEW SOURCE PERFORMANCE STANDARDS
NSPS applicable to refineries are contained in subparts J
and K of "Standards of Performance For New Stationary Sources."
Subpart J includes standards for fluid catalytic cracking (FCC)
catalyst regenerators, fuel gas combustion devices, and Claus
sulfur recovery plants. The Claus process is the most widely
used method for extraction of sulfur from acid gases (see Sec-
tion 4.16 for a detailed description). Subpart K includes stand-
ards for storage facilities for volatile organic compounds (VOC).
Any FCC catalyst regenerator that was built or modified
after June 11, 1973, is subject to NSPS. The specific emissions
standards are as follows:
Particulates: 1.0 kg/1000 kg of coke burnoff
Opacity: 30 percent
Carbon monoxide: 0.050 percent by volume
Particulate emissions may exceed this level if the gases pass
through a waste heat boiler or incinerator. The incremental
increase cannot, however, exceed 43.0 g/MJ (0.10 Ib/million Btu)
of heat input that is attributable to any auxiliary fuel burned.
The 30 percent opacity limitation may be exceeded for one 6-min-
ute period in any 1 hour.
Any fuel gas combustion device (heater) that is built or
modified after June 11, 1973, must burn fuel with a hydrogen
sulfide (H2S) content less than 230 mg/dscm (0.10 gr/dscf). The
H2S content of fuel gas may exceed this level if the gases from
Petroleum Refinery Enforcement Manual Regulations
3/80 3-2
-------
the combustion are treated to reduce sulfur dioxide (S02) emis-
sions.
Any Claus sulfur recovery unit that is built or modified
after October 4, 1976, is subject to emission levels based on the
control methods used. If emissions are controlled by an oxida-
tion or a reduction control system followed by incineration, the
unit may not emit more than 0.025 percent by volume of S09 at
fit
zero percent oxygen (dry basis). If emissions are controlled by
a reduction control system not followed by incineration, the unit
may not emit more than 0.030 percent by volume of reduced sulfur
compounds and 0.0010 percent by volume of H2S calculated as S02
at zero percent oxygen (dry basis).
Subpart K of NSPS applies only to storage vessels having
capacities greater than 151,416 liters (40,000 gallons or 952
barrels) and containing volatile organic compounds. If tank
capacity is between 151,416 and 245,000 liters (40,000 to 65,000
gallons or 952 to 1548 barrels), the standard is enforceable
for tanks built or modified after March 8, 1974. If tank capa-
city is greater than 245,000 liters (65,000 gallons), the stand-
ard is enforceable for tanks built or modified after June 11,
1973.
The standard for storage vessels is in two parts. If the
true vapor pressure of the stored material is greater than 10.5
kPa (kilo Pascals) (1.5 psia) but less than or equal to 77 kPa
(11.1 psia), the vessel must be equipped with a floating roof, a
vapor recovery system, or their equivalents. If the true vapor
pressure of the stored material exceeds 77 kPa (11.1 psia), the
tank must be equipped with a vapor recovery system.
NSPS include some special provisions for Claus plants. The
standards do not apply to plants with a capacity of 20 long tons
per day or less and associated with a small petroleum refinery.
[A small petroleum refinery is defined as one with a crude oil
processing capacity of 7.9 million liters (5.0,000 barrels) or
less per stream day and that is owned or controlled by a refinery
with a total combined crude oil processing capacity of 21.8
Petroleum Refinery Enforcement Manual Regulations
3/80 3-3
-------
million liters (137,500 barrels) or less per stream day.] Also,
the Glaus plant need not be physically located within the boun-
daries of a petroleum refinery to be an affected facility, pro-
vided it processes gases produced within a petroleum refinery.
3.4 PREVENTION OF SIGNIFICANT AIR QUALITY DETERIORATION
On December 5, 1974, EPA published regulations under the
1970 version of the Clean Air Act for the prevention of signifi-
cant air quality deterioration (PSD). These regulations estab-
lished a program for protecting areas having air quality cleaner
than the national ambient air quality standards (NAAQS).
Under EPA's regulatory program, clean areas could be desig-
nated under any of three classes. Specified numerical increments
of air pollution were permitted under each class up to a level
considered to be significant for that area. Class I increments
permitted only minor air quality deterioration; Class II incre-
ments, moderate deterioration; Class III increments, deteri-
oration up to the secondary NAAQS.
EPA initially designated all clean areas as Class II.
States, Indian governing bodies, and Federal land managers were
-given authority to redesignate their lands under specified proce-
dures. The area classification system was administered and
enforced through a preconstruction permit program for 19 speci-
fied types of stationary air pollution sources. This precon-
struction review, in addition to limiting future air quality
deterioration, required any source subject to the requirements to
apply best available control technology (BACT) (see Section 3.4.3
for definition of BACT).
On August 7, 1977, the Clean Air Act Amendments of 1977
became law. The 1977 amendments changed the 1970 act and EPA's
regulations in many respects, particularly with regard to PSD.
In addition to mandating certain immediately effective changes to
the PSD regulations, the amended Clean Air Act contained compre-
hensive new PSD requirements. These regulations, which are more
Petroleum Refinery Enforcement Manual Regulations
3/80 3-4
-------
stringent, are contained in 40 CFR 52.21, SUPPLEMENT 1 (Federal
Register, Vol. 43, No. 118, Monday, June 19, 1978, Part V).
The sources that are subject to PSD regulations include the
following:
Any stationary source listed in Table 3-1 that emits, or has
the potential to emit, 91 Mg/yr (100 tons/yr) of any air
pollutant regulated under the Clean Air Act. (See Section
3.4.3 for emissions definitions.)
Any source that emits, or has the potential to emit,
227 Mg/yr (250 tons/yr) or more of any air pollutant regu-
lated under the Clean Air Act.
The two types of PSD reviews are TIER I and TIER II. TIER I
is an abbreviated review, intended for smaller sources of air
pollutants that have a proportionately smaller impact on air
quality. TIER II is a more intensive review, intended for larger
and more significant sources of air pollutants.
3.4.1 TIER I Review
The applicant must demonstrate that the requirements for all
applicable State Implementation Plans (SIP), NSPS, and
National Emissions Standards for Hazardous Air Pollutants
(NESHAPS) have been met. This demonstration may be accom-
plished by presenting an enforceable SIP permit.
Allowable emissions (see Section 3.4.3) from the source must
be less than 45 Mg/yr, 454 kg/day, or 45 kg/h (50 tons/yr
1000 Ib/day, or 100 Ib/h).
The source must not have an impact on a Class I area or an
area where the applicable increment is known to be violated.
If there is doubt about this requirement, the applicant
should contact the EPA regional office.
The data sheets in Appendix I list source information re-
quired to determine if PSD regulations apply and to conduct
TIER I reviews.
3.4.2 TIER II Review
If allowable emissions from a source are equal to or greater
than 45 Mg/yr (50 ton/yr), 454 kg/day (1000 Ib/day), or 45 kg/h
(100 Ib/h), the source is given a TIER II review. This review
Petroleum Refinery Enforcement Manual Regulations
3/80 3-5
-------
TABLE 3-1. SOURCES SUBJECT TO PSD REVIEW
Fossil-fuel-fired steam electric plants of more than 264 million MJ/h
(250 million Btu/h) heat input
Kraft pulp mills
Portland cement plants
Primary zinc smelters
Iron and steel mill plants
Primary aluminum ore reduction plants
Primary copper smelters
Municipal incinerators capable of charging more than 227 metric tons
(250 tons) of refuse per day
Sintering plants
Chemical process plants
Fossil-fuel-fired boilers (or combinations thereof) totaling more than
264 million MJ/h (250 million Btu/h) heat input.
Hydrofluoric acid plants
Sulfur acid plants
Petroleum refineries
Lime plants
Phosphate rock processing plants
Coke oven batteries
Sulfur recovery plants
Carbon black plants (furnace process)
Primary lead smelters
Fuel conversion plants
Secondary metal production plants
Petroleum storage and transfer units with a total storage capacity
exceeding 48 million liters (300,000 barrels or 12.6 million gallons)
Charcoal production plants
Taconite ore processing plants
Glass fiber processing plants
Nitric acid plants
Petroleum Refinery Enforcement Manual Regulations
3/80 3-6
-------
has two parts: a control technology review and an air quality
review.
Control Technology Review—
In the first phase of a Tier II review, the applicant must
demonstrate that he is applying best available control techno-
logy. To accomplish this, the applicant must prepare a BACT
presentation for each applicable pollutant. This includes the
data requirements for precipitators, baghouses, and S0~ scrub-
bers.
If, after BACT is applied, allowable emissions are equal to
or greater than 45 Mg/yr (50 ton/yr), 454 kg/day (1000 Ib/day),
or 45 kg/h (100 Ib/h), an Air Quality Impact Analysis must be
made.
Air Quality Review—
The applicant must demonstrate that the allowable emission
increases from the proposed source or modification will not cause
a violation of either of the following:
Any national ambient air quality standard in any air quality
control region.
Any applicable maximum allowable increase over the baseline
concentration in any area (see Section 3.4.3).
To meet these requirements, the applicant must submit an
analysis of the impact of the proposed source on the NAAQS and
the PSD increment. The analysis must be supported with the data
needed to estimate air quality impact, including data on meteo-
rology, topography, source emissions, and air quality.
As part of the analysis, the applicant must describe the air
quality impacts and the nature and extent of any or all general,
commercial, residential, industrial, and other growth in the
impact area since the baseline date of August 7, 1977.
Preliminary screening techniques can be used to determine
whether full-scale modeling is necessary. For screening pur-
poses, conservative estimates of emission characteristics and
ambient impacts are modeled using relatively straightforward
Petroleum Refinery Enforcement Manual Regulations
3/80 3-7
-------
formulas. If screening procedures indicate that ambient concen-
trations would exceed one-half of the remaining ambient increment
or ceiling allowance, more refined techniques are used.
Any permit application submitted after August 7, 1978, must
include an analysis of air quality monitoring data for any pollu-
tant emitted by the source or modification for which an NAAQS
exists, except nonmethane hydrocarbons. The monitoring data may
be required for a period of up to 1 year.
Air quality data are used to determine whether emissions
from the proposed source or modification would cause a violation
of the NAAQS. Existing data are used to the maximum extent
practicable, and preconstruction monitoring is required only as
necessary. In general, monitoring data are not to be used to
determine how much of the available increment has been consumed.
The applicant is required to include an analysis of the
impairment to visibility, soils, and vegetation that would occur
as a result of the source or modification and the general commer-
cial, residential, industrial, and other growth associated with
the source or modification.
The data sheets in Appendix I list source information re-
quired for a TIER II review.
3.4.3 Definitions
The following definitions are found in the regulations on
prevention of significant deterioration (40 CFR 51.24, July 1,
1979).
Allowable emissions means the emission rate calculated using
the maximum rated capacity of the source (unless the source
is subject to enforceable permit conditions that limit the
operating rate or hours of operation, or both) and the most
stringent of the following: (i) Applicable standards as
set forth in 40 CFR, Part 60 and Part 61; or (ii) The
applicable state implementation plan emission limitation; or
(iii) The emission rate specified as a permit condition
[Section 5.24 (b) (17)].
Baseline concentration means that ambient concentration
level reflecting actual air quality as of August 7, 1977,
minus any contribution from major stationary sources and
Petroleum Refinery Enforcement Manual Regulations
3/80 3-8
-------
major modifications on which construction commenced on or
after January 6, 1975. The baseline concentration shall
include contributions from: (i) The actual emissions of
other sources in existence on August 7, 1977, except that
contributions from facilities within such existing sources
for which a plan revision proposing less restrictive re-
quirements was submitted on or before August 7, 1977, and
was pending action by the Administrator on that date shall
be determined from the allowable emissions of such facili-
ties under the plant as revised; and (ii) The allowable
emissions of major stationary sources and major modifica-
tions which commenced construction before January 6, 1975,
but were not in operation by August 7, 1977. [Section 51.24
(b) (11)]
Best available control technology means an emission limita-
tion (including a visible emission standard) based on the
maximum degree of reduction for each pollutant subject to
regulation under the act which would be emitted from any
proposed major stationary source or major modification which
the Administrator, on a case~by=case basis, taking into
account energy, environmental, and economic impacts and
other costs, determines is achievable for such source or
modification through application of production processes or
available methods, systems, and techniques for control of
such pollutant. In no event shall application of best
available control technology result in emissions of any
pollutant which would exceed the emissions allowed by any
applicable standard under 40 CFR, Part 60 and Part 61. If
the Administrator determines that technological or economic
limitations on the application of measurement methodology to
a particular class of sources would make the imposition of
an emission standard infeasible, a design, equipment, work
practice or operational standard, or combination thereof,
may be prescribed instead to require the application of best
available control technology. Such standard shall, to the
degree possible, set forth the emission reduction achievable
by implementation of such design, equipment, work practice
or operation, and shall provide for compliance by means
which achieve equivalent results. [Section 51.24 (b) (10)]
Potential to emit means the capability, at maximum capacity,
to emit a pollutant in the absence of air pollution control
equipment. Air pollution control equipment includes control
equipment which is not, aside from air pollution control
laws and regulations, vital to production of the normal
product of the source or to its normal operation. Annual
potential shall be based on the maximum annual rated capa-
city of the source, unless the source is subject to enforce-
able permit conditions which limit the annual hours of
operation. Enforceable permit conditions on the type or
Petroleum Refinery Enforcement Manual Regulations
3/80 3=9
-------
amount of materials combusted or processed may be used in
determining the potential emission rate of a source.
3.4.4 Proposed Changes to PSD Regulations
EPA has proposed to change the PSD regulations in response
to a court decision (Alabama Power Company vs. Costle, June 18,
1979) that overturned those regulations in major respects. The
thrust of the proposed changes includes major changes in the
definitions of baseline concentration and potential emissions and
the elimination of the TIER system of PSD review.
Within the definition of baseline concentration, the base-
line date is proposed to be changed from August 7, 1977, to the
date of the first completed application after August 7, 1977, for
every part of an Air Quality Control Region designated as unclas-
sifiable or as an attainment area. Within the definition of
potential emissions, potential to emit is proposed to be changed
from "in the absence of air pollution control equipment" to "in
the presence of air pollution control equipment." Annual poten-
tial is proposed now to ignore any permit conditions that limit
the annual hours of operation and consider each source as operat-
ing 8760 hours per year. These changes in definitions substan-
tially change the implications of the original regulations.
The proposed regulations would exempt on a pollutant-speci-
fic basis major modifications from all permit requirements and
new major sources on a pollutant-specific basis from all require-
ments when emissions of the particular pollutant are below a
specified "de minimis" or significant emission rate. Table 3-2
(Table 1 in the proposed changes and so referred to in this
report) lists the "de minimis" emission rates.
Table 1 would have two principal uses. First, it would be
used to show that the net increase associated with a modification
would be "de minimis" for all pollutants for which the source is
major. A showing for all regulated pollutants for which the
source is major would be required of modifications at major sta-
tionary sources in PSD areas. A successful showing would exempt
a modification from PSD requirements. Such a source would,
Petroleum Refinery Enforcement Manual Regulations
3/80 3-10
-------
TABLE 3-2. .GUIDELINES FOR SIGNIFICANT EMISSION RATES
(TABLE 1 IN PROPOSED CHANGES)
Pollutant
Carbon monoxide
Nitrogen dioxide
Total suspended parti culates
Sulfur dioxide
Ozone
Lead
Mercury
Beryllium
Asbestos
Fluorides
Sulfuric acid mist
Vinyl chloride
Total reduced sulfur:
Hydrogen sulfide
Methyl mercaptan
Dimethyl sulfide
Dimethyl di sulfide
Reduced sulfur compounds:
Hydrogen sulfide
Carbon disulfide
Carbonyl sulfide
Emission rate, tons/yr
100
10
10
10
10
1
2
0.004
1
0.02
1
1
1
1
1
1
1
10
10
Petroleum Refinery Enforcement Manual
3/80 3-11
Regulations
-------
however, be required to provide notice to the Administrator and,
therein, make the "de minimis" demonstration. The proposed
regulations incorporate the "de minimis" concept by requiring
that major modifications have a significant net increase in
potential emissions.
Even if a modification cannot be shown to be minor, Table 1
can be used to limit the pollutants for which BACT must be ap-
plied or an air quality analysis done. If a modification to a
source is subject to review because it results in a significant
net increase in potential emissions of a pollutant for which the
source is major, or if a new source is subject to review because
it will have the potential to emit a regulated pollutant in major
amounts, the source may still avoid BACT or an air quality analy-
sis for other pollutants it emits if it emits such pollutants in
"de minimis" amounts. Table 1 identifies the emission cutoffs
that would trigger the need for control technology and ambient
review for those other pollutants. Thus, when a major stationary
source or modification is subject to PSD review because of poten-
tial emissions of one or more pollutants, the review would apply
to only those other pollutants that the source would have the
potential to emit in amounts above those proposed in Table 1.
Table 3-3 (Table 2 in the proposed changes and so referred
to in this report) is proposed as an additional mechanism to
limit the air quality review for pollutants that the source would
have the potential to emit in significant amounts but that have
an insignificant ambient impact. Table 2 does not apply to
pollutants that a new major source would emit in excess of the
applicable threshold of 90/227 Mg, nor does it apply to major
construction that would be located in a nonattainment area or
would adversely impact a Class 1 area.
3.5 REASONABLY AVAILABLE CONTROL TECHNOLOGY
In October and December 1977 and in June 1978, EPA promul-
gated control technique guidelines (CTG) for process unit turn-
arounds, storage tanks, vacuum-producing systems, wastewater
Petroleum Refinery Enforcement Manual Regulations
3/80 3-12
-------
TABLE 3-3. GUIDELINES FOR SIGNIFICANT AMBIENT AIR QUALITY IMPACTS
(TABLE 2 IN PROPOSED CHANGES)
Pollutant
Carbon monoxide
Nitrogen dioxide
Total suspended particulates
Sulfur dioxide
Lead
Mercury
Beryllium
Asbestos
Fluorides
Sulfuric acid mist
Vinyl chloride
Total reduced sulfur:
Hydrogen sulfide
Methyl mercaptan
Dimethyl sulfide
Dimethyl disulfide
Reduced sulfur compounds:
Hydrogen sulfide
Carbon disulfide
Carbonyl sulfide
Air quality impact
500 pg/m3, 8-hour avg.
1 pg/m3, annual
5 pg/m3, 24-hour
5 pg/m3, 24-hour
0.03 pg/m3, 3-month
0.1 pg/m3, 24-hour
0.005 pg/m3, 24-hour
1 pg/m3, 1-hour
0.01 pg/m3, 24-hour
1 pg/m3, 24-hour
1 pg/m3
maximum value
1 pg/m3, 1-hour
°'5 ^/m3, 1-hour
0.5 pg/m3, 1-hour
2 pg/m3, 1-hour
1 pg/m3, 1-hour
200 pg/m3, 1-hour
200 pg/m3, 1-hour
Petroleum Refinery Enforcement Manual
3/80 3-13
Regulations
-------
separators, and fugitive emissions. Annual nationwide emissions
of volatile organic compounds (VOC) from these sources are esti-
mated to be 1.46 million Mg (1.6 million tons), which represents
approximately 6.7 percent of the total VOC emitted from station-
ary sources. The overview of reasonably available control tech-
nology (RACT) requirements for petroleum refineries is based on a
literal interpretation of the CTG and a discussion between PEDCo
personnel and a representative of EPA's Office of Air Quality
Planning and Standards (OAQPS).
3.5.1 Process Unit Turnarounds
Refinery units are periodically shut down and emptied for
internal inspection and maintenance. The procedure of shutting
down a unit, repairing or inspecting it, and restarting it is
termed "unit turnaround." The CTG do not set specific practices
to be followed during turnarounds but do recommend depressurizing
process units to 137.9 kPa (5 psig) before atmospheric venting.
In a typical process unit turnaround, liquid contents are
pumped from the vessel to some available storage facility. The
vessel is then depressurized; flushed with water, steam, or
nitrogen; and ventilated. The major potential for VOC emissions
occurs when the vessel is depressurized by venting the hydrocar-
bon vapors to the atmosphere. Incineration of vapors in a flare
or as fuel gas (until the pressure in the vessel is as close as
practicable to atmospheric pressure) greatly reduces VOC emis-
sions to the atmosphere and complies with RACT requirements. The
pressure at which the vapors are vented to the atmosphere depends
on the pressure of the disposal system. Many refineries, how-
ever, should be able to depressurize process units to 137.9 kPa
(5 psig) before atmospheric venting (as recommended in the CTG)
without significant process changes. At some refineries the
safety relief valves and blowdown systems may require modifi-
cation.
Petroleum Refinery Enforcement Manual Regulations
3/80 3-14
-------
3.5.2 Storage Tanks
Storage tanks for petroleum liquids are a significant source
of VOC emissions. Combined emissions from fixed-roof and exter-
nal and internal floating-roof storage tanks are about 830,000
Mg/yr (915,000 ton/yr). It is estimated that 67.5 percent of
these emissions [560,000 Mg (617,000 tons)] are from fixed-roof
storage tanks containing petroleum liquids with true vapor pres-
sures above 10.5 kPa (1.5 psia). Estimated emissions from exter-
nal floating-roof tanks during 1978 were 65,000 Mg (71,650 tons).
The VOC emissions from fixed-roof tanks can be controlled by
one of the following methods:
Retrofitting with internal floating roofs
Retrofitting with external floating roofs
Retrofitting with vapor recovery systems
Tanks with capacities less than 151,416 liters (40,000 gallons or
952 barrels) are specifically exempt from the preceding require-
ments .
RACT for external floating-roof tanks is as follows:
A welded, external floating-roof tank with a primary metal-
lic shoe or liquid-mounted seal must be retrofitted with a
rim-mounted secondary seal if the true vapor pressure of the
stored material exceeds 27.6 kPa (4 psia).
A welded or riveted external floating-roof tank equipped
with a vapor-mounted seal must be retrofitted with a rim-
mounted secondary seal if the true vapor pressure of the
stored liquid exceeds 10.5 kPa (1.5 psia).
A riveted, external floating-roof tank equipped with a
primary metallic shoe or liquid-mounted seal must be retro-
fitted with a rim-mounted secondary seal if the true vapor
pressure of the stored liquid exceeds 10.5 kPa (1.5 psia).
The following external floating-roof tanks are specifically
exempt from the preceding requirement:
Petroleum Refinery Enforcement Manual Regulations
3/80 3-15
-------
External floating-roof tanks having capacities less
than 1,600,000 liters (420,000 gallons or 10,000 bar-
rels) and used to store produced crude oil and condensate
prior to custody transfer
A metallic-type shoe seal in a welded tank that has a
tank wall
External floating-roof tanks storing waxy, heavy-pour
crudes.
3.5.3 Vacuum-Producing Systems
The vacuum-producing systems associated with vacuum distil-
lation and other refinery processes are potential sources of
atmospheric emissions of VOC. Three types of vacuum-producing
systems may be used:
Steam ejectors with contact (barometric) condensers
Steam ejectors with surface (shell and tube) condensers
Mechanical vacuum pumps
A petroleum refinery is not allowed to discharge more than
1.36 kg (3 Ib) of noncondensable VOC into the atmosphere in any 1
hour from any vacuum-producing system unless the total VOC dis-
charge has been reduced by at least 90 percent. If the uncon-
trolled discharge is greater than 1.36 kg/h (3 Ib/h), it should
be vented to an incinerator, flare, or refinery fuel gas system.
If a refinery uses contact condensers, hot wells associated with
these condensers must be covered.
3.5.4 Wastewater Separators
Contaminated wastewater originates from several sources in
petroleum refineries, including (but not limited to) leaks,
spills, pump and compressor seal cooling and flushing, sampling,
equipment cleaning, and rainwater runoff. Contaminated waste-
water is collected in the process drain system and directed to
the refinery wastewater treatment as required. Refinery drains
and wastewater treatment facilities are a source of emissions
resulting from evaporation of VOC contained in wastewater. When
a petroleum refinery is recovering at least 760 liters (201 gal-
lons or 4.8 barrels) or more of VOC per day from a wastewater
Petroleum Refinery Enforcement Manual Regulations
3/80 3-16
-------
separator and the VOC have a Reid vapor pressure of 3.5 kPa
(0.5 psia) or greater, the separator must be equipped with one of
the following vapor loss control devices:
Solid cover
Floating pontoon or double-deck cover
Vapor recovery system
3.5.5 Fugitive Emissions
Equipment leaks in petroleum refineries are a significant
source of VOC emissions. Nationwide VOC emissions from equipment
leaks in petroleum refineries are presently estimated to be
170,000 Mg/yr (187,393 tons/yr), or about 1 percent of the total
VOC emissions from stationary sources. Equipment considered in-
cludes pump seals, compressor seals, and seal oil degassing
vents; pipeline valves, flanges, and other connections; pressure
relief devices; process drains; and open-ended pipes.
When a VOC concentration of over 10,000 ppm is found in
proximity to a potential leak source, the source is leaking from
1 to 10 kg/day (2.2 to 22 Ib/day) depending on the source. If
the leak is not located or repaired for a year, annual emissions
from this single source can be from 0.4 to 3.7 Mg (0.44 to 4.1
tons) of VOC.
The VOC emissions from equipment leaks are controlled in two
phases: first, the leaks must be located (monitoring), and then
the leak must be repaired (maintenance).
Monitoring includes annual, quarterly, and weekly inspec-
tions. The refinery operator determines the VOC concentration
near each potential leak source with a portable VOC detection
instrument. If the VOC concentration at the source exceeds
10,000 ppm, the leak should be repaired within 15 days. The
monitoring intervals are as follows:
Monitor with a portable VOC detection device annually:
Pump seals
Pipeline valves in liquid service
Process drains
Petroleum Refinery Enforcement Manual Regulations
3/80 3-17
-------
Monitor with a portable VOC detection device quarterly:
Compressor seals
Pipeline valves in gas service
Pressure relief valves in gas service
Monitor visually weekly:
Pump seals
No individual monitoring necessary:
Pipeline flanges
Pressure relief in liquid service
Whenever a liquid leak from a pump seal is observed during
the visual inspection and whenever a relief valve vents to the
atmosphere, the operator must immediately monitor the VOC concen-
tration of that component. If a leak is detected, it should be
repaired within 15 days.
Some of the components having VOC concentrations in excess
of 10,000 ppm will not be able to be repaired within 15 days.
The refinery operator should report quarterly leaks that cannot
be repaired within the time frame and make arrangements for the
equipment to be repaired during the next scheduled turnaround.
If the operator is unable to bring a component into compliance,
he should apply for a variance.
3.6 STATE IMPLEMENTATION PLANS
The CAAA of 1977 required each state in which there is a
nonattainment area to adopt and submit a revised state implemen-
tation plan (SIP). Official designation of attainment areas for
the NAAQS has been made but is subject to change as more air
quality monitoring data are developed. Although the original
date for completion of the SIP's was 1980, the standards for some
pollutants and, hence, some nonattainment areas have been chang-
ed; the date has been extended accordingly for states preparing
new SIP's. The ozone plan portion of the SIP submittals relating
Petroleum Refinery Enforcement Manual Regulations
3/80 3-18
-------
to stationary sources of volatile organic compounds must contain
regulations reflecting the application of RACT.
Although the SIP's will differ, most will include emission
standards for particulates, carbon monoxide, sulfur dioxide,
nitrogen oxides, and volatile organic compounds from petroleum
refineries. As an example, the Kansas SIP is presented on the
following pages in outline form.
Petroleum Refinery Enforcement Manual Regulations
3/80 3-19
-------
KANSAS
(effective January 1, 1971)
I. Particulates
A. Regulation 28-19-20. This regulation addresses parti-
culate emissions limitations for any processing ma-
chine, equipment, device, or other articles excluding
indirect heating equipment and incinerators. (In a
refinery this would include FCC units, coking units,
sulfur plants and fugitives.)
Process weight rate, Rate of emission, Process weight rate, Rate of emission,
Ib/h tons/h Ib/h Ib/h tons/h Ib/h
100
200
400
600
800
1,000
1,
2,
2,
3,
3,
500
000
500
000
500
4,000
5.
6,
7,
,000
,000
,000
8,000
9,000
10,000
12,000
0.05
0.10
0.20
0.30
0.40
0.50
0.75
1.00
1.25
1.50
1.75
2.00
50
00
,50
,00
50
,00
0.551
0.877
1.40
1.83
2.22
2.58
3.
4.
38
10
4.76
5.
5.
38
96
6.52
7.58
8.56
9.49
.4
2
6.00
10.
11
12.0
13.6
16,000
18,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
120,000
140,000
160,000
200,000
,000,000
,000,000
6,000,000
8.00
9.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
50.00
60.00
70.00
80.00
100.00
500.00
1,000.00
3,000.00
16.5
17.9
19.
25.
30.
35.4
40.0
41.
42.
43.
44.
46.3
47.8
49.0
51.2
69.0
77.6
92.7
To calculate the rate of emissions:
1. Change Ib/h to tons/h by dividing by 2000
2. Insert into one of the following equations:
a. If process weight < 30 tons/h -» E = (4.1)(P°
b. If procesg weight > 30 tons/h -> E
= (55)
-------
3. Example calculation:
Let process weight rate = 250,000 Ib/h
250,000/2000 = 125 tons/h = P
Since P > 30 tons/h
E = (55)(P6>11) - 40
E = (55)(1256>11) - 40
E = (55) (1.7) - 40
E = 93.5 - 40
E = 53.5 Ib/h
B. Regulation 28-19-31. This regulation addresses parti-
culate emissions limitation for any indirect heating
equipment. (For a petroleum refinery, this includes
process heaters, boilers, and direct-fired compressors)
Total input, Allowable Total input, Allowable
106 Btu/h Ib/h 106 Btu* 106 Btu/h Ib/h 106Btu*
10 or less 0.60 1,000 0.21
50 0.41 2,000 0.17
100 0.35 5,000 0.14
500 0.24 7,500 0.13
700 0.22 10,000 0.12
or more
*The allowable emission rate for equipment having
intermediate heat input between 10 x 106 Btu and
10,000 x 106 Btu may be determined by the formula:
where A = the allowable emission rate in lb/h/106 Btu
I = the total heat input in 106 Btu/h
Example calculation:
Let I = 17.2 x 106 Btu/h
n —
A —
a -
j-zaa
1.026
17.2'*-3-4
1.026
A = 0.53
Petroleum Refinery Enforcement Manual Regulations
3/80 3-21
-------
II. Opacity
Regulation 28-19-31B. This regulation addresses the opacity
of stack gases and fugitive emissions.
A. Existing equipment: 40 percent opacity allowed
B. New equipment: 20 percent opacity allowed
III. Regulation 28-19-31C
This regulation addresses sulfur dioxide emissions and is
applicable to heaters, boilers, and compressors. The emis-
sions limit is 1.5 pounds of sulfur per million Btu of heat
input per hour. Indirect heating equipment having a heat
input of less than 250 million Btu per hour is exempt.
IV. Regulation 28-19-31D
This regulation addresses nitrogen oxide emissions and is
applicable to heaters, boilers, and compressors. The emis-
sions limit is 0.30 pounds of nitrogen oxides per million
Btu of heat input per hour. Indirect heating equipment
having a heat input of less than 250 million Btu per hour is
exempt.
V. Regulation 28-19-23
This regulation addresses hydrocarbon emissions and is
applicable to storage tanks, ethylene plants, and vapor
blowdown systems.
A. Any storage tank of 40,000-gallon capacity or greater
storing material which has a vapor pressure greater
than 3.0 psia must be equipped with one of the follow-
ing vapor loss control devices:
1. A double deck type floating roof or internal
floating cover; not allowed for materials with
vapor pressure greater than 13.0 psia
2. A vapor recovery system
3. Other equipment as may be approved by the Kansas
State Department of Health.
B. No person shall emit ethylene unless the waste gas is
burned at 1300°F for 0.3 seconds or more in a direct
flame afterburner.
Petroleum Refinery Enforcement Manual Regulations
3/80 3-22
-------
C. No person shall emit any gas stream excluding methane
of more than 50 Ib/day from a vapor blowdown system
unless the gases are burned by smokeless flares.
D. Installations and equipment existing on January 1,
1972, shall be exempt from the provisions of this
regulation.
VI. Regulation 28-19-24
This regulation addresses carbon monoxide emissions and is
applicable to FCC catalyst regenerators and coking units.
No person shall emit CO from any catalyst regeneration of a
petroleum cracking system, petroleum fluid coker, or other
petroleum process unless the gas stream is burned at 1300°F
for 0.3 seconds or more in a direct-flame afterburner.
Petroleum Refinery Enforcement Manual Regulations
3/80 3-23
-------
PROCESS
OPERATIONS
-------
SECTION 4.0
PROCESS OPERATIONS
An integrated refinery is made up of many interconnected
processes. By recognizing and understanding the individual
processes, the inspector can gain an understanding of the entire
refinery operation. This section presents process descriptions,
monitoring and inspection procedures, and related descriptive
material for a large number of common refining processes. The
processes are not categorized or grouped by type or quantity of
emissions; rather, they are presented as independent sections.
To prepare for an inspection at a relatively simple refinery, the
inspector may need to consult only six or eight sections. The
enforcement procedures are discussed in Section 5. Specific
emissions from valves, pumps, compressor seals, and other refin-
ery equipment components are discussed in Appendix H.
To gain further understanding of the refinery being inspect-
ed, the inspector should first stop in the control room for each
process unit. In the main control room for the fluid catalytic
cracking unit, for example, the recorders of concern to the
inspector are the temperature, pressure, and space velocity
gauges. The inspector should also ask to see the control room
logbook or, in larger refineries, a computer printout of the
operational parameters.
When recording any data from the logbook in the control
room, ask for conversion factors. Pressure is usually read in
pounds per square inch gauge (psig), but a factor of 10 may need
to be applied. Temperature is recorded in degrees Fahrenheit.
The metric system has not reached refineries. It is particularly
important that a conversion factor be known for flow rates.
Petroleum Refinery Enforcement Manual Process Operations
3/80 4.0-1
-------
Before starting an inspection, the inspector should consult
this section of the manual to insure he has an understanding of
the operation of the unit, the types and sources of emissions,
and the information to be obtained. Section 5 delineates the
various levels of inspection to be performed.
Each refinery process is described in terms of the following
subsections:
4.n.l Process Description
This subsection presents a description of the process, taken
from the literature. The description gives the inspector a
complete view of the process. A conceptual diagram illustrating
the process flow accompanies each description. Table 4.0-1 shows
the symbols that are used in the diagrams.
4.n.2 Emission Sources
A discussion of the types and sources of emissions is pre-
sented. Data from EPA publication AP-42 are not repeated, but
the reader is directed to the pollutants of concern and their
sources, including vents and leaks in seals, packing, and
flanges.
A major reference study providing information on emission
sources is the 1978 survey conducted by the California Air Re-
o
sources Board. This survey estimated the extent of leakage from
various refinery equipment.
4.n.3 Emission Controls
This description of the control methods used to reduce
emissions, including add-on devices and process modifications,
helps the inspector in his discussions with plant personnel.
4.n.4 Ins trumentati on
Refinery processes are enclosed, high-volume operations. A
great deal of instrumentation is used to monitor flows, emis-
sions, operating conditions, and control systems. The inspector
should understand the pertinent readings from these instruments.
Petroleum Refinery Enforcement Manual Process Operations
3/80 4.0-2
-------
TABLE 4.0-1. SYMBOLS USED IN PROCESS FLOW DIAGRAMS
SYMBOL
DESCRIPTION
or
c
1 1
or
-o
Direct-fired heater; also referred to
as furnace, pipe still, or heater.
Fractionating tower; also referred to
as fractionator, distillation column,
stabilizer, or stripper.
Separator or settler.
Accumulator.
Heat exchanger.
Petroleum Refinery Enforcement Manual
3/80 4.0-3
Process Operations
-------
TABLE 4.0-1 (continued)
SYMBOL
DESCRIPTION
O
-------
TABLE 4.0-1 (continued)
SYMBOL
DESCRIPTION
Valve.
Emission point, with point source
number (n) indicated inside the
diagram.
Petroleum Refinery Enforcement Manual
3/80 4.0-5
Process Operations
-------
This subsection describes flow rates, operating temperature,
operating pressure, and other parameters related to emissions.
The parameters stated in the text are based on engineering judg-
ment.
4.n.5 Startup/Shutdown/Maifunctions
This subsection describes the frequency of startup/shutdown
operations and their effect on emissions. Emissions at these
times, and during malfunctions or upsets, are frequently vented
to the plant blowdown system. Increases in emissions can, how-
ever, still occur.
4.n.6 References
The references are intended to document the information
presented in the subsection. References for this subsection are
listed below.
1. U.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2d ed. AP-42. 1979.
2. State of California. Air Resources Board. Emissions From
Leaking Valves, Flanges, Pumps and Compressor Seals and
Other Equipment at Oil Refineries. Report No. LE-78-001.
April 1978.
Petroleum Refinery Enforcement Manual Process Operations
3/80 4.0-6
-------
DISTILLATION
-------
4.1 DISTILLATION1'9
Distillation refers to the complete operation required to
separate materials having different boiling points. This opera-
tion includes heating, vaporization, fractionation, condensation,
and cooling. The most important distillation unit in the refin-
ery is that which separates incoming crude oil into various
boiling point fractions. This section discusses the distillation
process that occurs under both atmospheric and vacuum conditions.
Higher efficiencies and lower costs are achieved when the crude
oil separation is accomplished in these two steps: the total
crude is fractionated in a tower at essentially atmospheric
pressure, the high-boiling bottoms fraction (residual) from the
atmospheric still is then fed to a second fractionator operated
at vacuum conditions. The main separation technique used in
distillation is fractionation, which is discussed in detail in
Appendix C. The inspector should refer to the literature refer-
ences in the Bibliography for additional information.
4.1.1 Process Description
Atmospheric Distillation
Before the incoming crude enters the atmospheric distilla-
tion unit it is usually treated to remove salt, which would
corrode the equipment (Section 4.9). A typical atmospheric
distillation unit is illustrated in Figure 4.1-1. The crude is
preheated by exchange with outgoing streams to about 290°C
(550°F), whereupon it enters the crude heater. In the heater the
temperature of the crude is raised to about 400°C (750°F), which
partially vaporizes it. The crude then flows to a distillation
column (crude tower), which serves as the atmospheric fractiona-
tor. This tower normally contains 30 to 50 fractionation trays
and three or more liquid sidestream draws. The crude is separ-
ated into several cuts, including gas containing light hydrocar-
bons (butanes, propane, and lighter hydrocarbons), light naphtha
with a boiling range of 40° to 120°C (100° to 250°F), heavy
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-1
-------
CO hd
XCD
oo rt
o n
o
I-1
0>
e
Jd
(D
i-h
H-
0
0>
O
H
O
0>
CD
a
rt
3
o
H-
w
H-
WATER TO
TREATMENT
CRUDE OIL
DISTILLATION
COLUMN
GAS TO
FUEL GAS
SYSTEM
HEAVY
NAPHTHA
LIGHT
GAS OIL
HEAVY
GAS OIL
TO VACUUM
UNIT OR
STORAGE
H-
o
C3
Figure 4.1-T. Typical crude oil distillation unit.
-------
naphtha with a boiling range of 90° to 175°C (200° to 350°F),
light gas oil with a boiling range of 160° to 260°C (325° to
500°F), heavy gas oil with a boiling range of 230° to 340°C (450°
to 650°F), and residuum.
As shown in Figure 4.1-1, the gas and the pentane and light-
er fractions come off the top of the crude tower and flow to the
overhead condenser and accumulator. In the accumulator, two
phases are present: a gas phase containing light hydrocarbons
(butanes and propane) and a liquid phase containing water and the
pentane and lighter crude fractions. The gas from the accumula-
tor, which is usually compressed, flows to the refinery fuel gas
system. The water collected in the accumulator was either pre-
sent in the crude or entered the tower from the stripping steam
(see below). This water is sent to the wastewater treatment
facility. The pentane and lighter fractions contain light gaso-
line and some propane and butane. Some of this fraction is
returned to the top of the crude tower as reflux, and the rest is
sent to a stabilizer (fractionator) where the propane and butane
are removed.
As discussed in Section 2.2.2, the crude tower usually
produces three or more sidestreams that are stripped of their
light ends by steam. This step is necessary because the liquid
sidestreams withdrawn from the column contain low-boiling compon-
ents that lower the flash point; the lighter products pass
through the heavier products and are in equilibrium with them on
every tray. These light ends are stripped from each sidestream
in a separate, small stripping tower containing 4 to 10 trays.
Steam is introduced under the bottom tray and the steam and
stripped light ends are returned to the crude tower above the
corresponding side draw tray. This procedure also reduces the
vapor pressure of the sidestreams. Each sidestream (shown in
Figure 4.1-1 as heavy naphtha, light gas oil, and heavy gas oil)
is stream stripped, subjected to heat exchange with crude oil,
cooled, and pumped to storage.
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-3
-------
The hot residual is steam stripped in the base of the crude
tower, whereupon it usually flows to the vacuum distillation unit
(vacuum tower). Alternatives to vacuum distillation may be used
(e.g., residual oil supercritical extraction or ROSE, residuum
extraction, coking, or Residfiningj, but most refineries follow
atmospheric distillation with vacuum distillation.
Vacuum Distillation
The vacuum distillation unit is used to separate the heavier
portion of the crude into fractions. A typical vacuum distilla-
tion unit is shown in Figure 4.1-2. If this operation were
performed at atmospheric pressure, the temperatures necessary to
vaporize the atmospheric bottoms would cause thermal cracking and
resultant discoloration of product; coke formation would also
cause fouling in the equipment. In the vacuum unit, hot residual
bottoms from the crude tower flow to a vacuum heater, which heats
the oil to 400°C (750°F). The residual then flows to the vacuum
tower, where distillation occurs under the combination of high
temperature (390° to 450°C; 730° to 850°F) and low pressure (3.3
to 5.3 kPa; 25 to 40 mm Hg absolute).
Vaporization is improved when the effective pressure is
lowered even further to 1.3 kPa (10 mm Hg) or less by the addi-
tion of steam at the furnace inlet and the bottom of the vacuum
tower. Addition at the furnace inlet increases the furnace tube
velocity and minimizes coke formation in the furnace, as well as
decreasing the partial pressure of the hydrocarbons in the vacuum
tower.
At least one gas oil stream is taken off from the side of
the vacuum tower. The sidestream is subjected to heat exchange
with the feed, cooled, and pumped to storage. The vacuum resi-
dual from the bottom of the tower is either cooled and sent to
storage or sent to the coking unit for further processing.
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-4
-------
oo
o
o
I-'
133
0>
H>
H-
2
(D
H
^
W
O
hf
O
n>
• 3
h-1 ju
i 3
in pi
fl f"l STEAM
DISTILLATION./!
TOWER
VACUUM
HEATER
A A
V \
v
FROM
CRUDE
TOWER
RESIDUALS
1
OIL TO
("\J >• SLOPS
c=a
-*• TO SOUR WATER
STRIPPER
LIGHT VACUUM
_^ GAS OIL TO
STORAGE
-»• HEAVY GAS OIL
TO STORAGE
VACUUM RESIDUAL
TO TANKAGE
O
H-
OT
ri-
H-
Figure 4.1-2. Vacuum distillation unit.
ft
H-
O
-------
The desired operating pressure is maintained by the use of
steam ejectors (Figure 4.1-2) and barometric or surface conden-
sers. The size and number of ejectors and condensers are deter-
mined by the vacuum needed and quantity of vapors handled. For a
tower operating at 3.3 kPa (25 mm Hg absolute), three ejector
stages are usually required. The first stage condenses the steam
and compresses the noncondensable overhead gases. The overhead
gas and steam are cooled in an intercondenser. A steam nozzle
discharges a jet of high-velocity steam across a suction chamber
that is connected to the tower. The exiting steam and any en-
trained vapors are condensed by direct water quench in a baromet-
ric condenser or a surface (shell and tube) condenser. The
second stage removes the noncondensable gases from the condenser.
The steam and noncondensable gas are cooled in the second inter-
condenser. The third stage removes the noncondensable gases from
the second intercondenser. The gas and steam are cooled in an
aftercondenser. The noncondensed gas is vented to a heater, the
refinery fuel gas system, or the atmosphere. The condensers may
be barometric (contact) or surface (shell and tube). The con-
densed gas and steam flow to an accumulator, where the phases are
separated. The hydrocarbon liquid is sent to a slop oil tank.
The water phase is sent to a sour water stripper for purifica-
tion.
Where contact condensers are used, the steam and overhead
gas are mixed with the cooling water. These hydrocarbon vapors
may be emitted to the atmosphere, posing an air pollution prob-
lem.
4.1.2 Emission Sources
The heaters in the crude distillation unit (Figure 4.1-1,
point 1) and the vacuum unit (Figure 4.1-2, point 1) are poten-
tial sources of sulfur dioxide and particulate emissions.
The overhead accumulator vent in both the crude distillation
unit (Figure 4.1-1, point 2) and the vacuum unit (Figure 4.1-2,
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-6
-------
point 2) are potential sources of hydrogen sulfide and hydro-
carbon emissions.
In vacuum units using barometric condensers, the oily con-
densate produces evaporative emissions of hydrocarbons from the
hot well (sump) to which it is discharged.
The study by the California Air Resources Board found that
the distillation units contributed 1.2 percent of all the fugi-
tive emissions from the refinery. Of the devices tested in
distillation units, 22 percent of the pump seals leaked and 1.2
percent of the valves leaked. Fractionation units in general,
however, were found to contribute 5.4 percent of the total refin-
ery fugitive emissions. Of the devices tested in fractionation
units, leakage occurred in 32 percent of the pump seals, 50
percent of the compressor seals, 12 percent of the valve outlets,
12 percent of the threaded fittings, and 11 percent of the val-
ves.
4.1.3 Emission Controls
The gas or oils fired by process heaters are fairly clean
fuels. Particulates can generally be controlled by proper opera-
ting practices and adjustments of the air-to-fuel ratio.
The fuel gas stream from the overhead accumulator vent
contains hydrogen sulfide, which is removed in the amine unit and
eventually converted into elemental sulfur in the sulfur plant.
The wastewater from the overhead accumulator on the atmo-
spheric distillation unit contains hydrocarbons and may emit
volatile organic compounds if it flows in open ditches. The use
of closed piping prevents the emissions.
The noncondensable emissions from steam ejectors are con-
trolled by venting into blowdown systems or fuel gas systems and
incineration in furnaces, waste heat boilers, or incinerators.
Vapor recovery units return condensable hydrocarbon vapors to
process streams. Incineration is accomplished by catalytic or
direct flame combustion. These controls reduce the hydrocarbon
emissions from this source to negligible amounts.
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-7
-------
Emissions of vapors from the hot wells associated with baro-
metric condensers can be controlled by covers and incineration.
Emissions of oily condensate can be eliminated by mechanical
vacuum pumps or surface condensers that discharge to a closed
drainage system.
Noncondensables and oily condensate and their emissions can
be minimized by installing a lean-oil absorption unit between the
vacuum tower and the first-stage vacuum jet. The rich oil ef-
fluent is used as charge stock and is not regenerated.
Steam ejectors with surface condensers form a closed system
and need no further controls.
4.1.4 Instrumentation
Process control in a petroleum refinery is automatic. Most
refineries use trend analyzing instruments to monitor changes in
process parameters. Three parameters are monitored for the
towers in a distillation unit: feed rate, feed temperature, and
overhead temperature.
A rise in the feed temperature is detected and the heat
input reduced before an upset can occur. Automatic control of
the heaters can, in this case, result in emissions caused by an
improper air-to-fuel ratio. When the feed rate is increased, so
is the demand on the heater; greater fuel usage then results in
higher sulfur or particulate emissions. When the overhead tem-
perature increases, cracking is occurring in the tower and more
vapors are exiting overhead. As the vapors increase in quantity,
the accumulator may be unable to separate the phases, allowing
the vapor to become trapped in the liquid. The vapor would then
enter the wastewater and be emitted as volatile organic compounds
at the treatment facility. A high feed temperature can also
create this problem.
4.1.5 Startup/Shutdown/Malfunctions
Startups and shutdowns are potentially troublesome and haz-
ardous. Plant operators are usually especially alert and cau-
tious during these periods.
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-8
-------
The major steps in unit startup are as follows:
Preliminary preparations
Elimination of air
Tightness testing
Disposal of purge material
Elimination of water
Operation of the unit on stream
Hydrocarbon gas can be used to remove the purge gas (steam or
nitrogen) from the unit. Presumably, this gas is removed from
the column by normal operating methods. If the gas is vented,
that procedure could be a source of emissions. Refluxing with
liquid products can be used in startup and shutdown procedures to
facilitate transition into regular operation with a minimum of
process upsets.
The major steps in unit shutdown are as follows:
Furnace drying
Oil wash
Vapor purging
Steam purging
Water washing
These steps overlap in the shutdown operation. Oil wash begins
as the sidestream draws are closed off and before the feed is
removed; coil outlet temperatures are also cut at this time. The
feed is then removed by continuous overhead reflux to the tower.
The oil is pumped from all levels of the tower as it accumulates.
The system is then steamed and water washed.
The furnace-drying period is about 4 hours. Steam is intro-
duced into the furnace and exhausted into the closed tower. All
steam is then removed from the furnace, isolated from the tower,
and allowed to cool.
The oil vapors are purged through the vapor recovery system
until the final stage, when unit safety valves are bypassed and
the vapor is steamed directly to the unit flare. At this time
all auxiliary equipment is steaming out to rundown tankage.
The steam-cooling period begins after the oil washing is
complete and about 2 hours before furnace drying is to begin; the
operation takes about 10 hours. A high volume of live steam is
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-9
-------
introduced into the tower bottom and sidestreams. It is ini-
tially removed through the flare systems; after the vapor-purging
period, the system is opened to the atmosphere.
The water washing begins at the conclusion of the steam-
cooling period. Water is introduced into the top of the tower at
a gradually increasing flow rate. When the washing is complete,
the unit is cooled, depressurized, purged, and prepared for
workers to enter.
4.1.6 References
1. Ballmer, R. W. Towers Are Touchy. American Petroleum
Institute Proceedings, 1960. pp. 279-283.
2. Bonnell, W. S., and J. A. Burns. Startup/Shutdown Proce-
dures For Large Crude Oil Distillation Unit. American
Petroleum Institute Proceedings, 1960. pp. 285-291.
3. Hanson, P. N., and J. Newman. Calculation of Distillation
Columns at the Optimum Feed Plate Location. Industrial
Engineering Chemistry, 16(2): 223-227, 1977.
4. Holland, C. P., and G. P. Pendon. Solve More Distillation
Problems. Part 1. Hydrocarbon Processing, 53(7): 148,
1974.
5. Holland, C. D., and P. T. Eubank. Solve More Distillation
Problems. Part 2. Hydrocarbon Processing, 53(11): 176,
1974.
6. Kern, R. Layout Arrangements for Distillation Columns.
Chemical Engineering, August 15, 1977. pp. 153-160.
7. Kister, H. Z. When Tower Startup Has Problems. Hydrocarbon
Processing, February 1979. pp. 89-94.
8. Nelson, W. L. Petroleum Refinery Engineering. 4th ed.
McGraw Hill Book Company, New York, 1969. pp. 226-262,
435-438, 499, 608.
9. Yaws, C. L., et al. Estimate Multicomponent Recovery.
Hydrocarbon Processing, February 1979. pp. 99-100.
Petroleum Refinery Enforcement Manual Distillation
3/80 4.1-10
-------
CATALYTIC
CRACKING
-------
4.2 CATALYTIC CRACKING1'2
Catalytic cracking is one of the decomposition processes
briefly discussed in Section 2. In the reactor of a catalytic
cracking unit, gas oil (heavy distillate) carbon chains are
broken down in the presence of heat and a catalyst. The reaction
products are hydrocarbons of lighter weight and a lower boiling
temperature. The catalytic cracking unit is used to upgrade the
heavy distillates to lighter, more useful distillates such as
gasoline, kerosene, and heating fuels.
4.2.1 Process Description
The catalyst in a catalytic cracking process is handled by
one of four methods: fluidized bed, moving bed, fixed bed, and
once-through operation. Fluidized-bed processes are predominant
but some moving-bed units are still in operation. Moving-bed
processes include Thermofor catalytic cracking (TCC) using bucket
elevators or air-lift processes, and the Houdriflow air-lift
process. Fixed-bed and once-through catalytic crackers are not
in general use today.
Fluidized-Bed Catalytic Cracking Unit
Several proprietary fluidized-bed catalytic cracking pro-
cesses are available from engineering construction companies and
oil refining research and development groups. The process may be
called Flexicracking, fluid catalytic cracking (FCC), Orthoflow,
or UltraCat Cracking; the difference between them is subtle. The
following description (and subsequent sections) refers to a FCC
unit, but the principles of operation apply to any of the fluid
processes mentioned above.
As product needs change, different catalysts—low alumina,
high alumina, kaolin, clay, and zeolite—have been used in FCC
processes. These and molecular sieves are currently being used.
Figures 4.2-1 through 4.2-3 illustrate various aspects of
the FCC unit. Figure 4.2-1 shows the reactor/regenerator portion
of the process and the flue gas control devices. Figure 4.2-2
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-1
-------
to I
ooft
on
o
0>
3
0>
H-
0>
M
3
O
o
CD
(D
fg RISER
N>0>
1 3
£U
M
£ FEED >.
ft
^
\ ,
PRODUCTS
CFLUE GAS
/
M
bpl*
r
1|--
Jh
1
^
<3> © <^>
REACTOR STJAM @ -Q
AIR^ I T OPACITY METER
FIIFI TAC 1 1 1 1 *-
'''CO BOILERt_BFW ^PRECIPITATOR
<-TT AM
-STEAM STEAM /,
t <2>
FLUE GAS S\ ^/
— tef 1 ^
Ly
* ROT! FR FFFHUATFR
— Dw 1 LL.I\ r t.LL/nr\ 1 L.r\
(BFW)
REGENERATOR .
f AIR
x^- CATALYST
^AIR TRANSFER LINE
rt
H.
0 Figure 4.2-1. Reactor/regenerator portion of a fluid catalytic cracking unit.
o
O>
O
-------
GO
oo <-t
on
o
M
(D
(D
H,
H-
3
0)
W
O
(D
(D
• s
K) (U
co c:
o
(u
rt
3
H-
O
O
REGENERATOR
RECYCLE
VAPOR TO GAS
COMPRESSOR
2
s
s
\^
J
1
FRACT
ION/1
X-N
T
TN COOLER/
\) CONDENSER
STRIPPER
* STEAM
-»• RAW GASOLINE
LIGHT CYCLE
"*" GAS OIL
HEAVY CYCLE
GAS OIL
O
*•
H-
Figure 4.2-2. Fractionator portion of a fluid catalytic cracking unit with two risers.
-------
\CD
00 ft
O H
O
M
(D
M
0
HI
O
H.
O
CD
n
0
rt
to
o
OJ
ft
C1J
ft
H-
o
o
H.
(>>
O
W
H-
WET GAS .«-
ELECTROSTATIC
PRECIPITATOR
RAW
GASOLINE-*-
STEAM —»
.LIGHT CYCLE
OIL
HEAVY CYCLE*
OIL
BOTTOMS •*
FEED
Figure 4.2-3. Overview of fluid catalytic cracking unit.
-------
shows the fractionator portion of an FCC unit having two risers.
Figure 4.2-3 is an overview of the FCC process that also shows
the points of emission.
The liquid gas oil feed in an FCC unit is preheated by
exchange with the outgoing product. The feed then comes into
contact with hot catalyst in a vertical tube leading to the
reactor vessel (Figure 4.2-1). The gas oil vaporizes at this
point of initial contact. A second vertical tube may be present
to carry the recycle feed stream (Figure 4.2-2). These tubes are
referred to as the riser sections because the gas oil vapors rise
and carry the catalyst with them. The rising catalyst behaves as
a fluid, giving the process its name.
The gas oil vapors undergo cracking reactions in the risers
and some reaction products are deposited on the catalyst. The
mixture of catalyst and products flows from the risers to the
reaction vessel. As the mixture enters, steam is injected to
strip the products from the catalyst. The products rise as
vapors through the reactor vessel and are discharged through
cyclones, where fine catalyst particles are removed (Figure
4.2-2). The vapors are then passed through a condenser and
routed to a fractionator (also known as a distillation or stabil-
ization column) for separation. The noncondensables or light
gases flow from the top of the fractionator to the gas recovery
system. Other cuts from the fractionator may include alkylation
unit feed, light cycle oil, heavy cycle oil, and slurry oil.
Gasoline is recovered from the cooler-condenser. The heavier
liquid products separated in the fractionator may be recycled to
the FCC reactor or further processed in another unit (such as the
coker or asphalt plant).
As with any catalytic process, the catalyst in an FCC unit
loses activity (effectiveness in changing the rate of a specific
reaction) with use. After steam stripping, coke (carbon) and
some metals remain deposited on the catalyst. The results of
these deposits are pore shrinkage and a loss of available cataly-
tic surface area. The used (spent) catalyst is thus routed from
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-5
-------
the reactor to a regenerator where the catalyst is partially
restored by burning the coke off in a controlled combustion
reaction. The air injected into the vessel for the combustion
reaction also serves to fluidize the catalyst.
Combustion gases from the regenerator are cleaned and passed
through cyclones for recovery of catalyst. The regenerated
catalyst flows down a transfer line for reuse (Figure 4.2-1).
Moving-Bed Catalytic Cracking Unit
Moving-bed catalytic cracking units use heat and pellet
catalysts to crack the heavy distillate oils and form more useful
products. Unlike the powdered catalyst sometimes used in fluid-
ized-bed units, beads or pellets are easy to handle and do not
cause plugging. Synthetic silica-alumina compositions, including
acid-treated bentonite clay, fuller's earth, aluminum hydrosili-
cates, and bauxite, are often used as catalyst. Natural cata-
lysts are softer, have lower activity and selectivity, and higher
losses due to attrition than synthetic catalysts. Therefore
natural catalysts are less desirable than synthetic catalysts.
As in an FCC unit, carbon is the main material deposited on
the catalyst in a TCC or Houdriflow unit. The carbon deposits
are burned off the catalyst under controlled temperature and air
rates in a regeneration kiln.
A moving-bed catalytic cracking unit consists of a combina-
tion reactor-kiln vessel, a catalyst lift, a catalyst elutriator,
a catalyst fines separator, and an air heater that is used only
for startup (See Figure 4.2-4). A hot catalyst storage vessel
usually acts as a support for the catalyst-lift and the catalyst
elutriator. A fresh catalyst storage vessel is located just
above the cracking reactor.
Charge stocks are fed into the moving-bed cracking unit near
the top of the reactor vessel through a specially designed noz-
zle. The charge stocks may enter as liquid, vapor, or a mixture
of liquid and vapor. The physical state of the charge stock
depends on the design requirements of the cracking unit and the
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-6
-------
SURGE
HOPPER
LIQUID FEED
PRODUCT
TO
FRACTIONATOR
AIR
HEATER
CATALYST
LIFT
PIPE
JELUTRIATOR
CYCLONE
SEPARATOR
COMBUSTION AIR
LIFT POT
LIFT AIR
Figure 4.2-4. Moving-bed (airlift) catalytic cracking unit.
Petroleum Refinery Enforcement Manual
3/80 4.2-7
Catalytic Cracking
-------
composition of the heavy distillate feed streams. The entry
nozzle directs the flow of the charge stock so that it is uni-
formly distributed on the hot catalyst, which is being continu-
ously fed into the reactor from the top of the vessel (Figure
4.2-4). Partial cracking occurs when the charge stock comes into
contact with the catalyst, along with almost immediate vaporiza-
tion of liquid feed. The cracked and uncracked vapors remain
mixed as they flow down through the solid bed of catalyst, which
itself is moving downward through the reactor and into the kiln.
Before reaching the bottom of the reactor, the catalyst and
vapors are separated in a disengager. The vapors are collected
in a chamber outside the reactor shell and sent to a fractiona-
tor.
The catalyst that flows from the disengager has residual
oils remaining on it, which are vaporized and purged by the
injection of steam at low pressure. The steam and purged hydro-
carbon vapors are collected and routed to a fractionator.
After leaving the purge zone, the catalyst continues its
downward flow through a group of pipes and into the kiln. Steam
is injected with the catalyst into the pipes to reduce the pres-
sure to about atmospheric at the entry to the kiln. In the top
zone of the kiln, the downward moving catalyst is met with a
countercurrent flow of air from the air inlet channels (Figure
4.2-4). The resulting combustion reactions burn some of the coke
deposits from the catalyst. More coke deposits are removed in
the cooling zone and the bottom zone of the kiln. The excess
heat produced in the combustion reactions is removed by heat
exchange with internal cooling coils. About 70 percent of the
gases exit through the flue gas vent at the top of the kiln.
This flue gas is channeled through a fume burner for removal of
remaining hydrocarbons. The other 30 percent is entrained in
catalyst, from which it is separated at the bottom of the kiln.
The catalyst is then sent to a catalyst cooler and on to the lift
pot. The flue gas is vented to the atmosphere or to a control
device.
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-8
-------
Flue gas and steam are used to lift the regenerated catalyst
from the lift pot up through the lift pipe to the surge hopper
above the reactor. A lift disengager is located at the top of
the lift pipe to separate the catalyst from the lift gas (Figure
4.2-5). The catalyst is transferred through a line to the top of
the reactor. Gravity pulls the catalyst down through the reac-
tor, and the cycle continues.
The fresh catalyst storage hopper is located between the
surge hopper and the reactor.
4.2.2 Emission Sources
The major source of emissions from both fluidized-bed units
and moving-bed units is the regenerator flue gas stream. Carbon
monoxide (CO), at an uncontrolled emission rate of approximately
3
10.8 kg/m of fresh feed, is a major contaminant in the stream.
This stream is generally routed to a CO boiler, whereupon the
stack from the boiler becomes the emission point (Figures 4.2-1,
4.2-3, and 4.2-5, point 1). It must be noted that CO is not a
major pollution source from some new fluid catalytic crackers
that use improved catalyst and high-temperature regeneration. In
these cases, the catalyst is regenerated at a high temperature—
over 732°C (1350°F)—and the carbon monoxide is burned in the
regenerator instead of being emitted to the atmosphere.
Particulates are another major pollutant from catalytic
crackers. Those particulates not collected in control devices
(e.g., cyclones, electrostatic precipitators) are emitted to the
atmosphere from the CO boiler stack or the regenerator. The
uncontrolled particulate emission rate is usually much higher for
fluidized-bed units than for moving-bed units.
The sulfur compounds in the feed to catalytic crackers cause
sulfur oxide emissions. When the catalyst becomes coated with
carbon it is regenerated to restore its activity. The carbon
coating contains sulfur compounds and metals. During regenera-
tion, combustion converts the carbon to gaseous form and the
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-9
-------
A
STACK <3,
s
CATALYST
SURGE
HOPPER
FRESH
CATALYS'
STORAGE
REACTOR
CHARGE
PRODUCTS
TO /
r KAL 1 iUNnlUK •* 1
PURGE . -
STEAM
9
V
AIR A
HEATER
/— ri »
FINES
EPARATI
SYSTEM
S~~^!
\y
[ 1
SJ V
/^^
^^^
DDDD
1DDD
M[
^^
f^
ON 1 1 \~- -
1 J
' i
TO FINES
BIN
.FRESH CATALYST
X MAKEUP ..
no%-
OPACITY ^^
] METER (^g) —
AIR
V ^W-
FLUE Q \
1 GAS
OUTLET
p STEAM
MOTIVE GAS/T
TO LIFT Li
\ENGAGER
^x '
~t/* 1 1 STARTUP AIR ^\ ~>
^y£ CATALYST TO ENGAGER ^»£
COMPRESSOR
LIFT
7DISENGAGER
CATALYST
LIFT PIPE
^-PRECIPITATOR
^CO BOILER
^-•FUEL GAS
A LIFT
J ENGAGER
Figure 4.2-5. Points of emission from moving-bed catalytic cracking unit.
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-10
-------
sulfur compounds to sulfur oxide. The sulfur and metals are
emitted to the atmosphere.
Amoco has developed a new catalyst for fluid catalytic
crackers that lessens the sulfur oxide emission rate from the
regenerator. The catalyst retains the sulfur until it is return-
ed to the reactor, where it is reacted with hydrogen to form
hydrogen sulfide (H2S). The H2S leaves the reactor with the
cracked product and is later converted to sulfur in the Claus
plant.
Other emissions from the CO boiler stack are any uncombusted
aldehydes, ammonia, hydrocarbons, and contaminants in the regen-
erator flue gas that were not combusted in the CO boiler. These
contaminants are oxides of nitrogen, sulfur dioxide, and sulfur
trioxide. In the absence of a CO boiler and high temperature
regeneration, all of these flue gas contaminants are emitted to
the atmosphere. The stack would be at point 2 on Figures 4.2-2,
4.2-3, and 4.2-5. The composition of contaminants depends on the
feed and operating conditions of the unit.
If an external cyclone or an electrostatic precipitator is
used in either a fluidized-bed unit or a moving-bed unit, cata-
lyst fines can result in significant particulate emissions as the
fines are transferred from the bases of the cyclones and the ESP
hoppers (Figure 4.2-3, point 3).
Hydrocarbons may also be emitted from leaking valves,
flanges, and pump and compressor seals on fluidized-bed or mov-
ing-bed units.
Moving-bed units may emit particulates from the disengaging
drum of the catalyst transfer system (Figure 4.2-5, point 3).
Fluidized-bed units continuously lose particulates to the atmo-
sphere from the reactor product vent (Figure 4.2-1, point 3).
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-11
-------
4.2.3 Emission Controls
Cyclones
The regenerator off-gas (flue gas) contains a substantial
amount of particulates in the form of catalyst fines. A multi-
cyclone (also known as a swirl-vane dry classifier) is often used
as the primary particulate removal device. It can remove parti-
culates having a diameter of 40 microns or greater. The flue
gases are forced tangentially into a cylindrical vessel, where
strong centrifugal force separates out the large particles. The
gases spiral upward and out of the first cyclone, and may enter a
second cyclone for finer separation. These cyclones are usually
internal (located inside the regenerator housing); they are
important as catalyst recovery equipment. In some refineries,
external cyclones (located outside of the regenerator housing)
are also used after the CO boiler for additional particulate
control. The base of an external cyclone, which is usually
tapered for collection of the catalyst fines, is periodically
opened for removal of the fines into disposal hoppers. Internal
cyclone efficiency is improved with an external separation de-
vice.
Carbon Monoxide Boiler
Regenerator flue gas from the internal cyclone system (Fig-
ure 4.2-1, point 2) also contains a significant amount of CO and
other contaminants. The CO is generally burned in a CO boiler to
prevent its escape to the atmosphere. This control unit operates
the same way as an ordinary process unit boiler. Some additional
fuel gas and air must be provided for combustion, as indicated on
Figure 4.2-1. Other contaminants in the regenerator flue gas
(aldehydes, ammonia, and hydrocarbons) can also be controlled by
combustion in a CO boiler. The boiler is beneficial to the
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-12
-------
refiner because it controls emissions of CO and other contami-
nants and converts energy, that would otherwise be lost, to
steam.
Electrostatic Precipitator
The flue gas from the CO boiler contains particulates formed
in the boiler during combustion, as well as fine (less than 40
microns) residual catalyst particulates. In fluidized-bed units,
an electrostatic precipitator generally follows the CO boiler,
although a third-stage cyclone or water scrubber may be used
instead. In a moving-bed unit, an ESP and an additional parti-
culate control device may be used if the emission level is severe
enough to warrant control.
In the ESP, very fine particulates are charged by high-volt-
age, direct current coronas. Large, plate-like electrodes are
used for collection of the charged particles. They are periodi-
cally removed from the electrodes by rapping or washing. An
internal cyclone and ESP system achieve about 99 percent effi-
ciency.
High-Temperature Regeneration
High-temperature regeneration is an alternative to the CO
boiler as a control technique for CO emissions from fluidized-bed
units. New catalysts and regenerator designs accelerate the
conversion of CO to C0«, thereby reducing CO emissions. The heat
liberated in the conversion is used in the regenerator to in-
crease the efficiency of the catalytic cracker. The higher
temperature in the catalyst bed gives the process its name,
high-temperature regeneration. The increase in temperature over
a conventional regeneration system is about 78°C (140°F). Cy-
clone temperatures have a small increase of about 17°C (30°F).
The flue gas from a high-temperature regenerator contains about
0.4 percent CO by weight, as compared with an uncontrolled CO
content of about 9.3 percent from a standard regenerator system.
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-13
-------
Catalyst Attrition Control Techniques
In a TCC unit, particulate emissions are controlled by
preventing the attrition of catalyst. Factors important in
minimizing catalyst attrition include design, maintenance and
operation of the unit, and characteristics of the catalyst it-
self. The following procedures will minimize particulate emis-
sions:
Among components of the lift system, the feed pot, tapered
lift pipe, and disengagement system in the separator should
be designed for minimum catalyst attrition. When flow rates
are greater than design, problems with these components will
increase particulate emissions.
Good maintenance is an essential control technique. High
attrition rates can be caused by such malfunctions as mis-
aligned or worn lift pipe components, partially blocked
catalyst passages, or worn disengaging system components.
Variations in the lift air rate, which are caused by ambient
temperature changes, must be corrected promptly.
The elutriator should be operated to prevent an increase in
emissions from the accumulation of fines in the catalyst
inventory.
Proper use of the shaveoff system will reduce fines in the
lift air.
Catalyst treatment techniques minimize attrition and reduce
erosion of critical system components whose failure could
cause abnormal attrition.
4.2.4 Instrumentation
Fluidized-Bed Catalytic Cracking Unit
The inspector in the control room (board room) for the
fluidized-bed unit monitors temperature, pressure, and space
velocity gauges. The temperature of the catalyst (as it comes in
contact with the feed) ranges from 520°C to 550°C (960° to
1020°F). The reactor temperature ranges from 450°C to 550°C
(850° to 1020°F). The temperature of the flue gas from the
regenerator is between 540° and 650°C (1000° and 1200°F). A heat
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-14
-------
exchanger is applied at this point to produce steam from boiler
feedwater. The gauge pressure of the reactor vessel, risers, and
regenerator varies depending on the configuration of the unit. A
fluidized-bed reactor typically operates at low positive pres-
sure, such as 170 to 450 kPa (10 to 50 psig). Space velocity
varies with a number of operating parameters; therefore, the
range must be obtained from the unit operator.
The inspector must know the appropriate conversion factors
before he records data from the instruments in the board room.
Instruments may have been altered to protect trade secrets or to
add convenience to data recording. Pressure is usually read in
pounds per square inch gauge, but a factor of 10 may need to
applied to convert the gauge reading to the actual pressure.
Temperature is recorded in degrees Fahrenheit. Refiners have not
adopted the metric system. It is particularly important that a
conversion factor be known for flow rates.
A temperature reading well above the normal reactor tempera-
ture means that cracking is occurring. As a result, large quan-
tities of coke (carbon) are being deposited on the catalyst. The
inspector may see more particulates coming out of the CO boiler
and the ESP or scrubber. Opacity could reach levels that do not
comply with air pollution regulations if the control equipment is
not designed to handle this larger particulate load.
A low temperature usually means that the desired reaction is
not complete. The refiner will be worried about the quality of
his product, but the pollution control equipment will not be
affected.
Instead of feed rate, a recorder reports the space velocity
of feed in the riser of a fluid catalytic cracking unit. Space
velocity is defined as the ratio of the volume of inlet material
(at standard conditions and per unit of time) to the volume of
the retention space. Knowing the volume of retention space gives
the inspector the feed rate to the unit. A high or low feed rate
may result in excessive coking of the catalyst unless the operat-
ing temperature or pressure is adjusted. Excessive coking may
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-15
-------
produce a noncompliant opacity level because of particulate
emissions. The inspector should ask for the feed rate to the
unit when entering the control room.
Several readings are important for observing the status of
ESP's. The control room reports the primary and secondary cur-
rent and the primary voltage. The primary voltage should be
compared with the design value. A number less than design may
mean the system is overloaded and could short out soon. A low
(around zero) primary current value usually means that the system
has shorted out, probably because of a broken discharge wire.
Constant fluctuation in the secondary current reading means a
short is in progress. The hopper heaters should be on. The
hopper level should not be full.
The opacity recorder for the CO boiler stack is also usually
located in the control room; the opacity monitor is located in
the CO boiler stack. The instrument may be an optical trans-
missometer or an optical density meter that converts its readings
to opacity. Readings from the meter are usually in percentage of
opacity. Sometimes they are in percentage of transmittance,
which can be converted to percentage of opacity by subtracting
from 100.
Figure 4.2-1 also shows regulators labeled "TR" and "02,"
which refer to temperature recorders and oxygen analyzers. The
temperature of the gas entering the ESP must be regulated for
proper operation. A high temperature can melt electrodes or
cause heat damage to the sensitive ESP equipment. The oxygen
analyzer is a control device that monitors the extent of com-
bustion in the CO boiler. A low percentage of oxygen indicates
that some CO could be leaving the stack. A high percentage of
oxygen indicates no emission problems.
Moving-Bed Catalytic Cracking Unit
The operating conditions of a moving-bed catalytic cracking
unit are about the same as those of a fluidized-bed unit. The
reactor temperature ranges from 475° to 550°C (890° to 1022°F),
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-16
-------
with a pressure of 170 to 310 kPa (10 to 30 psig). Regenerator
temperature ranges from 675° to 760°C (1250° to 1400°F) with a
pressure of 205 to 345 kPa (15 to 35 psig). These temperatures
and pressures should be noted by the inspector. The feed rate
and catalyst temperature should also be noted.
Conversion factors should be obtained when recording data
from instruments in the board room. The instruments are often
set to read an altered version of the true value.
The preceding discussion of instrumentation for fluidized-
bed units describes the problems indicated by extreme tempera-
ture, pressure, or flow rate readings. That discussion applies
to moving-bed units as well. The information about CO boilers
and control device also applies to the moving-bed units.
4.2.5 Startup/Shutdown/Malfunctions
An FCC or moving-bed unit emits excessive particulates
during startup because of the loading of catalyst into the sy-
stem. The CO boiler that is generally associated with catalytic
crackers does not operate efficiently until the proper conditions
are achieved. As a result, CO emission rates are high during
startup. Emission rates of the other regenerator flue gas con-
taminants are also high.
Startup is defined as the time required for line out (return
to normal) and attainment of compliance with pollution regula-
tions. The typical startup time for an FCC or moving-bed unit is
1 to 7 days. In addition to problems during startup of the
cracker the pollution control equipment may also malfunction.
For example, startup of an ESP can be delayed up to 3 days if
power failure occurs or a discharge wire breaks. Malfunctions
and repair times of pollution control equipment are listed in
Table 4.2-1.
4.2.6 References
1. Refining Process Handbook. Hydrocarbon Processing, Septem-
ber 1978. pp. 109.
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-17
-------
Table 4.2-1. TYPICAL TIMES FOR REPAIR OF UNIT MALFUNCTIONS
Malfunction
Action by company
Repair time
Hot tube in CO boiler
Electrical outage
Electrical short in ESP
Excessive reaction temperature
Bypass boiler;
may emit directly
to the atmosphere
Bypass ESPs
Bypass portion
of ESP
Reduce heat input
2 days
Several hours
to days.
Several days
to months.
Several hours
Petroleum Refinery Enforcement Manual
3/80 4.2-18
Catalytic Cracking
-------
2. Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill
Book Company, New York, 1958. pp. 801-808.
Petroleum Refinery Enforcement Manual Catalytic Cracking
3/80 4.2-19
-------
VISCOSITY
BREAKING
-------
4.3 VISCOSITY BREAKING
Viscosity breaking (or "visbreaking") and coking are the two
principal thermal cracking methods used in petroleum refining
today. Visbreaking uses milder conditions than either delayed or
fluid coking to cause the thermal decomposition of large hydro-
carbon molecules. Therefore, less cracking takes place during
visbreaking than during coking.
The visbreaking process is primarily used to convert atmo-
spheric distillation bottoms and vacuum distillation bottoms into
middle distillates and a stable, heavy fuel oil with a more
favorable pour point and lower viscosity than the feed material.
If visbreaking were not used, middle distillates would have to be
added as blending (cutting) stock to lower the viscosity and pour
points. Visbreaking is thus a method for conserving valuable
middle distillates.
4.3.1 Process Description
The visbreaking process is a once-through operation. The
residue (bottoms) is preheated and fed into a tube-still (vis-
breaker) furnace, where the hydrocarbons in the residue are
partially cracked (See Figure 4.3-1). At the same time, coke is
formed through polymerization, condensation, dehydrogenation, and
dealkylation reactions. The temperature and residence time of
the process stream in the furnace are controlled. The operating
temperature of a cracking furnace, which is higher than that of
other refinery furnaces, is influenced by the type of feed. The
tubes in the heater box are heated by radiant heat from burners
located near the floor. Coke may be deposited on the hot tube
surfaces, especially in liquid phase operations; the surfaces
must be cleaned regularly to maintain efficient heat transfer. A
convection section at the top of the furnace recovers heat from
the combustion gases. This recovered heat is used to generate
steam, heat other process streams, or preheat air.
Petroleum Refinery Enforcement Manual Viscosity Breaking
3/80 4.3-1
-------
(A) V
\fl>
CO ft
O H
o
I-1
(D
to
H-
a
(0
n
^
M
3
H,
O
H
O
I
S
3
ATMOSPHERIC
AND/OR VACUUM
DISTILLATION
BOTTOMS »
* ( ' )
/^-^\
S*.
x/
n
— ' ' —
\2/
I/ISBREAKER
FURNACE
i
^4
(\
u Q-
>^
COMBINATION
TOWER
4
^
-i
\
f
1
-\
i_
/
s
^^ —
f~*\
Y
3
1 ' \X
1 v
Q KNOCKOUT POT^)
J
» rfl^ni TNP
STEAM
STRIPPER
< • STEAM
GAS OIL
TAR
H-
01
O
O
CO
H-
Figure 4.3-1. Visbreaking process.
CD
H-
a
-------
One constraint on visbreaker operation is the formation of
coke deposits because of the high temperature. Another con-
straint is the stability of the visbreaking product. The stabil-
ity of the colloidal residue solution is maintained at low per-
centages of conversion of heavy hydrocarbons to lighter mole-
cules. As conversion continues the solution becomes unstable,
and asphaltenes and coke are deposited on storage equipment and
other equipment that comes in contact with the residue. At the
conversion limit, deposits form on the visbreaking unit itself.
These two constraints are in conflict, because the produc-
tion of stable residue requires short reaction times at high
temperatures. Heat transfer must occur at a high rate, which
causes a high rate of coke formation on the heater tubes and a
decrease in the heat transfer rate. The severity of visbreaking
operation is thus limited either by excess coking or by fuel
stability, depending on the feedstock and the design of the unit.
When installing a visbreaking unit, a refiner must choose the
constraint that is more advantageous for that refinery.
The effluent from the visbreaker furnace may be rapidly
cooled (quenched) with a recycle stream of gas oil, or it may
proceed to a soaker drum (See Figure 4.3-2). The soaker drum,
which is optional, provides an additional chamber for longer
residence time and further conversion. It is separate from the
furnace, and allows the furnace to operate at slightly lower
temperatures than other visbreaking units by providing additional
residence time for conversion. Effluent from the soaking drum is
quenched.
After quenching, the visbroken mixture must be separated.
The stream enters the lower end of a combination tower, where it
is flashed (Figure 4.3-1). The visbroken bottoms ("tar") accumu-
late at the base of the tower, and the flashed vapors are frac-
tionated in the upper section of the tower. These vapors can be
fractionated into light ends, gasoline, light gas oil, and heavy
gas oil. An alternative design in the fractionating tower separ-
ates only light ends and gasoline from the visbreaker bottoms.
Petroleum Refinery Enforcement Manual Viscosity Breaking
3/80 4.3-3
-------
UJ ^
\(D
oo rt
O h(
o
I-1
01
(T)
H,
H-
H,
O
H
O
0)
0)
• 3
10 (U
I 3
*>£
ft)
ATMOSPHERIC
AND/OR VACUUM
DISTILLATION
BOTTOMS
n
FRACTIONATION
TOWER
VISBREAKER
FURNACE
SOAKER
DRUM
RECYCLE
STEAM (FOR
QUENCHING)
RESID
H-
W
O
O
Dl
H-
Figure 4.3-2. Visbreaking unit with soaker drum.
ro
H
0)
-------
This design results in less viscous bottoms, which require a
minimum of blending stock to meet viscosity specifications. In a
third design, the light ends are flashed off and the remaining
mixture routed to a fractionating tower that is operated at a
vacuum.
After separation by fractionation, the heavy gas oil frac-
tion is stripped of light ends. The gas oil may then be blended
with visbreaker bottoms to meet necessary viscosity, sulfur, and
pour-point specifications, or it may be used as feed for the
catalytic cracker. The light ends are collected from the frac-
tionator and steam stripper (stabilizer) accumulators and are fed
either to a gas recovery plant or to the refinery fuel gas sy-
stem. Visbreaker bottoms that do not contain or have not been
blended with gas oil may be used as feed for the coking unit.
The use of visbroken material depends on the demand for various
products.
4.3.2 Emission Sources
The visbreaker furnace stack is the major source of emis-
sions in a visbreaking unit (Figure 4.3-1, point 1). Particu-
lates, S09, and NO are contained in the furnace exhaust. The
£ X
amount of each pollutant emitted depends on the type of fuel
(fuel oil, natural gas, or refinery fuel gas). For example,
gaseous fuels are usually not as significant a source of parti-
culates as fuel oil.
The furnace itself can be a source of emissions during a
maintenance shutdown (Figure 4.3-1, point 2). Furnace tubes are
generally cleaned with steam-air mixtures. Coke deposits (which
contain sulfur and nitrogen) emit particulates, CO, S02/ and NO
if burned in the furnace.
The light ends collected from the fractionation and stabil-
ization stages of visbreaking may contain some H2S, which is
created by a desulfurization side reaction of the thermal crack-
ing process. Therefore, the gas stream from the accumulators is
a potential source of H2S emissions (Figure 4.3-1, point 3).
Petroleum Refinery Enforcement Manual Viscosity Breaking
3/80 4.3-5
-------
Fugitive leaks from valves, flanges, pump seals, and com-
pressor seals are sources of hydrocarbon emissions.
4.3.3 Emission Controls
Particulates, SO-, and NO are not usually emitted from
^ X
visbreaking units in large enough quantities to warrant the use
of control equipment. When coke is deposited on the tube stills,
it can be removed mechanically rather than burned. This method
avoids the excess air pollution of burning, but it creates an
additional solid waste that must be disposed.
The gas stream from the accumulators may be sent to an acid
gas treating plant to minimize H2S emissions. Sour steam conden-
sate may have to be sent to a sour water stripper. Fugitive
leaks can be controlled by proper maintenance.
4.3.4 Instrumentati on
The inspector should note the temperature and pressure of
the visbreaker furnace. The usual operating temperature is in
the range of 460° to 475°C (860° to 890°F), with pressure normal-
ly ranging from 1685 to 1825 kPa (230 to 250 psig); however, this
pressure can be as low as 445 kPa (50 psig). The feed rate
varies with the size of the unit.
The fractionation tower associated with the unit is run
either at pressure greater than 3550 kPa (500 psig) or under
vacuum conditions in order to separate the heavy material. The
pressure depends on the design of the fractionating system.
Level controls in the distillation tower indicate the amount of
material on tower plates, and the temperatures along the tower
are continuously monitored. The inspector may note the tempera-
tures at various levels to determine whether the fractionator is
operating properly (as described in Section 4.1).
Typical stream stripper operating parameters are a tempera-
ture of 302°C (575°F) at 2170 kPa (300 psig), using 3.95 kg (8.7
Ib) of steam per barrel of feed. The feed rate of gas oil into
the stripper varies with the charge to the visbreaking unit.
Petroleum Refinery Enforcement Manual Viscosity Breaking
3/80 4.3-6
-------
4.3.5 Startup/Shutdown/Malfunctions
The startup period is similar to that of a distillation
unit. The startup of the visbreaker furnace should not pose any
major problems; however, some hydrocarbons may be emitted. If
particulate control equipment or a scrubber is to be used on the
unit, emission problems may develop while the control equipment
is being brought on line.
Emissions can be significant during unit shutdown (see
Subsection 4.3.3). The shutdown procedure for a visbreaking unit
would be typical of that for a process unit turnaround. Emission
of volatile organics to the atmosphere can be minimized by vent-
ing gases from the unit to a flare or fuel gas system for as long
as possible. The preferred procedure is to purge the system to
the flare with an inert gas before opening vessels to the atmo-
sphere .
Visbreaking units run for an average of 500 days between
scheduled maintenance shutdowns. The downtime for a maintenance
turnaround averages 2 weeks; for emergency shutdowns (malfunc-
tions), the average downtime per run is 9 days. This average is
usually the total for several malfunctions, each with a downtime
of a few days. Malfunctions are the same as those for heaters
and distillation units.
4.3.6 Reference
1. Nelson, W. L., Guide to Refinery Operating Costs. The
Petroleum Publishing Company, Tulsa, Oklahoma, 1976. p. 88.
Petroleum Refinery Enforcement Manual Viscosity Breaking
3/80 4.3-7
-------
HYOROCRACKING
-------
4.4 HYDROCRACKING1'2
Of the various cracking methods available to refiners today,
hydrocracking is the most versatile. Families of catalysts have
been developed for specific uses, and processing designs allow
for efficient catalyst usage. This process, which combines
hydrogenation and catalytic cracking, can be used to upgrade a
wide range of feedstocks into lighter, more valuable products.
Because hydrogenation is involved, a hydrocracking unit also
improves the quality of the material that it processes by desul-
furizing and denitrifying it.
Hydrocrackers are used in refineries along the Gulf Coast to
produce motor fuels and light oil distillates. One-third of the
nation's hydrocracking capacity is located in California, al-
though less than one-seventh of the total refinery production is
conducted there. Hydrocrackers are prevalent in California
because the State's strict sulfur regulations sharply reduce the
marketability of high-sulfur No. 6 fuel oil. The hydrocrackers
are used to convert heavy fuel oils into lighter fuels of lower
sulfur content, such as motor or jet fuel.
The feed materials for hydrocrackers range from naphtha to
deasphalted vacuum residues. Depending on the feed, products
range from liquified petroleum gas to lubricating oils. Hydro-
cracking is especially useful in allowing the production of
gasoline or jet fuel to be maximized as needed. Often a refiner
will supplement the cracking ability of a fluidized catalytic
cracker by adding a hydrocracker unit, to which effluent from the
fluid catalytic cracking unit may be used as feed.
Several variations of the hydrocracking process with differ-
ent catalyst systems are used today, depending on the type and
compositions of the charge materials and the desired products.
H-G hydrocracking, a Gulf and Air Products process, converts
light and heavy gas oils into lower boiling derivatives. Flexi-
cracking, an Exxon process, uses feed material such as vacuum gas
oils, catalytic cycle oil, deasphalted oil, and paraffinic raffi-
nates to produce gasoline, naphtha, jet fuels, and midbarrel
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-1
-------
products. BP Trading Ltd. has a hydrocracking process that
converts full-range wax distillates (350° to 550°C; 660° to
1020°F) into gasoline, diesel oils, and chemical feedstocks.
Badiche Anilin und Soda-Fabrik AG and Institute Francais du
Petrole processes use heavy sour feedstocks composed of naphthas,
middle distillates, virgin gas oil, and deasphalted vacuum resi-
dues as charge material. Products from these processes include
liquefied petroleum gas (LPG), naphthas for petrochemicals,
gasoline, jet fuel, and diesel oil. Chevron's isocracking,
Standard Oil's ultracracking, and Union Oil's unicracking are
other hydrocracking techniques used in the refining industry.
4.4.1 Process Description
The typical hydrocracking process is carried out in one or
two stages, depending upon the concentrations of nitrogen and
sulfur in the feedstock. Feedstocks having high nitrogen and/or
sulfur content are processed in two reactor stages, as are those
with high concentrations of unsaturates or aromatics. Converse-
ly, feedstocks with low concentrations of sulfur and nitrogen and
high concentrations of saturates are generally hydrocracked in a
one-stage unit.
Two-Stage Hydrocracking
In a two-stage hydrocracking process (Figure 4.4-1) the
first reactor has a hydrogen-rich atmosphere and acts as a hydro-
desulfurizer (or hydrotreater, see Section 4.9). It is run at
high temperature and pressure. The catalyst bed is fixed, and
therefore occasional shutdowns are required for catalyst regen-
eration. In this reactor, an exothermic reaction causes unsatu-
rates to become saturated and nitrogen and sulfur from the feed
to be converted into ammonia (NH~) and hydrogen sulfide (H2S).
Partial cracking also occurs in the first reactor.
The catalyst used in hydrocrackers must provide sites for
hydrogenation and cracking reactions. The various catalysts cur-
rently available differ in degree of acidity, hydrogenation
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-2
-------
co hd
\fD
co rt
on
o
I—'
0>
SO
tt>
H,
H-
0
tt>
O
CD
I
MAKEUP •-
HYDROGEN
FEED
HYDROGEN-RICH GAS
*• FUEL GAS
*• LIGHT ENDS
PRODUCT
o
o
Figure 4.4-1. Two-stage hydrocracking unit.
o
pr
H-
-------
activity, surface area, and porosity. The type of feed and the
products desired dictate the type of catalyst selected.
In many two-stage hydrocrackers, particularly in older
units, NH3 and H2S must be separated from the effluent of the
first-stage reactor. If the NH3 and H2S are not separated from
the organic phase, these impurities may poison the catalyst in
the second-stage reactor. Newer hydrocrackers use ammonia-
resistant catalyst and the separation step is omitted. Instead,
NH3 and H2S impurities are removed during the fractionation
process that follows the second-stage reactor.
Where a separation is required between the reactors, efflu-
ent from the first-stage reactor is cooled by heat exchange with
reactor feed. Water is then added to the product stream so that
most of the ammonia is extracted from the organic phase. Then
the mixture is sent to a high-pressure separator, which yields a
hydrogen-rich gas containing significant amounts of H2S, a hydro-
carbon liquid phase containing some H2S and very little NH3/ and
a water phase containing most of the NEU impurities and a small
amount of H2S.
The hydrogen-rich gas stream is recycled to the reactors.
Makeup hydrogen is fed to the first reactor to replace the hydro-
gen consumed in the reaction. The hydrocarbon liquid phase
contains a mixture of the desired products and unreacted feed;
therefore, it is sent to a fractionating tower. The water phase
is sent to a sour water stripper or wastewater treatment.
In the fractionating section, the hydrocarbon liquids from
the first-stage high-pressure separator are added to the hydro-
carbon liquids from a high-pressure separator associated with the
second reactor. Together, these liquids are fed to a low-pres-
sure separator. The lower pressure causes more fuel gas to be
flashed out of the liquid. The remaining liquid flows to a
stabilizer, where more H2S and light ends are stripped out and
taken overhead. The effluent from the stabilizer then flows to
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-4
-------
the fractionating tower, in which the desired products are separ-
ated. The fractionator bottoms are the unreacted feed, which is
sent to the second reactor.
In the second reactor, cracking of the organics is completed
to extinction by continuously recycling any converted effluent.
Makeup hydrogen is also continually fed to the second reactor.
The operating conditions of the second reactor are less severe
than those of the first reactor.
One-Stage Hydrocracking
One-stage hydrocracking units crack and hydrogenate the
distillate charge in one reactor (see Figure 4.4-2). The charge
generally contains less sulfur and nitrogen than the charge to a
two-stage hydrocracker, but the catalyst is more sulfur-resistant
than catalyst used in the second stage of a two-stage hydrocrack-
er. The reactor generally is the fixed-bed type, with a regener-
able catalyst.
Hydrogen is introduced to the feed stream and the mixture is
preheated, then fed into the reactor, which is run at high tem-
peratures and pressures. The hydrogen-rich atmosphere allows
hydrogenation to take place along with the cracking reactions.
The reactions are highly exothermic and should cause the reactor
temperature to increase dramatically. Operating temperature can
be maintained, however, by injecting cold recycle gas that has
been scrubbed for removal of H2S, or cold, fresh hydrogen between
the catalyst beds.
The reactor effluent contains a gas phase and a liquid
phase. The gas phase is rich in hydrogen and contains H2S; this
stream is routed to a sour gas scrubber and then to a recycle gas
compressor. The liquid phase contains hydrocarbons and is re-
covered as the product mixture. This mixture is routed to a
fractionator, where it is separated into the desired fractions.
Gasoline and middle distillates are the usual products from a
one-stage hydrocracker.
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-5
-------
CO
\
oo
o
CD
c
3
50
0>
Hi
H-
3
(D
HI
O
M
o
rn
y
rt
s
cn
MAKEUP
HYDROGEN •
FRESH FEED*—j
RECYCLE HYDROGEN
REACTOR
v'W—U
SOUR GAS SCRUBBER
KNOCKOUT!
J
I
RECYCLE FEED
k
r
FRACT
PRODUCTS
ffi
o
n
h!
ft)
o
Figure 4.4-2. One-stage hydrocracking unit.
H-
3
-------
4.4.2 Emission Sources
Because the material fed into a two-stage hydrocracking unit
generally contains significant amounts of sulfur and/or nitrogen
impurities, there is a potential for emission of sulfur and
nitrogen compounds. For example, the bleed gas from the hydro-
gen-rich gas in the first reaction stage of a two-stage unit may
contain 0.5 to 1.5 percent by volume of H2S (Figure 4.4-1, point
1). Light ends and fuel gas produced in the unit also contain
some H2S, and these streams must be treated for ELS removal
(Figure 4.4-1, points 2, 3, and 4).
Sour water is a byproduct of the high- and low-pressure
separators and the stabilizer accumulator in a two-stage reactor.
This sour water, a potential source of H2S and NH3 emissions
(Figure 4.4-1, points 5, 6 and 7), must be treated for removal of
these impurities.
Catalyst regeneration is a significant source of carbon
monoxide emissions in both one- and two-stage hydrocracking
units. The coke that accumulates on the catalyst must be burned
off, a process that generates carbon monoxide. (Figure 4.4-1,
points 8 and 9; Figure 4.4-2, point 1).
Regeneration may also cause particulate emissions. Use of
steam in the catalyst regeneration process results in some con-
taminated, condensed steam, which becomes another sour water
waste stream and thus a potential source of NH3 and H2S emis-
sions.
Because feedstocks to a one-stage hydrocracking unit are low
in sulfur and nitrogen content, the concentrations of H2S and NH3
in waste streams are low, and these streams are not considered
significant sources of emissions.
Common to all units are hydrocarbon emissions from leaks in
valves, flanges, threaded fittings, pump seals, and compressor
seals. The 1978 study by the California Air Resources Board
showed leakage in 2.5 percent of the 2344 sources of fugitive
emissions inspected at hydrocracking units. In the survey of
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-7
-------
entire refineries, the highest percentage of leaking equipment in
a single unit was 11.0 percent at the isomerization unit. The
lowest percentage of leaks was 1.1 percent at the coking unit.
4.4.3 Emission Controls
Sour gas (acid gas) streams (overhead from separators, fuel
gas, and light ends) must be treated for the removal of H2S to
prevent H2S emissions. The H2S is removed by absorption into an
alkaline solution under fairly high pressure.
The solution is then regenerated by heating at low pressure.
Among several available sour gas treatment processes, the primary
difference is in the alkaline absorbants. Commonly used absorb-
ing media include an aqueous monoethanolamine (MEA) solution, a
diethanolamine (DEA) solution, and a potassium carbonate solution
(Section 4.14).
Sour water streams from the high- and low-pressure separa-
tors and the stabilizer accumulator must be stripped of H~S and
£*
NH~ (Section 4.21.1). Carbon monoxide emissions can be controlled
by incineration in a CO boiler (Subsection 4.2.3), but this is
generally not needed for a hydrocracking unit because CO emis-
sions occur only during catalyst regeneration.
Hydrocarbon emissions from equipment leaks can be controlled
by proper maintenance.
4.4.4 Instrumentation
Pressure and temperature are key parameters in this opera-
tion. In two-stage hydrocracking, pressures of about 20,684 kPa
(3000 psia) and a temperature of 371°C (700°F) must be maintained
during the hydrocracking reaction step or first stage. The
second-stage (or fractionator bottom hydrocracking reaction) is
controlled at 10,342 kPa (1500 psia) and 316°C (600°F). Each
reactor is equipped with a temperature and flow recorder and
controller. Because the reactions are exothermic, cold hydrogen
is injected to control the reactor's temperature. High-pressure
water separators that remove sulfur and nitrogen from the hydro-
carbons are equipped with level controllers and flow controllers
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-8
-------
and recorders. Temperature control is unnecessary during the
water/oil separation.
Several controls are needed in the distillation phase of
hydrocracking. Level and pressure controllers are used for the
first fuel gas separation step. The stabilizer section is moni-
tored for temperature, flow, and level. The overheads from the
stabilizer go into an accumulator, where the fuel gas exit is
pressure-controlled and the light ends are controlled by level.
The bottoms from the stabilizer to the fractionator are con-
trolled by level, as are the strippers and accumulator. The
fractionator reboiler is controlled by flow and the overhead
return by temperature.
4.4.5 Startup/Shutdown/Malfunctions
The startup of a hydrocracking unit involves stabilizing the
reactors and the fractionator temperatures and pressures. The
major sources of emissions during startup are the catalyst bed
(particulates) and leaks (hydrocarbons). The H2S and NH3 gener-
ated in the hydrocracking unit may be accidentally emitted to the
atmosphere during the startup period if the systems for treatment
of sour gas and sour water are inadequate. The length of the
startup period is variable.
Periodic shutdowns of the hydrocracker are necessary for
catalyst regeneration as well as for routine maintenance and
emergencies. As mentioned, carbon monoxide emissions and the
sour water waste stream are significant potential problems during
catalyst regeneration. When the catalyst is replaced every 2
years or so, particulate emissions may occur if the catalyst is
spilled. During process unit turnarounds, all vapors should be
routed to the flare or the refinery fuel gas system to prevent
emission of hydrocarbons, NH-, H2S, or other gases.
The malfunctions in a hydrocracking unit are similar to
those that may occur in catalytic crackers, hydrotreaters, or
fractionators (distillation units). These include electrical
problems, insufficient separation in the fractionator, water in
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-9
-------
the unit, leaks resulting in pressure drop, and other mechanical
problems. The frequency of malfunctions is not predictable.
4.4.6 References
1. Billon, A., et al. More Ways To Use Hydrocracking. Hydro-
carbon Processing, May 1978. pp. 122-127.
2. McGrath, H. G., and M. E. Charles. Origin and Refining of
Petroleum. American Chemical Society, 1971, pp. 113-129.
Petroleum Refinery Enforcement Manual Hydrocracking
3/80 4.4-10
-------
CATALYTIC
REFORMING
-------
4.5 CATALYTIC REFORMING1'2'3
The need to increase the antiknock properties of naphtha as
a blending stock for motor fuels is the greatest single reason
for installing catalytic reforming. Catalytic reforming was dis-
covered during the search for ways to improve thermal reforming,
one of the first reforming processes. Researchers sought to
eliminate the destruction of paraffins inherent in thermal re-
forming and to create a method for synthesizing aromatics. The
catalytic reforming method, in which noble metals were originally
used for catalysts, emerged as a more selective process, promot-
ing desired reactions and minimizing unwanted ones.
4.5.1 Process Description
Catalytic reforming processes involve a complicated series
of catalytic reactions that change the chemical structure of the
hydrocarbons. The hydrocarbon reforming process can be described
in terms of the following four principal reactions: (1) dehydro-
genation of naphthenes to aromatics to near completion with very
little ring rupture; (2) isomerization of paraffins to more
highly branched forms; (3) dehydrocyclization of paraffins to
aromatics; and (4) hydrocracking of paraffins to lower molecular
weights, but with a minimum production of light hydrocarbon
gases. The predominant reaction is the dehydrogenation of naph-
thenes to form aromatics. Some of these aromatics are isolated
to become petrochemical feedstocks, but most become motor fuel
blending stocks of high antiknock quality. Table 2-2 shows each
of these reactions.
The reactions occur over a noble metal catalyst such as
platinum on alumina or platinum-rhenium. Catalysts that promote
reforming reactions can often cause the side reaction of hydro-
cracking to produce unwanted lighter products. Higher reactor
pressures would suppress hydrocracking, but would also suppress
reforming and thus would yield a product of lower antiknock
quality. Until about 10 years ago the most popular reforming
catalyst was platinum on alumina. This has since been replaced
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-1
-------
by bimetallic catalysts containing platinum plus other metal
promoters such as rhenium. The improved activity and selectivity
of these newer catalysts permit operations at lower pressures and
greater severities (i.e., higher temperatures, higher catalyst-
to-oil ratios, and lower space velocity) without shortening the
regeneration cycle. Where greater severity is not needed, the
newer catalyst gives greater throughput from existing units,
accounting in part for the increase in total capacity during the
early 1970's.
Use of the reforming catalysts developed most recently per-
mits still lower pressures, in the range of 2515 to 3550 kPa (350
to 500 psig) and greater severities. The greater severity in-
creases the formation of carbon on the catalyst (coke laydown),
which deactivates the catalyst and necessitates more frequent
catalyst regeneration.
The reforming reactions are carried out in a controlled
atmosphere of pressurized hydrogen to inhibit undesirable side
reactions such as the production of olefins; this atmosphere
reduces susceptibility to oxidation and enhances stability in
storage. The hydrogen also minimizes coke laydown.
Most feedstocks for reforming are hydrotreated first to re-
move arsenic, sulfur, and nitrogen compounds, which would poison
the reforming catalyst. The cost of the hydrotreating step is
justified by the extended life of the reforming catalyst.
Various types of catalytic reforming systems in use in the
United States include Platforming, Ultraforming, Powerforming,
Magnaforming, Houdriforming, and catforming.
Platforming
Platforming, the original catalytic reforming system, is the
most widely used. The Platforming unit consists of five major
sections: (1) reactors containing the particulate catalyst in
fixed beds, (2) heaters that bring hydrotreated naphtha charge
and recycle gas to reaction temperature and provide the heat of
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-2
-------
reaction, (3) a product cooling system and a liquid/gas separa-
tor, (4) a hydrogen gas recycle system, and, (5) a fractionator
to separate light hydrocarbons dissolved in the separator liquid.
Platforming units have at least three adiabatic reactor ves-
sels, each containing particulate catalyst in a fixed bed, opera-
ting in series. Figure 4.5-1 shows the process flow for a Plat-
forming unit. Because the reaction between the combined feed and
the catalyst is so highly endothermic, it is necessary to heat
the feed before it enters each reactor. After the reaction
process, the effluent from the last reactor is cooled and sent to
the receiver, where it is separated into a gas and a liquid
stream. Most of the gas, which is largely hydrogen, is compress-
ed and recycled into the reactors, where it provides the protec-
tive pressurized hydrogen atmosphere. The remainder of the gas
comprises a net hydrogen product stream; it is withdrawn from the
system by the pressure control on the reaction system. The
liquid stream from the receiver, which contains dissolved light
hydrocarbons, is routed to the fractionator, in which a stabil-
ized reformate is produced for blending into finished gasoline
pools.
The most variation in design of a Platforming unit is in
catalyst regeneration. In Platforming systems that operate at
relatively high pressures and with high ratios of recycle gas to
naphtha feed, the catalyst degenerates slowly; this allows for an
uninterrupted process run, which ranges from few months to more
than a year. The length of the run is determined by the deter-
ioration of the catalyst. Either the reactor inlet temperature
requirement exceeds the capacity of the heater or catalyst selec-
tivity diminishes to the point that it is economical to shut down
the unit and regenerate the catalyst.
The catalyst is either regenerated at the refinery or is
shipped offsite and replaced with new catalyst. The in-place
regeneration procedure burns the carbon deposits from the cata-
lyst by using the recycle compressor to circulate an air/combus-
tion gas products mixture through the reactor at a controlled
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-3
-------
CD ft
O H
O
50
fl>
Hi
H-
3
0)
H
W
O
(D
(D
• 3
en (u
O
(U
ft
ft
H-
O
50
0>
REACTORS
REACTOR-PRODUCT
SEPARATOR
STABILIZER
STABILIZER
RECEIVER
HEATER
TO
AMINE UNIT
COMPRESSOR
Fiqure 4.5-1. Process flow diaqram of Platforming unit.
-------
burning temperature. This process returns catalytic capacity to
the level it held before regeneration. To eliminate much of the
downtime necessary to complete in-place regeneration, some Plat-
forming systems completely replace the spent catalyst.
A second type of regeneration operates at lower pressure and
low ratios of recycle gas to naphtha feed. The catalyst of these
Platforming units deteriorates rapidly, and the catalyst must be
changed often. To avoid long periods of downtime, such units are
equipped with an extra reactor, so that each reactor can be
isolated at least once a day for regeneration. Without shutdown
of the system, the "swing-reactor" system provides reformate
yields of a given octane number, but the cost of installation and
operation are considerably higher.
Processes other than Platforming have stressed the regenera-
bility of the catalyst. The platinum catalysts are difficult to
regenerate, but development work has provided techniques that
restore a substantial portion of the reforming characteristics of
the catalyst. Advantage is taken of the ability to regenerate
the catalyst by operating at lower pressures and thus increasing
liquid product yields. The trend in the design of semiregenera-
tive processes is to operate in the range of 2515 kPa (350 psig).
Ultraforming and Powerforming
The Ultraforming and Powerforming processes are cyclic
regenerative processes operating for relatively short on-stream
periods. The catalyst is rugged, and a regeneration-rejuvenation
technique effectively restores the catalyst's reforming charac-
teristics. As a result, these processes take full advantage of
the high yields at low pressures and operate at about 1480 kPa
(200 psig) with low recycle gas rates. Capital investment for
the cyclic units is high, but they reform naphthas effectively to
high octane levels. These processes are very similar to Plat-
forming; therefore, no process description is included.
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-5
-------
Magnaforming
The Magnaforming concept supplements the improvements in
catalysts with processing conditions that optimize catalyst use
and performance. The Magnaforming process decreases the amount
of recycle gas to the first reforming reactor and increases the
recycle gas to the last reactor. Figure 4.5-2 shows the process
flow in Magnaforming. In the primary reforming reactor, the
dehydrogenation of naphthenes is rapid and highly endothermic. A
large temperature drop occurs, with the result that the system
approaches the thermodynamic equilibrium of the naphthene-aroma-
tic-hydrogen system. This slows down the dehydrogenation reac-
tion relative to the hydrocracking reaction. By decreasing
hydrogen to the first reactor this effect is minimized, and gas
production caused by hydrocracking is decreased.
Magnaforming differs from the other reforming process by use
of a four-reactor rather than three-reactor system, with inlet
temperatures ascending from the first to the last reactor. The
mole ratio of recycle gas to feed might be 2.5 to 3 in the first
reactor and 9 to 10 in the last reactor. Liquid yields higher by
at least 1 to 2 percent and increases in hydrogen production have
been obtained with both platinum and platinum-rhenium catalysts.
This higher yield reportedly justifies a 6.5 percent increase in
investment for the Magnaforming design over conventional three-
reactor systems.
Process flows for IFF (Institute Francais du Petrole) re-
forming, Houdriforming, Powerforming, Rheniforming, and Ultra-
forming are described in the September 1978 "Hydrocarbon Process-
o
ing." These processes have either semiregeneration or cyclic
catalytic regeneration. Basically, they are similar in operation
to Platforming or Magnaforming but a different bimetallic cata-
lyst gives different yields.
4.5.2 Emission Sources
The catalytic reforming process unit is a closed system.
The only continuous emissions are those from process heaters
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-6
-------
CD
o
O
M
CD
50
(D
H)
H-
§
M
0
Hi
O
h
O
fD
• 3
en tu
O
(U
rt
H-
O
FIRED HEATER
M M M M
REFORMING
REACTORS
NAPHTHA
HYDROGEN
HYDROGEN
HYDROGEN TO
HYDROGEN PLANT
M
REACTOR
PRODUCTS
FRACTIONATOR
TO
STABILIZER
HYDROGEN COMPRESSOR
(D
Hi
O
9
H-
Figure 4.5-2. Process flow diagram of Magnaforming unit.
-------
(Figure 4.5-1, point 3), the hydrogen sulfide in the fuel gas
stream (Figure 4.5-1, point 2), a small volume of wastewater
containing a low concentration of oil that is produced by the
reformer overhead accumulator (Figure 4.5-1, point 4), and possi-
ble equipment leaks.
Unlike fluid catalytic cracking catalysts, which are regen-
erated continuously, reforming catalysts are regenerated period-
ically. Figure 4.5-1, point 1, shows the emission point of these
gases during regeneration. A steam and air mixture is introduced
to the catalyst bed, causing combustion of the coke deposits.
The combustion may produce carbon monoxide (CO) and unoxidized
hydrocarbons. AP-42 estimates the emissions from this source at
0.240 to 2.4 grams/liter (0.002 to 0.02 lb/bbl);3 this quantity
is considered negligible. These emissions could become signifi-
cant, however, if the unit required frequent regeneration.
The study by the California Air Resources Board found that
reformers contributed 1.5 percent of the total refinery fugitive
emissions. Among the devices tested, leakage was found in 12
percent of the threaded fittings, 2.8 percent of the valves, 2.1
percent of the valve outlets, and 3.6 percent of the pump seals.
4.5.3 Emission Controls
Emissions from process heaters can be reduced by desul-
furization of the fuel. Generally, particulates can be con-
trolled by proper operating practices and adjustment of the
air-to-fuel ratio.
The fuel gas stream goes to the amine unit for hydrogen
sulfide (H2S), which is eventually handled in the sulfur plant.
Therefore, H2S is not an emission problem at the reforming unit.
The wastewater from the overhead accumulator (stabilizer
receiver) is collected and sent to the refinery's wastewater
treatment facility. Generally the concentration of oil is low
and does not pose a volatile organic emission problem.
The principal control measure for hydrocarbons in catalyst
regeneration flue gas is incineration in a heater firebox or
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-8
-------
smoke plume burner. These devices reduce hydrocarbon emissions
to negligible quantities. Use of a control device on these re-
generator offgases is not widespread, however, because this
emission source is not considered significant. Incineration of
organics containing sulfur may produce SO emissions. Incinera-
a
tion also can produce CO and NO emissions.
X
The fugitive emission sources can best be controlled by
instituting a good maintenance program.
4.5.4 Instrumentation
The inspector should monitor stack opacity to determine
whether process heaters are a source of particulate emissions.
The type of fuel and its sulfur should be noted for indications
of sulfur emissions.
Since frequent regeneration can cause emissions of carbon
monoxide and volatile organics, the inspector's attention will be
focused on changes in process parameters that lead to regenera-
tion. Frequency of regeneration is determined by the severity of
the operations, type of feed, and availability of hydrogen.
With the platinum reforming catalyst at a pressure of
2515 kPa (350 psig), regeneration is usually infrequent because
the catalyst ages slowly. At 1480 kPa (200 psig), however, the
catalyst ages rapidly and frequent regeneration is needed. The
platinum-rhenium catalysts age less rapidly than platinum; it is
possible to regenerate infrequently by operating at a lower
pressure and thus to realize higher liquid product yields and
higher hydrogen production.
It is important for the inspector to realize that pressure
is the controlling variable that determines whether the dehydro-
genation or hydrocracking reaction predominates. Hydrocracking
is promoted by high pressure, and dehydrogenation by low pres-
sure. Generally speaking, an increase in liquid product yield at
a given octane number is accompanied by an increase in hydrogen
production to satisfy the carbon-hydrogen balance of the system.
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-9
-------
Therefore, the operating pressure of the unit varies with
reforming feed, reforming catalyst, and the ratio of hydrogen to
hydrocarbon. Table 4.5-1 summarizes the octane numbers associ-
ated with high and low severity operations. A low pressure may
lead to rapid catalyst aging and necessitate more frequent regen-
eration, which causes emissions of hydrocarbons and carbon mon-
oxide.
The reformers generally operate at temperatures between 430°
and 480°C (800° and 900°F). The operating temperatures may fall
outside this range when relatively heavier or lighter feedstocks
are processed.
Hydrogen pressure is an important control variable, since it
inhibits undesirable side reactions and delays coking of the
catalyst. The pressure of the unit is monitored.
The relative yield of butanes and gas is monitored as an
indication of the catalyst activity. If yields fall, regener-
ation may be required, with the resultant emissions of hydro-
carbons and carbon monoxide.
4.5.5 Startup/Shutdown/Malfunctions
Since the stream processed in this unit must be practically
free of sulfur, startup and shutdown should not cause significant
sulfur emissions. The most frequent shutdown is for regenera-
tion. Although we have indicated that emissions of hydrocarbons
and carbon monoxide from regeneration are negligible, this be-
comes an important emission source when regeneration is frequent.
The frequency at which the catalyst is regenerated is determined
by the severity of the operation, quality of hydrogen, and type
of feed. Therefore, the frequency and duration of downtime for
regeneration cannot be estimated. Regenerating the catalyst may
generate a small amount of particulates.
On the average, the reforming unit is shut down for general
inspection once during every year of operation, but time between
shutdowns ranges from 8 to 25 months. The downtime for a sched-
uled shutdown averages 15 days.
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-10
-------
TABLE 4.5-1. NAPHTHA YIELDS UNDER VARYING CONDITIONS
1
Type of operation
Low severity operation:
Reformer pressure, kPa
Reformer pressure, psig
Weight space velocity, hourly
Volume percent C5+
High severity operation:
Pressure, kPa
Pressure, psig
Weight hourly space velocity
Volume percent C5+
Research octane number, clear
85
•<
86.5
86.5
90
95
•1135 to 3550-
-150 to 500-
1 0
i_ . O
83.0
83.8
75.0
80.0
100
55.0
2515
350
1.5
74.5
103
2515
350
1.0
71.1
105
2515
350
0.8
67.6
Petroleum Refinery Enforcement Manual
3/80 4.5-11
Catalytic Reforming
-------
The shutdown procedures follow a sequence of venting pres-
sure to the refinery flare system. Flow of feed is stopped, heat
is removed, and the unit is flushed with inert gas, then with
air. In the startup sequence, air is displaced by inert gas,
heating is started, process flow is started, and the unit is
pressurized when at temperature.
Reforming malfunctions include a decline in hydrogen purity
due to production of light ends in the reactors; loss of hydrogen
pressure due to compressor failure; loss of hydrogen due to a
malfunction at the hydrogen plant; problems in the reformer
heater such as blown tubes, hot spots, inability to control tem-
peratures in the heaters, or flame-out; loss of reformer feed-
stock due to a failure at the crude unit or hydrogen desulfuriza-
tion unit; loss of reformer feedstock due to pump failure on the
reforming unit; and loss of cooling water to the unit. The
frequency of malfunctions varies with the type of crude being
processed, severity of the operation, maintenance practices, and
reliability of upstream processes. Each of the malfunctions des-
cribed requires a different period of downtime. Emergency down-
times average 10 days.
4.5.6 References
1. Schwarzenbek, E. F. Catalytic Reforming. In H. G. McGrath
and M. E. Charles, eds., Origin and Refining of Petroleum.
American Chemical Society, Washington, D.C., 1971. p. 102.
2. Refining Handbook. Hydrocarbon Processing, 57(9): 159-166,
September 1978.
3. U.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 2nd ed. AP-42, 1979.
Petroleum Refinery Enforcement Manual Catalytic Reforming
3/80 4.5-12
-------
ALKYLATION
-------
4.6 ALKYLATION1'2
In alkylation, branched hydrocarbons are synthesized by the
addition of an alkane or aromatic hydrocarbon to an alkene (ole-
fin) in the presence of an acid catalyst. The product, alkylate,
is desirable as an antiknock additive in motor and aviation fuel.
4.6.1 Process Description
There are four types of alkylation units: hydrofluoric (HF)
acid, sulfuric acid, aluminum chloride, and thermal, the first
two being the most common. Because aluminum chloride and thermal
alkylation are not commonly used in petroleum refineries, these
processes are not discussed in this manual. Details on the
aluminum chloride alkylation process are given in Reference 1,
and on the thermal alkylation process, in Reference 2. A discus-
sion of the hydrofluoric acid and sulfuric acid alkylation units
follows.
Hydrofluoric Acid Alkylation
In a hydrofluoric acid alkylation process, an isoparaffin is
combined with an olefin or olefin mixture to form a highly
branched, high-octane gasoline component. Isobutane may be
alkylated with propylene, butylenes, amylenes, or even higher
boiling olefins. The particular olefin used as a reactant deter-
mines the octane number of the alkylate produced. Butylenes or a
mixture of butylenes and propylene are the most common olefin
charge stocks. A simplified block diagram, Figure 4.6-1, depicts
the complex flow of this process. This is a conceptual diagram
that represents the activities occurring in the process; the size
of the blocks does not indicate the relative importance of the
process steps. Figure 4.6-2 is a typical process flow diagram.
The mixture of olefins and isobutane is introduced into a
vessel that serves as both a reactor and settler (see
Figure 4.6-2). At the same time, hydrofluoric acid is fed into
the reactor/settler vessel. The hydrogen ion from the acid
initiates a reaction with the hydrocarbon mixture, leading to the
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-1
-------
U) ^
\fl>
OD rt
o n
o
50
fl>
Hi
en
i
o
13
3
tU
RECYCLE ISOPARAFFIN
ISOPARAFFIN
SUCH AS
ISOBUTANE
OLEFIN
SUCH AS
BUTYLENE
REACTOR
HYDROFLUORIC
ACID FROM HF
RERUN UNIT
SETTLER
Q-
Q
»—i
O
HYDROCARBON
PHASE
ISOBUTANE
FRACTIONATOR
TO
HF RERUN UNIT
PROPANE
CUT
ALKYLATE
FRACTION
DEBUTANIZER
ISOBUTANE
HF
STRIPPER
PROPANE
TO
CAUSTIC
WASH
STABILIZED
ALKYLATE
fl)
ft
Figure 4.6-1. Block flow diagram of hydrofluoric acid alkylation.
-------
\n>
oo ft
Ohj
o
M
0>
0)
13
rt)
M
P
H,
O
M
O
CD
(D
MAIN
FRACTIONATOR
HF
STRIPPER
RECYCLE
ISOBUTANE
COMBINED
REACTOR/
SETTLER
DRY
BUTYLENE
PROPYLENE •-
AMYLENE
FEED
DRY
ISOBUTANE *"
•FROM HF
RERUN
UNIT
OPTIONAL
DEBUTANIZER
•TO CONVEN-
TIONAL HF sr
RERUN UNITV
n-BUTANE
TO CAUSTIC
*- WASH
STABILIZED
»- ALKYLATE
£
LPG PROPANE
*- TO CAUSTIC
WASH
O
P
Figure 4.6-2. Process flow diagram of hydrofluoric acid alkylation.
-------
formation of alkylate. Settling results in a hydrocarbon phase
and an acid phase.
The hydrocarbon phase consists of propane (small quantities
inevitably enter the reactor with the isobutane and olefin),
alkylate product, recycle isobutane, and some hydrofluoric acid.
The acid phase consists of hydrofluoric acid saturated with
hydrocarbons. So that acid may continue to catalyze the alkyla-
tion reaction, this saturated acid must be regenerated or fresh
acid must be supplied. An acid rerun tower may be used for
purification of the HF stream. In regeneration of the acid, tar
is produced as a byproduct.
The hydrocarbon phase flows to the main fractionator for
separation into isobutane that is recycled to the reactor, a
propane cut that continues to the HF stripper, and an alkylate
fraction.
In the HF stripper, dissolved hydrofluoric acid and isobu-
tane are removed from the propane cut. The resulting propane
then goes to caustic treating for final removal of traces of HF.
The isobutane is recycled to the reactor. The amount of HF in
the HF stripper is regulated by recycling.
The alkylate fraction may be routed to a debutanizer, or the
vapor side stream from the main fractionator that contains alkyl-
ates may be steam stripped to remove butane (Figure 4.6-2). The
stabilized alkylate contains traces of hydrofluoric acid and
organically combined fluorides, which must be removed before the
alkylate is used in gasoline blending.
Sulfuric Acid Alkylation
Isobutane and the olefin butene (also called butylene) are
used primarily as feedstocks in the sulfuric acid alkylation
process. Strength of the sulfuric acid catalyst is approximately
94 to 98 percent. Because the acid becomes saturated with hydro-
carbons and thus loses strength, the acid must be regenerated to
catalyze the alkylation reaction further. Spent acid from the
Petroleum Refinery Enforcement Manual . Alkylation
3/80 4.6-4
-------
process is generally exchanged for fresh acid from a supplier and
shipped offsite for regeneration.
Two common means of sulfuric acid alkylation are by effluent
refrigeration and cascade autorefrigeration. A discussion of
each process follows.
Sulfuric Acid Alkylation With Effluent Refrigeration
The simplified block flow diagram, Figure 4.6-3, gives a
conceptual idea of this complex process. Figure 4.6-4 illu-
strates the process flow.
In the effluent refrigeration system, the olefin and isopar-
affin (isobutane) streams are mixed before entering the horizon-
tal reactor. In the reactor, contact of the hydrocarbon mixture
with concentrated sulfuric acid is achieved by circulation of the
liquid contents at high velocities for 5 to 40 minutes to induce
mixing. The resulting reactions are exothermic. The reaction
forms an emulsion of 35 to 50 percent hydrocarbons and 50 to
65 percent sulfuric acid, which is sent to the settler for separ-
ation. Since some of the acid becomes saturated with hydro-
carbons, fresh acid is needed to maintain enough acid strength to
initiate the alkylation reaction. The separated hydrocarbons
undergo pressure reduction, which causes vaporization and cooling
of the hydrocarbons. The cooled hydrocarbons (consisting mainly
of isobutane) flow through the reactor cooling elements and act
as a refrigerant. Since the reaction is exothermic, this cooling
is necessary.
The mixture of liquids and vapors from the cooling elements
flow to the vapor-liquid separator (Figure 4.6-4). The liquid
mixture is treated in the treating section, while the vapors are
compressed and condensed. The condensate flows to an accumulator
and then to the depropanizer. The propane overhead is sent to
the refinery fuel gas system and the depropanizer bottoms undergo
pressure reduction, then are sent to a flash drum. In the flash
drum, the bottoms and some liquid from the accumulator are par-
tially vaporized.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-5
-------
oo ft
O H
O
M
CD
i
so
o>
H)
H-
3
td
3
HI
o
rt>
(D
0
ft
SB
(U
ft
H-
O
OLEFIN
SUCH AS
BUTYLENE;
ISOPARAFFIN
SUCH AS
ISOBUTANE
HYDROCARBON
PHASE ..
PRESSURE
REDUCTION
VAPOR (MAINLY ISOBUTANE)
VAPOR-LIQUID
SEPARATOR
ISOBUTANE
DEISOBUTANIZER
Figure 4.6-3. Block flow diagram of sulfuric acid alkylation with effluent refrigeration.
-------
co IT)
\n>
oo rt-
Ohj
o
M
01
CD
CD
n
CD
-------
The liquid from the vapor-liquid separator is cold [approxi-
mately -8°C (18°F)]. This stream undergoes heat exchange with
the fresh feed before proceeding to a treating section. Treat-
ment consists of a caustic wash followed by a water wash. After
treatment, the liquid stream is routed to the deisobutanizer.
The resulting isobutane is recycled as reactor feed. The alky-
late product is in the deisobutanizer bottoms, which are handled
in various ways depending on the end usage of the alkylate.
Generally, some normal butane is removed if the alkylate is to be
used in aviation or motor fuels. Additional fractionation is
needed for alkylate used in aviation gasoline, in which an exact
end point is required.
Sulfuric Acid Alkylation With Cascade Autorefrigeration
Cascade autorefrigeration is similar to effluent refriger-
tion except that a multicompartment reactor/settler vessel is
used rather than a single compartment reactor with separate
settling vessel. There are usually two to eight reactor com-
partments (zones) in a multicomponent reactor/settler. The
number of zones depends on the capacity of the reactor. Fig-
ure 4.6-5 is a simplified block diagram showing this process.
In cascade refrigeration the olefin feed is cooled in a
flash drum (illustrated in Figure 4.6-6 as a combination flash
drum and heat exchanger) and undergoes indirect heat exchange.
Recycle isobutane is also cycled through the flash drum/heat
exchanger. The olefin is fed in parallel to each reactor zone.
Isobutane and sulfuric acid are introduced into the reactor
before the first reactor zone. The resulting mixture of these
two liquids flows in series, or cascades, through the reactor
zones and reacts exothermally with the olefin. The light hydro-
carbons evaporate directly from the hydrocarbon-sulfuric acid
reaction mixture and thus cause cooling by evaporation. Because
this process cools the reaction without the use of cooling ele-
ments, it is called autorefrigeration. The liquids from the last
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-8
-------
CO l-tj
\tt>
oo ft
O
M
(D
£
*>
(D
H)
H-
P
0)
i-h
O
M
O
(D
en
OLEFIN
DEPROPANIZER
ISOBUTANE
HYDROCARBON VAPOR
FLASH DRUM/
HEAT
EXCHANGER
ACIDJH2S04) A
ISOBUTANE
RECYCLE ISOBUTANE
n-BUTANE
rt
H-
o
Figure 4.6-5. Block flow diagram of sulfuric acid alkylation with cascade autorefrigeration.
-------
oo
O
M
(D
£
5d
0)
HI
H-
3
(D
H
^
M
3
i-h
O
n
O
(D
0)
CT« fU
I S
MC
O fl)
DEPROPANIZER
PROPANE
OLEFIN FEED
ISOBUTANE
DEISOBUTANIZER
HYDROCARBON VAPORS
fFLASH DRUM/ REACTOR
HEAT
EXCHANGER
i, ,, .. j, ji
ISOBUTANE
I
OLEFIN
SETTLER
SPENT ACID
FRESH ACID
ACID RECYCLE-
)
TREATING
SECTION
n-BUTANE
DEBUTANIZER
ALKYLATE
FRACTIONATION RECYCLE ISOBUTANE
rt
H-
o
Figure 4.6-6. Process flow diagram of sulfuric acid alkylation with cascade autorefriaeration.
-------
reactor zone flow into the settler section of the reactor/settler
vessel, where the acid separates from the hydrocarbon.
After the acid is separated from the hydrocarbon, the acid
is recycled. Spent acid is removed and fresh acid supplied as
necessary. Some of the acid is contaminated by hydrocarbons.
Additional acid is needed to maintain enough acid strength to
initiate the alkylation reaction. The liquid hydrocarbon phase
contains the alkylate. This phase undergoes treating, deisobu-
tanizing (shown as DeIC4 in Figure 4.6-5), debutanizing (shown as
DeC4), and other finishing steps of the effluent refrigeration
process.
The hydrocarbon vapor phase (rich in isobutane and propane)
is sent from the settler to a compressor. Vapors from the flash
drum/heat exchanger also enter the compressor. Following com-
pression is condensation. The condensate enters an accumulator.
The resulting vapors are routed to a depropanizer, while the
liquids are added to depropanizer bottoms. These liquids undergo
pressure reduction for cooling before they enter the flash drum.
The isobutane from the flash drum is recycled to the reactor.
4.6.2 Emission Sources
The alkylation units are potential sources of particulates,
fluorides, sulfur oxides, and volatile organic compounds.
Potential emission points of particulates include emissions
from fired heaters (Figure 4.6-2, point 1).
Potential emissions of fluorides shown in Figure 4.6-2
include the following:
1. Hydrofluoric acid and organically combined fluorides
that appear in the following streams: n-butane
(point 2), stabilized alkylate (point 3), and propane
(point 4).
2. A waste stream from the HF acid regenerator (point 5);
this stream is either incinerated or treated with an
alkaline solution to recover the fluoride as a solid
waste, which is placed in a landfill.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-11
-------
3. Some HF units may incorporate a process vent from the
main fractionator accumulator (point 6) for releasing
noncondensable ethane from the system. Generally,
however, the alkylation processes are closed systems
with no process vents to the atmosphere because of
possible discharges containing HF. The system includes
vents from pumps, exchangers, and all equipment in acid
service, all of which discharge to an alkaline scrub-
ber, where HF is removed before the stream is exhausted
to the atmosphere or a blowdown system. Scrubbing is
done with spent caustic, lime slurry, or potassium
hydroxide. The recovered fluoride is placed in a
landfill.
Potential sulfur emissions from alkylation units are as
follows:
1. Sulfur oxides from process heaters (Figure 4.6-2,
point 1).
2. Liquid wastes associated with water and caustic scrub-
bing of feed and product streams (Figure 4.6-4 point 1;
Figure 4.6-6, point 1). These wastes are generally
processed in the refinery's neutralization and waste-
water treatment facilites.
3. Small quantities of liquid containing sulfuric acid,
from the depropanizer accumulator (Figure 4.6-4, point
2; Figure 4.6-6, point 2).
In both the hydrofluoric acid and sulfuric acid alkylation
units, leaks are a major source of emissions of hydrocarbons,
organic fluorides, and organic sulfides. The highly corrosive
acid makes these units susceptible to leaks.
4.6.3 Emission Controls
Alkylation units are not equipped with common air pollution
control equipment as used in the fluid catalytic cracking unit.
This section therefore describes the operating practices used to
control emissions.
The sulfur oxide emissions from process heaters can be
reduced by desulfurization of the fuel. Generally, particulates
can be controlled by proper operating practices and by adjustment
of the air-to-fuel ratio.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-12
-------
In the hydrofluoric alkylation unit, potential emissions of
hydrofluoric acid and organically combined fluorides are con-
trolled by the following procedures.
Butanes and alkylate leaving the unit are passed over walnut-
sized potassium hydroxide (KOH) pellets to remove any traces of
acid. These streams are also protected by bubblers, which re-
quire only visual checking. Bottoms from the HF stripper are
also passed over walnut-sized KOH pellets to prevent any entrain-
ment of HF with the propane.
A hot bauxite treatment is commonly used to reduce combined
fluoride to less than 10 ppm in the propane stream.
A neutralization pit handles area runoff, condensate, and
liquid wastes. Lime is added to remove the acid by formation of
insoluble calcium fluoride. The recovered fluoride goes to a
landfill.
The relief gas system can use a knockout drum and liquid KOH
scrubber. A small flow of dry sweep gas is passed through the
scrubbers continuously to maintain constant operation.
Dispersal of caustic vapors or hydrocarbon vapors to the
atmosphere can be controlled by using a vapor recovery system to
confine the vapors and vent them to a flare. The HF process
usually has an alkaline scrubber that removes HF prior to flar-
ing. Walnut-sized potassium hydroxide pellets are usually used
for scrubbing. The potassium fluoride is treated with lime. The
resulting calcium fluoride goes to landfill.
In the sulfuric acid alkylation process, the liquid wastes
associated with water and caustic scrubbing of the feed and
product streams can be controlled by processing in the refinery's
neutralization and wastewater treatment facilities.
The spent sulfuric acid, which may be shipped offsite for
regeneration, is saturated with volatile hydrocarbons. The
hydrocarbon vapors can be controlled by flaring or incineration.
A study by the California Air Resources Board revealed that
an alkylation unit contributes 8.4 percent of the total refinery
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-13
-------
fugitive emissions; emissions from this unit occur by leakage
from valves, flanges, threaded fittings, valve outlets, pump
seals, and compressor seals. The pump seals in the alkylation
unit leak the most (33 percent of all seals). Leaks were found
at 30 percent of the threaded fittings, 18 percent of the valves,
and 0.4 percent of the flanges; no leaks were found at valve
outlets or compressor seals. All leakage can be limited by
proper maintenance.
Because prompt maintenance is the only feasible control for
fugitive emissions, prompt detection of emissions is critical.
Detection of HF leaks is important because of the physiological
hazard as well as the potential for damage to equipment. Studs
exposed to acid may suffer stress corrosion cracking or embrit-
tlement in a short period of time. Flanged connections at points
where HF can be present are usually painted with a special indi-
cating paint, which turns from brillant orange to yellow when it
comes in contact with acid. This change in color is often the
first indication of a leaking joint.
Lines carrying HF may be jacketed to contain any possible
leakage. A water spray or alkali dump system is usually provided
for use in the event that a mechanical failure releases acid.
A differential conductivity cell records continuously the
amount of electrolyte in the secondary water from the unit before
it is discharged. The secondary water used in HF regeneration is
also checked because large volumes of acid could escape to the
system if a leak developed. Caustic is injected to the secondary
water when HF is detected.
4.6.4 Ins trumentati on
Neither the hydrofluoric acid or the sulfuric acid alkyla-
tion unit is operated under severe conditions. Tables 4.6-1
and 4.6-2 list the operating ranges of the hydrofluoric acid and
sulfuric acid alkylation processes. The inspector should note
the exact values of these operating parameters, because values
outside of target ranges may result in excess emissions.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-14
-------
TABLE 4.6-1. RANGES OF OPERATING CONDITIONS
FOR HYDROFLUORIC ACID ALKYLATIONa
Process parameter
Operating range
Pressure, kPa
Pressure, psig
Temperature, °C
Temperature, °F
Ratio of isobutane/olefin
in feed
Olefin contact time, min
Catalyst acidity, wt %
Acid in emulsion, vol %
790 to 1135
100 to 150
15 to 52
60 to 125
3 to 12
8 to 20
80 to 95
25 to 80
Reference 2, p. 134.
Petroleum Refinery Enforcement Manual
3/80 4.6-15
Alkylation
-------
TABLE 4.6-2. RANGES OF OPERATING CONDITIONS
FOR SULFURIC ACID ALKYLATIONa
Process parameter
Operating range
Pressure, kPa
Pressure, psig
Temperature, °C
Temperature, °F
Ratio of isobutane/olefin
in feed
Olefin space velocity,
volume of olefin per hour
per volume of acid
Olefin contact time, min
Catalyst acidity, wt %
Acid in emulsion, vol %
445 to 790
50 to 100
2 to 15
35 to 60
3 to 12
0.1 to 0.6
20 to 30
88 to 95
40 to 60
Reference 2, p. 134.
Petroleum Refinery Enforcement Manual
3/80 4.6-16
Alkylation
-------
The sulfuric acid units usually operate at temperatures
between 2° and 15°C (35° and 60°F). For processing of butylenes,
the range is 2° to 13°C (35° to 55°F). For processing of olefin
feed mixtures containing high percentages of propylene, the
preferred range is 10° to 15°C (50° to 60°F). Therefore, the
inspector should note both the temperature and the type of feed.
Temperatures above the upper limit can cause cracking of the
feed and lighter products, and concentration of acid in the
lighter products. The caustic scrubbers could become overloaded
with resulting excess emissions of organics and fluorides.
Usual operating range of the HF unit is 15° to 50°C (60° to
125°F). The unit operating temperature is usually set by the
temperature of the available cooling water. Higher octane alky-
late can be produced at temperatures around 15°C (60°F).
Inadequate temperature control leads to reduction of alkyl-
ate yields and octane numbers, and to an increase in acid con-
sumption. With increasing acid consumption, the scrubbers or
caustic treaters may become overloaded, as may the acid recovery
unit; these overloads would cause emissions.
Pressure has no significant effect on alkylation reactions
as long as it is high enough to maintain a liquid phase, which is
needed for the reaction to occur. Short contact time or high
space velocity can adversely affect alkylate yield and quality.
Prompt detection and remedy of leakage from valves, flanges,
threaded fittings, pump seals, and compressor seals are essential
for control of fugitive emissions.
4.6.5 Startup/Shutdown/Malfunctions
During startup of an alkylation unit (which requires a
minimum of 1.5 days), leaks in equipment would lead to emissions.
The quantities of hydrocarbons and acid vapors emitted depend on
the processing equipment used at the unit. Because of the vari-
ability in process equipment and in operating conditions, it is
impossible to specify a time frame for identifying and repairing
such leaks.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-17
-------
Malfunctions requiring the emergency shutdown of one or more
components can cause emissions of hydrocarbons (and sometimes
acid) unless the refinery vents vapors to a flare or fuel gas
system.
Leakage is a common problem with alkylation units and can
necessitate shutdown of the unit. Generally, streams can be
rerouted while leaks are being repaired. Repair usually requires
1 day or less.
On most alkylation units steam reboilers are used rather
than heaters to heat the fractionating towers. The use of direct-
fired furnaces for deisobutanizer column reboilers can provide
thermal defluorination of the alkylate product. The only type of
malfunction associated with steam reboilers is tube blockage,
which is rare. Malfunctions in the fractionators are the same as
those in other fractionators.
When malfunctions do occur, emergency downtime for the
entire alkylation unit averages about 10 days. This figure may
represent several shutdowns, which may occur before the unit can
resume normal operation. On an average, shutdown for general
unit inspection occurs once every year of operation, within a
range of 9 to 16 months between shutdowns. The downtime for a
scheduled shutdown is generally about 15 days.
4.6.6 References
1. Dickenspn, R. L. and W. S. Reveal. Ethylene Alkylate:
Commercial Production by the Shell Process. American Petro-
leum Proceedings, 1971.
2. Lafferty, Jr., W. L. and R. W. Stokeld. Alkylation and Iso-
merization. In H. G. McGrath and M. E. Charles, eds.,
Origin and Refining of Petroleum, American Chemical Society,
1971.
Petroleum Refinery Enforcement Manual Alkylation
3/80 4.6-18
-------
ISOMERIZATION
-------
4.7 ISOMERIZATION
The isomerization process is similar to catalytic reforming
in that both rearrange the molecular form of a feedstock while
reducing the losses that normally occur in cracking or condensa-
tion reactions. An isomerization reaction is illustrated in
Table 2-2. This process is used to upgrade normal paraffins
(straight-chain hydrocarbons) to isoparaffins (branched-chain
hydrocarbons).
4.7.1 Process Description
The isomerization process is usually applied to butane or to
mixtures of pentane and hexane. When butane is the feedstock,
the isobutane product is normally used as feed to an alkylation
unit. Pentane/hexane feeds, from crude distillation of catalytic
reforming, are processed to improve their octane ratings, and the
product is blended to gasoline. Pentane, having a research
octane rating of about 62, can be converted into isopentane
having a research octane rating of 92.
Isomerization catalysts were developed along two paths: (1)
Friedel-Crafts halide systems and (2) dual-site heterogeneous
catalysts, which originated with the commercial introduction of
platinum-aluminas for catalytic reforming in the 1940"s. The
Friedel-Crafts systems (aluminum chloride-hydrocarbon complexes)
were used exclusively during the early stages of World War II,
when the first commercial processes were introduced to manufac-
ture isobutane as a feedstock for alkylate for aircraft. This
practice is now obsolete, chiefly because the extreme reactivity
of the catalyst initiated a number of side reactions that led to
destruction of the reactants and products.
The new method uses noble metal catalysts on a solid cata-
lyst support. The feed is mixed with hydrogen to suppress un-
wanted reactions.
The main types of isomerization use butane, pentane, hexane,
or xylene as feedstocks. Because butane and mixtures of pentane
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-1
-------
and hexane are the most common, this section focuses on isomeri-
zation units that use these feedstocks. The xylene isomerization
unit is not common in refineries, and is not described here.
Details of the xylene unit are given in Hydrocarbon Processing,
November 1977, pp. 237-239.
Butane Isomerization
The butane isomerization process (also called Butamer)
converts normal butane into isobutane in the presence of a
platinum-containing catalyst and hydrogen. The hydrogen sup-
presses the polymerization of trace amounts of olefins formed
during the isomerization reaction. Figure 4.7-1 illustrates the
butane isomerization process.
A mixed butane feedstock enters the deisobutanizer tower,
where the isobutane product is taken overhead. A sidestream of
normal butane from the deisobutanizer is mixed with hydrogen
recycle, raised to reaction temperatures of 150° to 200°C (300°
to 400°F) and made to flow over the fixed-bed catalyst. A high-
activity, selective catalyst promotes the desired conversion of
normal butane to isobutane at low temperatures, so that equili-
brium conditions are favored. Table 4.7-1 summarizes the operat-
ing conditions. The reactor effluent is cooled and then routed
to a high-pressure separator for recovery of the hydrogen. Gas
from the separator and a small amount of makeup hydrogen are
recycled to the reactor by means of a compressor. Separator
liquid is sent to the stabilizer for removal of coproduct light
gas (hydrogen, ethane, and propane) overhead. This gas flows to
the refinery fuel gas system. The stabilizer bottoms are re-
turned to the deisobutanizer, where isobutane from the fresh feed
and that produced in the isomerization reactor are recovered
overhead. The normal butane is recycled until it is converted to
isobutane.
A small amount (parts per million) of organic chloride is
added to the feed to help maintain catalyst activity by replacing
the hydrogen chloride lost in the stabilizer overhead.
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-2
-------
oo rt
o H
o
M
(D
o»
HI
H-
3
(D
H
><
W
o
(D
• 3
vs
01
DEISOBUTANIZER
C4 PRODUCT
BUTANE
FEEDl
ISOMERIZED BUTANES RECYCLE
ORGANIC xKO
CHLORIDE MAKEUP ISOMERIZATION
MAKEUP GAS REACTOR
C5+ REJECT
TO FUEL GAS
STABILIZER
CO
o
(D
I-!
H-
N
&)
rt
H-
O
Figure 4.7-1. Butane isomerization process.
-------
TABLE 4.7-1. OPERATING CONDITIONS FOR
BUTANE ISOMERIZATION
Process parameter
Operating range
Reactor pressure, kPa
Reactor pressure, psig
Reactor temperature, °C
Reactor temperature, °F
Liquid hourly space velocity3
Mole/ratio of hydrogen to oil
in feed
1400 to 2860
200 to 400
150 to 200
300 to 400
3 to 5
0.1 to 0.5:1
Dimensionless number
Petroleum Refinery Enforcement Manual
3/80 4.7-4
Isomerization
-------
The platinum-containing catalyst is activated and regener-
ated "in situ" (in place). Because of the hydroscopic nature of
the isomerization catalyst system, a regenerable catalyst offers
the refiner ease in reactor loading and operating flexibility.
Pentane and/or Hexane Isomerization
Pentane, hexane, or a mixture of the two from straight-run
catalytic reforming or solvent extraction is processed in an
isomerization unit to increase the octane rating of pentane
and/or hexane fractions. The isomerization reaction takes place
in a hydrogen atmosphere to minimize polymerization. Figure
4.7-2 illustrates the pentane/hexane isomerization process.
Before being processed in the isomerization unit, the feed
is treated in a conventional hydrodesulfurization unit to remove
sulfur, which would poison the isomerization catalyst. The
desulfurized feed is mixed with hydrogen, heated, and passed over
the platinum-containing catalyst in a lead reactor, in which the
aromatics and olefins are saturated. Isomerization of normal
paraffins to isoparaffins also occurs in the lead reactor. The
reactor effluent is cooled before entering the tail reactor, in
which further isomerization takes place at more favorable, low-
temperature" conditions. When pentane is the feed, only one
reactor is used. Tail reactor effluent is cooled and sent to a
high-pressure separator. Gas from this separator, together with
a small amount of makeup hydrogen, is recycled to the reactors.
Separator liquid flows to a stabilizer, and the stabilizer off-
gas goes to the refinery fuel gas system. The stabilizer bottoms
give a final product suitable for blending directly into motor
gasoline. A small amount of organic chloride is added to the
feedstock to help maintain catalyst activity by replacing the
hydrogen chloride lost in the stabilizer overheads.
The catalyst is highly active and selective so as to provide
high product yield, depending on feedstock. Long cycle times of
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-5
-------
\n»
oo r*-
on
o
M
(D
s?
Hi
H-
3
(D
K
W
O
1-1
o
(D
3
(D
tu
ORGANIC
CHLORIDE MAKEUP
LEAD
ISOMERIZATION
REACTOR
DRIED DESULFURIZED FEED
MAKEUP H
TAIL
ISOMERIZATION
REACTOR
TO FUEL
GAS VIA
CAUSTIC
J WASH
LIGHT ENDS/HCL STRIPPER
PRODUCT
TO STORAGE
CO
I
i-l
H-
N
CD
rt
Figure 4.7-2. Pentane/hexane isomerization process flow.
-------
up to 2 years have been observed, but should accidental deactiva-
tion occur, the catalyst can be easily regenerated and reacti-
vated to full activity.
The reactor pressure ranges from 2170 to 7000 kPa (300 to
1000 psig), with operation usually around 300 psig. The lead
reactor temperature ranges from 150° to 260°C (300° to 500°F),
and the tail reactor temperature ranges from 120° to 205°C (250°
to 400°F). The lower temperature is more favorable for isopar-
affin yields.
4.7.2 Emission Sources
Isomerization is a closed process. Because the feed must be
nearly sulfur-free to protect the catalyst, the gas streams are
not contaminated with hydrogen sulfide.
Combustion gases from the fired heaters (Figure 4.7-1, point
1, and Figure 4.7-2, point 1) are a source of particulate and
sulfur oxide emissions.
Isomerization also can emit hydrogen chloride. Organic
chloride added to the feed to increase catalyst activity even-
tually shows up in the vapor stream as hydrogen chloride. Most
of the hydrogen chloride is recycled to the process, but some of
it is eliminated with the stabilizer overhead. (Figure 4.7-1,
point 2, and Figure 4.7-2, point 2). This gas should be treated
to remove the hydrogen chloride before the gas is burned as fuel.
Unlike the catalysts of fluid catalytic cracking, which are
regenerated continuously, isomerization catalysts are regenerated
only periodically. Figure 4.7-1, point 3, and Figure 4.7-2,
points 3 and 4, show the emission points during regeneration. The
isomerization catalyst is very stable and can be expected to last
at least 2 years before regeneration. During regeneration, the
introduction of a steam and air mixture to the catalyst bed
caused combustion of the coke deposits. This combustion may
produce carbon monoxide (CO) and unoxidized hydrocarbons. Some
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-7
-------
refiners replace the spent catalyst by returning it to the cata-
lyst manufacturer rather than regenerating. Thus, the catalyst
is not an emission source at these refineries.
The California Air Resources Board found that isomerization
units contribute 11 percent of the total fugitive emissions at a
refinery. Among the devices tested, 14 percent of the valves
leaked and none of the flanges leaked.
4.7.3 Emission Controls
Emissions from process heaters can be reduced by desulfuri-
zation of the fuel. Generally, particulates can be controlled by
proper operating practices and adjustment of the air-to-fuel
ratio.
The fuel gas stream goes to caustic treating for hydrogen
chloride removal. The caustic solution neutralizes the hydrogen
chloride. The resulting calcium chloride is then disposed of by
landfilling.
The principal control measure for hydrocarbons in catalyst
regeneration flue gas is incineration in a heater firebox, or use
of a smoke plume burner. These devices reduce hydrocarbon emis-
sions to negligible quantities. Since these emissions are infre-
quent and insignificant in volume, control devices are not com-
monly applied to regeneration offgases. Many refiners return the
spent catalyst to the manufacturer and replace it with fresh
catalyst, thereby reducing hydrocarbon emissions from regenera-
tion.
Fugitive emissions can best be controlled by adherence to a
good maintenance program.
4.7.4 Instrumentation
The type of feed and flowrate are monitored. As discussed
earlier, the type of feed results in different process flow
schemes. The feed rate should be compared with design values. A
flowrate lower than the design value may indicate that the reac-
tor will soon be regenerated.
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-8
-------
Reactor temperatures are very important. Temperatures
outside the design range may indicate that hydrocracking is
occurring. Deposition of coke on the catalyst necessitates
regeneration, which causes emissions. As discussed earlier, low
temperatures lead to poor yields of product.
The inspector should monitor the organic chloride makeup
rate. A high rate may indicate a high concentration of hydrogen
chloride in the stabilizer overhead or deactivation of the cata-
lyst. With high concentrations of hydrogen chloride in the
stabilizer overhead, the caustic wash unit should be checked to
determine whether it is designed to reduce these higher con-
centrations to acceptable concentrations. When the catalyst is
deactivated, it must be regenerated or replaced.
4.7.5 Startup/Shutdown/Malfunctions
Since the stream processed in the isomerization unit must be
nearly free of sulfur, startups and shutdowns should not cause
significant sulfur emissions. Subsection 4.7.2 discusses the
negligible quantity of carbon monoxide and hydrocarbon emissions
from regeneration. The frequency at which the catalyst is regen-
erated is determined by the quality of the feed and type of feed.
Therefore, estimates of downtime for regeneration are not avail-
able.
On the average, this unit is shut down for general inspec-
tion once each year of operation. Average downtime for a sched-
uled shutdown is 10 days.
The shutdown procedure follows a sequence of venting to the
refinery flare, stopping the feed flow, removing heat, and flush-
ing with inert gas, followed by flushing with air. In startup,
air is displaced with inert gas, which is then heated and the
process flow starts. The unit is pressurized when at tempera-
ture.
Malfunctions on an isomerization unit include a loss of
hydrogen due to a compressor failure or to a malfunction at the
hydrogen plant; loss of isomerization feed due to a malfunction
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-9
-------
upstream (i.e., hydrogen desulfurization unit, crude unit); and
loss of temperature control. The frequency of malfunctions
varies with the type of feed, quality of the feed, refinery main-
tenance practices, and reliability of upstream processes. Gen-
erally, emergency downtime for this unit averages 5 days.
4.7.6 Reference
1. Refining Process Handbook. Hydrocarbon Processing, 57(9):
170-172, September 1978.
Petroleum Refinery Enforcement Manual Isomerization
3/80 4.7-10
-------
POLYMERIZATION
-------
4.8 POLYMERIZATION1'5
Like alkylation, polymerization is a formation process used
to produce a high-octane gasoline from refinery gases. In poly-
merization, however, only the olefinic gases in the feed react,
linking together to form olefinic liquid. Any paraffinic gases
in the feed pass through the process unchanged. Unlike the
alkylation unit, which requires an olefin and isoparaffin for
feed, the polymerization unit requires two olefins. An example
of a polymerization reaction is two molecules of isobutylene
(C^Hg, an olefin) combining to form one molecule of a branched-
chain octylene (CgH-,,.). With the rising importance of olefins as
petrochemical feedstock, polymerization is being phased out as a
refining process. It is discussed here because some units are
still used by refiners.
4.8.1 Process Description
Polymerization is a continuous, catalytic conversion of
olefin gases to liquid condensation products. The feed usually
consists of propylene and/or butylene from cracking operations,
which is processed to form polymer gasoline for motor gasoline
blending. The feed is usually caustic washed and water washed to
remove sulfur and nitrogen compounds.
The treated, olefin-rich feed stream is brought into contact
with a catalyst consisting of a solid support impregnated with
solid phosphoric acid or liquid phosphoric acid.
Polymerization with Solid Phosphoric Acid
The olefin-rich feed enters the top of a fixed catalyst bed.
Pellets impregnated with the phosphoric acid catalyst are packed
in the fixed reactor, which operates at temperatures between 175°
and 225°C (350° and 435°F) and pressures of 2860 and 8375 kPa
(400 to 1200 psig), depending on the feedstock and desired octane
rating of the product. The exothermic reaction temperature is
controlled in a chamber reactor using depropanizer overhead as
recycle to the feed and as the quench stream between catalyst
Petroleum Refinery Enforcement Manual Polymerization
3/80 4.8-1
-------
chambers. Figure 4.8-1 illustates the process flow of a polymer-
ization unit with a solid phosphoric acid catalyst in a chamber
reactor. Addition of the depropanizer overheads to the feed
reduces the olefin concentration, with the result that less heat
is produced in the polymerization reaction.
The reactor effluent flows to the depropanizer, where pro-
pane and lighter gases are removed overhead. The depropanizer
bottoms flow to the debutanizer, where butane is removed overhead
and the product, polymer gasoline, is removed as bottoms.
Polymerization with Liquid Phosphoric Acid Catalyst
The olefin feed is caustic washed for removal of hydrogen
sulfide and mercaptans, then water washed for removal of nitrogen
compounds. Figure 4.8-2 illustrates the flow of this process.
The liquid phosphoric acid catalyst is brought into intimate
contact with the hydrocarbon feed in the reactor, which operates
at temperatures of 150° to 205°C (300° to 400°F) and pressures of
1135 to 2860 kPa (150 to 400 psig). The hydrocarbon polymer and
acid from the reactor are separated in a settler vessel, and the
acid is returned to the reactor after cooling. The hydrocarbon
from the settler is caustic scrubbed to protect the product
recovery equipment from acid carryover. In normal operation, all
of the acid is removed from the hydrocarbon stream in the set-
tler, and consumption of caustic is negligible. The hydrocarbon
stream then flows to the stabilizer, from which liquid petroleum
gas is recovered overhead and the product, polymer gasoline, is
recovered as bottoms.
4.8.2 Emission Sources
The polymerization unit is a potential source of sulfur,
phosphoric acid, and volatile organic emissions.
The main source of sulfur emissions is the caustic washing
section of the process, which removes mercaptans and hydrogen
sulfide from the feed (Figure 4.8-1, point 1; Figure 4.8-2,
Petroleum Refinery Enforcement Manual Polymerization
3/80 4.8-2
-------
\tt>
oo rt
o H
O
M
fD
£
(D
H,
H-
M
3
H,
O
H
O
i
(D
00 OJ
i 3
w e:
PROPANE RECYCLE
OLEFIN
FEED 1
POLYMER GASOLINE
PROPANE AND
LIGHTER
hO—O
SULFIDE
AND
MERCAPTANS
NITROGEN
COMPOUNDS
X
UJ
Q.
O
a:
a.
BUTANE
r
Bl
DEPROPANIZER
REACTOR
DE-
BUTANIZER
(D
H
H-
N
0)
ft
H-
O
3
Figure 4.8-1. Process flow of polymerization with solid phosphoric acid catalyst.
-------
oo rt
o h
o
M
(D
50
(D
ft)
1-1
W
13
HI
O
h
o
(D
• 2
oo tu
l 3
^ C
(u
—J LIQUID
r->/ )—*• PETROLEUM
I ^-^ GAS
X*Sv
STABILIZER
REACTOR
STEAM
OLEFIN
FEED
CAUSTIC
WASH
WATER
WASH
\
POLYMER
GASOLINE
^2N HYDROGEN NITROGEN STEAM
" SULFIDE AND COMPOUNDS
MERCAPTAN
ACID
PUMP
(D
M
H-
N
(U
d-
H-
O
Figure 4.8-2. Process flow of polymerization with liquid phosphoric acid catalyst.
-------
point 1). Sulfur emissions occur when the sulfur content of the
feed exceeds the design value for the caustic washing section.
In the solid phosphoric acid process, the only waste stream
is the spent catalyst (Figure 4.8-1, point 2). This spent cata-
lyst contains volatile organics and phosphoric acid. The cata-
lyst must be replaced periodically, and it is usually more eco-
nomical to dispose of it than to regenerate it. Disposal of the
catalyst causes a minimal amount of emissions.
In the liquid phosphoric acid process, the acid may carry-
over from the settler to the liquid petroleum gas and polymer
gasoline. The caustic scrubber neutralizes these potential acid-
saturated organic emissions.
The process is a closed system with no vents to the atmos-
phere. Some fugitive emissions may occur. The California Air
Resources Board did not include this unit in its study, and the
sources of these fugitive emissions have not been identified.
4.8.3 Emission Controls
Because this process is essentially a closed system with no
vents to the atmosphere, it is not equipped with typical pollu-
tion control devices such as a CO boiler.
The sulfur emissions are essentially eliminated by caustic
washing. The resulting calcium sulfate can be disposed of in a
landfill.
Emissions of hydrocarbon and acid from catalyst disposal can
be reduced by minimizing the number of turnarounds on the unit
and by use of a flare. The catalyst must be regenerated if it
comes in contact with nitrogen; therefore, the water washing must
satisfactorily remove the nitrogen compounds.
Only orthophosphoric acid (H3P04) is a catalyst; metaphos-
phoric acid (HPO.,) is inactive. Water is added to the feed to
form orthophosphoric acid. Too much water will turn the solid
catalyst to mud and render it corrosive. Temperature control is
also important because high temperatures cause cracking, which
leads to coke deposits on the catalyst, rendering it inactive.
Petroleum Refinery Enforcement Manual Polymerization
3/80 4.8-5
-------
High temperatures also dry the catalyst and reduce its activity.
When the catalyst is regenerated, volatile organic emissions
should be flared. A discussion of the regeneration procedure
follows in Subsection 4.8.5.
The liquid catalyst can be replaced continuously without
interrupting plant operation.
The liquid acid carryover is effectively controlled by the
caustic scrubber, in which the lime neutralizes any acid.
4.8.4 Ins trumentati on
Temperatures of solid catalyst reactors range from 175° to
225°C (350° to 435°F), and of liquid catalyst reactors, from 150°
to 205°C (300° to 400°F). Temperature depends on the type of
feed and desired octane rating of the product. As discussed
earlier, high temperatures cause cracking and deposition of coke
on the catalysts, and thereby necessitate regeneration. Regen-
eration or replacement of the catalyst generates emissions of
acid-saturated hydrocarbons. The temperature is monitored, as
are feed type and product octane rating. Since these parameters
are interrelated, the inspector may note that time between turn-
arounds depends on one of them.
4.8.5 Startup/Shutdown/Malfunctions
The liquid acid process can be started up rapidly, typically
in 1 to 2 hours, because a liquid catalyst circulates through
heat exchangers and thus facilitates rapid but controllable
heating, with no need for propane recycle.
The reactor using a solid acid catalyst takes 8 to 16 hours
for startup. Most of the time is for heating the catalyst bed
and establishing propane for recycling.
Shutdown of the liquid catalyst process takes about 4 hours;
shutdown of the solid catalyst process takes 6 to 8 hours to cool
the reactor and unload the catalyst. Regenerating the solid
catalyst bed takes 10 to 16 hours. Regeneration is achieved by
passing air at 340°C (650°F) into the reactor at such a rate that
the temperature does not exceed 510°C (950°F) (hot spots cause
Petroleum Refinery Enforcement Manual Polymerization
3/80 4.8-6
-------
volatilization of the acid). The catalyst is hydrated by main-
taining an atmosphere of steam at 260°C (500°F). When air is
passed over the catalyst during regeneration, the volatile organ-
ics leave the system and should be flared.
Common malfunctions include loss of feed due to an upset at
an upstream unit, pump failures, reactor feed distribution prob-
lems, and temperature control problems. The frequency of the
malfunctions varies with the type of feed, operating conditions
used to produce the needed octane of the polymer gasoline, refin-
ery maintenance practices, and reliability of upstream processes.
Because each malfunction involves a different downtime, emergency
downtime for this unit cannot be reliably estimated.
4.8.6 References
1. Bland, W. F., and R. L. Davidson. Petroleum Processing
Handbook. McGraw-Hill Book Company, Inc., New York, 1967.
pp. 3-58 and 3-61.
2. Chemical Technology: An Encyclopedic Treatment Vol. IV.
Petroleum and Organic Chemicals Barnes and Noble Books, New
York, 1972. p. 54.
3. Kirk-Othmer Encyclopedia of Chemical Technology. Vol. 10.
John Wiley & Sons, New York, 1966. p. 475.
4. Kirk-Othmer Encyclopedia of Chemical Technology. Vol. 16.
John Wiley & Sons, New York, 1966. p. 592.
5. Nelson, W. L. Petroleum Refinery Engineering. 4th ed.
McGraw-Hill Book Company, New York, 1969. pp. 722-736.
Petroleum Refinery Enforcement Manual Polymerization
3/80 4.8-7
-------
TREATING
-------
4.9 CRUDE AND PRODUCT TREATING1'2
Most refineries include some form of crude desalting as the
first step. Inorganic salts, which can cause corrosion, plugging
of exchangers, and coking of furnaces, are removed from crude
oils by electrical and chemical desalting processes. These
processes also remove arsenic and other trace metals that can
poison the catalysts in later processes.
Many commercial treating processes are available to remove
undesirable impurities, such as acids and sulfur compounds, and
to improve color, odor, and stability of refinery petroleum
products. The principal treating processes are chemical sweet-
ening, lube treating, and hydrotreating. Hydrotreating is dis-
cussed in Section 4.10.
4.9.1 Process Description
Crude desalting and the two treating processes of chemical
sweetening and lube treating are described in this section.
Crude Desalting
Electrostatic and chemical desalting processes remove inor-
ganic salts and trace metals from crude oils. The electrostatic
desalting process, which is more widely used, is discussed here
in greater detail.
In electrical desalting, water and demulsifier chemicals are
added to dissolve impurities from the crude oil. The crude,
water, and chemical mixture is then exchanged with products to
raise its temperature. The heat lowers the surface temperature
of the oil causing the water to agglomerate. The mixture then
flows through a mixing valve resulting in an emulsion. The
emulsion is then introduced to a treating vessel, where an elec-
trostatic field causes the water droplets to agglomerate and
settle to the lower portion of the vessel. A small quantity of a
demulsifying chemical is sometimes added to treat crude or slop
oils that have abnormally high concentrations of suspended sol-
ids. The treated crude flows to the atmospheric distillation
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-1
-------
CJ htf
\
CD rt
Oh
o
0)
Hi
H-
3
(D
H,
o
h
O
(D
n
I
n>
0)
WATER •-
CHEMICALS •-
PUMP
CRUDE OIL •-
CRUDE AND
PRODUCT HEAT
EXCHANGER
TREATED CRUDE
DISTILLATION
COLUMN)
DESALTER
CHARGE
PUMP
WATER
(TO WASTEWATER
TREATMENT SYSTEM)
••a
I-!
o
o
rt
Figure 4.9-1. Flow diagram of desalting process.
fD
(u
ft
H-
&
-------
column. The water containing salt, flows to the wastewater
treatment facility. Figure 4.9-1 illustrates this matter.
In chemical desalting, inorganic salts are separated from
oil by water washing in the presence of chemicals. The chemicals
that are used depend on the type of salts and the nature of the
crude oil.
The chemicals are added to the crude oil upstream from the
charge pump so that they are mixed thoroughly with the oil.
Fresh water is added to dissolve the salts not already in solu-
tion. The crude oil and fresh water are passed through a mixing
valve to form an emulsion and assure good contact. In some
cases, water is added upstream from the charge pump so that the
emulsion is formed by the pump impellers. The emulsion of water
in oil is then heated before it enters the settler to a temper-
ature that ranges from 65° to 180°C (150° to 350°F), depending on
the type of crude being processed. The surface tension of the
oil is lowered by heat, thus allowing water particles to coagu-
late. Similarly, the reduced viscosity of the oil offers less
resistance to separation of the salt solution.
The settler, which may be equipped with baffles to reduce
flow turbulence and channeling, has a settling time of from 20 to
60 minutes. The treated crude oil flows from the top of the
settler for further processing in a distillation column. The
salts are withdrawn as a solution in water and discharged to the
wastewater treatment system.
A two- or three-stage electrostatic or chemical desalting
process may be used to reduce the salt content of crude oil
before it enters the crude distillation tower. The increased
investment cost for multiple stages is offset by reduction in
corrosion, plugging, and catalyst poisoning in downstream equip-
ment.
Chemical Sweetening
Chemical sweetening improves the color and odor of petroleum
products by eliminating mercaptans (R-SH; SH is a thiol group
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-3
-------
attached to an organic alkyl radical such as CH3 or C2Hc), H2S,
and dissolved free sulfur. The three most common chemical sweet-
ening processes are solvent extraction, Bender sweetening, and
oxidation sweetening.
The original solvent extraction process for sulfur reduction
was simple caustic washing. Most of the patented processes are
modifications of caustic washing to make thiols more soluble in
the caustic solution. Some of the solvent extraction processes,
primarily used for gasoline treating, are briefly described
below.
Solutizer process
In this process, the sour gasoline is contacted counter-
currently in the extraction column with a "solutizer11 solu-
tion—a 25 percent caustic solution containing a small
amount of splutizing agent such as potassium isobutyl rate.
The solutizing agent makes thiols more soluble in caustic
solution and enables complete removal of thiols from gaso-
line.
Unisol process
The Unisol or caustic methanol process uses methanol at the
center of the packed treating column and caustic soda
throughout the entire length of the column. Sour gasoline
is passed through this column to extract H2S and mercaptans.
Small amounts of methanol are lost with the gasoline. The
methanol must be distilled after.it (and mercaptans) has
been steam stripped from the caustic.
Caustic washing
In this process, sour gasoline is contacted with sodium,
calcium, or magnesium hydroxides for removal of H2S and
mercaptans. Caustic solutions ranging from 5 to 15 percent
are used.
Bender sweetening is used to treat such distillate streams
as light naphtha, gasoline, kerosene, and No. 2 fuel oil. It is
especially effective for the treatment of jet fuel. Sweetening
is accomplished by converting mercaptans to disulfides in the
presence of a fixed-bed catalyst. Figure 4.9-2 is a flow diagram
of a typical Bender sweetening process.
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-4
-------
Ui H)
\fl>
00 ft
OH
o
M
(D
B
(D
HI
H-
M
3
Hi
O
H
O
0)
1
\£> (U
Oi C
CU
O
NaOH.
SULFUR ABSORBERS
UNTREATED
DISTILLATE
ORIFICE
RESTRICTION
-I-
MIXING VALVE
i
AIR
ALKALI
TREATED
OIL OUT
CATALYST TOWERS
T1
CATALYST REMOVED
o
ft
1-3
H
(D
B>
ft
H-
Figure 4.9-2. Flow diagram of Bender sweetening process.
-------
The untreated distillate is passed through the sulfur ab-
sorber to remove H2S from the feedstock by caustic treatment.
Sulfur, small amounts of caustic solution, and air are added to
the distillate. This mixture is then passed over a bed of solid
catalyst in two catalyst towers. The caustic soda solution
enters the top of each tower. A small amount of caustic solution
is added to the distillate to maintain the effluent in a slightly
alkaline state.
Oxidation sweetening converts the sulfur in thiol to disul-
fide. The most common oxidation sweetening process is the Merox
process, which is discussed in detail in the following para-
graphs. Other processes are doctor treating (sodium plumbite the
oxidizing agent); lead sulfide sweetening (lead sulfide acts as a
catalyst and thus may be cycled as an oxidizing agent); and
copper sweetening (cupric chloride used as the oxidizing agent).
These three processes are not very common; but can be used to
convert sulfur in thiol to disulfide. Complete removal of sulfur,
however, is important to increase the effectiveness of tetraethyl-
lead (gasoline additive to improve octane number) and to reduce
corrosion by S02 or S03 in the exhaust pipes of cars.
The highly successful Merox process can be used either as a
sweetening process (converting thiols to disulfides, which remain
in the product) or as a solvent extraction process that reduces
the amount of sulfur. Both operations can be conducted on a
single feed material. Figure 4.9-3 is a flow diagram of a typi-
cal Merox process.
The sour gasoline is contacted with the caustic solution
containing the Merox catalyst to extract the mercaptans. The
extracted gasoline is then sweetened by reacting with air in the
presence of Merox-containing caustic solution. The extracted
product passes through a settler, where the Merox solution and
the sweetened gasoline are separated. The sweetened gasoline is
sent to storage and the Merox solution is recycled to the Merox
sweetener mixer.
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-6
-------
UJ
\
CD
O
n>
rt
H
o
I— I
(D
JO
0)
Hi
H-
P
0)
H
w
o
Hi
o
n
o
0>
o>
o
(D
SOUR
GASOLINE
AIR
EXCESS
AIR
DISULFIDES
( SEPARATOR J
OXIDIZER
MERCAPTAN
EXTRACTOR ^REGENERATED
MEROX SOLUTION
•—
AIR
TREATED GASOLINE
-*- TO STORAGE
SETTLER
MEROX SWEETENER
MEROX SOLUTION
RECYCLE
o
rt
H3
M
0)
Figure 4.9-3. Flow diagram of Merox process.
rt
H-
-------
The Merox solution used in the extraction is mixed with air
and regenerated in the oxidizer. In the separator, the disul-
fides (which are insoluble in the caustic) are separated as an
oil-disulfides layer, and the excess air is vented to the atmo-
sphere. The regenerated Merox solution is returned to the ex-
tractor.
A major advantage of the Merox process is the reduction of
operating costs by eliminating the large amount of steam needed
for caustic regeneration in the older sweetening processes. In
the Merox process, caustic regeneration consists only of intro-
ducing air and then settling. The heating and stripping opera-
tions used in most cyclic extraction processes are not needed.
Sweetening alone is adequate for feedstocks having moderate
or low thiol content, as with catalytic cracked gasoline. Both
Merox sweetening and extraction, however, are used for feedstocks
having high thiol content; light straight naphthas are an exam-
ple.
Lube Treating
Solvent refining processes are used to improve the viscosity
index and the paraffin content of lubricating oil stocks. Many
solvents—such as furfural, phenol, cresylic acid/propane (DUO-
SOL), liquid S0~, methyl isobutyl ketone (MIBK), and propylene/
acetone—have been used in lube treating processes. In each
case, oil and solvent are first contacted counter-currently in a
packed column or in a series of tanks, and the refined oil and
extract layers are then separated. The recovery of solvent from
the oil and extract layers is a major part of the solvent re-
covery process, and it differs according to the boiling point of
the solvent used.
The common lube treating processes are phenol extraction and
furfural refining.
Phenol extraction improves the viscosity index and color of
lubricating oils. It also reduces the tendency of the oils to
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-8
-------
form carbon and sludge. Figure 4.9-4 is a flow diagram of a
phenol extraction process.
The heated feedstock (distillates or residual feedstock)
flows through a phenol absorber tower to recover the small amount
of phenol from extract and raffinate streams. The feed is pumped
from the absorber to the centrifugal extractor. The raffinate
stream is heated to about 290°C (550°F) and is flashed in the
raffinate furnace. Phenol vapor from this section is condensed
and stored. The raffinate oil flows down in a bottom section of
a raffinate tower in which it is steam stripped to remove sol-
vent. The treated oil is withdrawn from the bottom and stored.
Steam and solvent vapors flow from the stripping section to
vacuum equipment.
The extract stream from the centrifugal extractor is heated
and flows to a drying tower, in which all the water is removed as
a phenol-water azeotrope. This vapor is condensed and enters the
phenol-water drum. Dry extract solution is pumped from the
bottom of the extract flash tower. Most of the phenol is vapor-
ized in the extract furnace. The remaining extract solution
flows from the extract flash tower to a extract stripper, in
which the last traces of solvent are removed for storage.
Furfural refining is used to extract undesirable components
from petroleum lubricating oil stocks in order to produce high-
quality oils. Furfural has a high solvent power for components
that are relatively unstable to oxygen, and for such undesirable
materials as resins and sulfur compounds. Figure 4.9-5 is a flow
diagram of a typical furfural extraction process.
The untreated oil and furfural solvent are contacted in a
continuous countercurrent extractor. Furfural enters the extrac-
tion tower at the top, and the oil enters at some intermediate
point in the tower. The refined oil mixture rises to the top and
the extract oil settles to the bottom. The temperature of the
furfural depends largely upon the miscibility of the furfural and
the oil being refined. A substantial temperature gradient is
maintained between the 120°C (250°F) at the top of the tower and
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-9
-------
OJ ^
\0>
oo rt
o h
o
H-"
(D
H-
g
1-1
B
o
(D
3
(1)
I C
Oh-"
O
c
<\>
o
a.
d
o
rt
H
K
CD
PHENOL
STORAGE
CENTRIFUGAL
EXTRACTOR
RAFFINATE
FURNACE
r r~~i H
START •
CHARGE
STOCK
PHENOL-
WATER
DRUM
4VENT
n
ABSORBER
TOWER
EXTRACT OIL
RAFFINATE
OIL
Figure 4.9-4. Flow diagram of phenol extraction process.
rt
H-
-------
CO hb
\(D
oo ri-
Ohj
o
M
fD
PC
Mi
H-
3
(D
o
Hj
o
0)
n>
LEAN FURFURAL
0)
I-1
o
CD
(U
o
ft
CD
OJ
ft
H-
OIL FEED
COUNTERCURRENT
EXTRACTOR
RAFFINATE VACUUM
AND FLASH TOWER
RAFFINATE
STRIPPER
««-• STEAM
FURFURAL
AND
WATER
CBM FRACTIONATOR
LEAN FURFURAL
FURFURAL
EXTRACTOR
AND
ACCUMULATOR
EXTRACT VACUUM
FLASH TOWER
EXTRACT HP
FLASH TOWER
I
EXTRACT
LP
FLASH
TOWER
EXTRACT
STRIPPER
REFINED OIL
EXTRACT <1
Figure 4.9-5. Flow diagram of furfural refining process.
-------
the 60°C (140°F) at the bottom of the tower by indirect, external
water coolers. Extraction generally is accomplished by passing
the furfural in dispersed phase downward over Raschig ring nests
through the prevailing oil phase. Other types of extraction
equipment (towers containing rotating discs or stationary baf-
fles; centrifugal extractors) are also used.
Both the refined oil and the extract are heated in furnaces,
fractionated, and finally stripped for the removal of furfural.
Most of the furfural, nearly pure, is distilled from the extract
solution; the rest is associated with large amounts of water from
the stripping stream. When the steam-furfural mixture is conden-
sed, two immiscible solutions are formed, one rich in furfural
and the other rich in water. The wet furfural from all sources
is collected, condensed, and delivered to the accumulator. The
furfural-rich solution from the accumulator is distilled for
removal of water, and the pure furfural is pumped back to the
countercurrent extractor to complete the process loop. Similar-
ly, the water-rich solution is fractionated for the recovery of
furfural in the form of a constant boiling mixture (CBM), which
is returned to the accumulator.
The operating conditions and the yields of raffinate (re-
fined oil) depend upon the nature of the charge stock and the
degree of refining desired.
4.9.2 Emission Sources
Information about emissions will be given only for the major
processes of electrostatic desalting, the Merox process, and
furfural refining.
In electrostatic desalting, the major emission source is a
water effluent stream (Figure 4.9-1, point 1) containing dis-
solved chemicals mainly composed of chlorides, sulfates, and
bicarbonates. Small amounts of oil and sulfides are also found.
In the Merox process, the two emission sources are the
excess air stream leaving the separator (Figure 4.9-3, point 1),
which may contain disulfides, and the oil-disulfide product
stream leaving the separator (Figure 4.9-3, point 2), which can
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-12
-------
be a source of S02 emission if the oil-disulfide product is
incinerated.
In furfural refining, the extract stream (Figure 4.9-5,
point 1) is relatively rich in naphthenic, aromatic, and unsatu-
rated hydrocarbons; it also contains large amounts of sulfur. If
extracts are burned in process heaters or boilers, a large volume
of S02 will be emitted. The water effluent stream (Figure 4.9-5,
point 2) leaving the CBM extractor can contain oil and furfural
solution.
Atmospheric emissions are negligible, because the actual
vapor pressure of the hydrocarbons in the lube oil process is
very low.
4.9.3 Emission Controls
The water effluent stream leaving the electrostatic desalt-
ing unit is collected and sent to wastewater treatment. Impuri-
ties such as oil are removed by the primary treatment facility
(API separator), and dissolved chemicals are removed by the
secondary treatment facility (settling chambers and clarifiers).
The excess air stream from the Merox process, which may
contain disulfide, is sent to an incinerator. The oil-disulfide
product stream can also be burned in process heaters or incinera-
tor. If there is a large volume of oil-disulfide product, how-
ever, the S02 emissions from the incinerator may require control.
The extract stream from furfural refining is usually crack-
ed; it makes an excellent feed material for hydrocracking. If a
refinery does not have a cracking plant, the extract portion of
the oil can be burned in process heaters or boilers. It may also
be used for certain services that are not too exacting, such as
the lubrication of slow-moving, heavy machine parts.
4.9.4 Instrumentation
In electrostatic desalting, the temperature of the process
stream entering the settler varies from 65° to 180°C (150° to
350°F) depending on the type of the crude. The temperature of
this process stream must be controlled, because heat reduces the
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-13
-------
viscosity of the oil, giving less resistance to separation of
salt solution. The surface tension of the oil is also lowered by
heat, allowing water particles to coagulate.
In the Merox process, the flows of sour gasoline feed and of
the regenerated Merox solution entering the mercaptan extractor
are recorded and controlled. The flow of recycled Merox solution
entering the Merox sweetener is also recorded and controlled.
In furfural refining, the temperature of oil feed entering
the extractor is maintained at approximately 90°C (200°F) by
heating it in the charge oil heater. The temperature of regen-
erated furfural solution entering the extractor is maintained at
105°C (225°F) by the furfural cooler. The furfural countercur-
rent extraction is carried out at atmospheric pressure.
The flows of charge oil and regenerated furfural solution
are recorded and controlled.
4.9.5 Startup/Shutdown/Maifunctions
Shutdowns of the desalter unit are infrequent, because
little maintenance is required. The unit can usually be bypassed
and drained during a malfunction.
Shutdowns of the Merox unit are also infrequent. The cata-
lyst is regenerated once every 2 to 3 years. During a malfunc-
tion, the sour gasoline is stored until the unit is back in
operation.
4.9.6 References
1. Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill
Book Company, New York, 1958. pp. 347-366.
2. Refining Process Handbook. Hydrocarbon Processing. Septem-
ber 1978. pp. 178, 188, 191, 196, and 212.
Petroleum Refinery Enforcement Manual Crude and Product Treating
3/80 4.9-14
-------
HYDROTREATING
-------
4.10 HYDROTREATING
Hydrotreating (or hydrodesulfurization) is an extremely
versatile process that can be applied to straight-run products,
cracked products, feedstocks to catalytic reforming and catalytic
cracking, and lubricating oils. It has two purposes: the treat-
ment of petroleum fractions to remove such impurities as sulfur,
nitrogen, and metal compounds, thus preventing downstream corro-
sion and catalyst poisoning; and the treatment of products to
improve color and odor. Hydrotreating is the most common process
for pretreating catalyst reformer and catalyst cracker feedstocks
to remove sulfur and nitrogen, which can poison the catalyst.
This pretreatment prolongs catalyst life and the time between
regeneration cycles in the reformer and the cracker. Hydrotreat-
ing is also used to sweeten and improve the color and stability
of kerosene, jet fuels, and lubricating oils.
The wide range of hydrotreating processes that are available
reflects these many applications. Among the processes are Auto-
fining, Go-fining, Gulfining, Hydrofining, lube oil hydrotreat-
ing, Ultrafining, and Unionfining. Gulfining and Hydrofining
processes are discussed in detail in the following section.
4.10.1 Process Description
Gulfining
Gulfining is a desulfurization process, licensed by Gulf
Research and Development Company, that is capable of handling
straight distillate or cracked stocks. Kerosene, light gas oils,
light catalytic cycle oils, and stocks with similar boiling
ranges are normally desulfurized on units designed for general
light gas oil processing. Stocks with higher boiling ranges
(heavy gas oils, full-range vacuum gas oils) require more severe
conditions.
A simplified flow diagram of the Gulfining process is shown
in Figure 4.10-1. The gas oil feed is mixed with makeup and
Petroleum Refinery Enforcement Manual Hydrotreating
3/80 4.10-1
-------
00 ft
(D
Hi
H-
8
M
0
o
(D
I
Mg
0)
HYDROGEN
MAKEUP
RECYCLE HYDROGEN
FRESH
FEED *~
FEEDV
PREHEATER
REACTOR
n
HIGH-PRESSURE
SEPARATOR
SCRUBBER
ACID GASES
TO AMINE
TREATING UNIT
ACCUMULATOR
n
WATER
SCRUBBER
LOW-PRESSURE
SEPARATOR
STRIPPER
STEAM
DESULFURIZED
OIL
o
rt
n
(D
ft)
Figure 4.10-1. Flow diagram of Gulfining unit.
-------
recycled hydrogen, and is heated before flowing into the fixed-
bed reactor containing proprietary catalyst. Sulfur and nitrogen
compounds are converted in this reactor to hydrogen sulfide (H2S)
and ammonia (NEU). The reaction product is cooled and sent to a
high-pressure separator (flash drum), where the hydrogen-rich
stream is flashed from the reactor product and recycled. Oil
from the bottom of the high-pressure separator is fed to the
low-pressure separator (flash drum), where H2S, NHq/ and light
ends are recovered. The oil product from the low-pressure separ-
ator is fed to the steam stripper tower and stabilized by removal
of light ends.
Hydrofining
Hydrofining is a desulfurization process licensed by Exxon
Research and Engineering Company. The catalytic cracker or coker
naphthas can be partially hydrotreated to form stable desulfur-
ized fuel, or they can be completely hydrotreated to remove
sulfur, nitrogen, and saturate olefins to yield reformer feed-
stock or petrochemical-grade naphtha.
A simplified flow diagram of Hydrofining is shown in Fig-
ure 4.10-2. The gaseous-phase naphthas are mixed with hydrogen-
rich gas and preheated to reaction temperature before entering
the fixed-bed reactor. In the reactor, naphthas are contacted in
the presence of hydrogen with a metallic oxide catalyst. The
sulfur and nitrogen compounds break down to form H2S and NH3.
Some cracking of naphthas into lighter fractions will occur as a
side reaction.
The hot effluent leaving the reactor is cooled before enter-
ing the high-pressure separator, where hydrogen is removed and
recycled to the feed stream. The liquid from the separator is
preheated before it enters the stripper. In the stripper, steam
is injected to remove the acid gases from the product.
The overhead stream, which consists of acid gases and steam,
flows to a condenser and accumulator; the steam is returned to
Petroleum Refinery Enforcement Manual Hydrotreating
3/80 4.10-3
-------
OJ ^
\fD
00 ft
o H
O
50
(D
H,
S" RECYCLE HYDROGEN
fl> • '
I-** rrrn A ^ ' • '^1 1 ^
Q1 1 LLU • *] V V ^
o FEED I
2 PREHEATER f*\
(D HYDROGEN-
i-v 2. DTPU PAC "^ \ /
rf^ rt Kith taAo \/
MS X
0 0» /\
{L g REACTOR ^ >
p)
Y
Lrt-
x^
GAS
I L
SEPARATOR /^ ACID GASES T0 <2
btKAKAlUK /^ >. AMINE TREATING UNIT V
1 >^ I
(| D J^ C ) ACCUMULATOR
1 ^^ M— . -±S
1 ^^\,
AN ^ *• UATFR <2 >
"Tp STRIPPER
. _rf CTCAIul
_ -*• -* STEAM
bIKIrrtK IJ
PREHEATER [
^
fcj i_- >> DDnnurT
*\7^ *• r KUUUL 1
Figure 4.10-2. Flow diagram of Hydro-fining unit.
o
rt
H
(D
(u
rt
H-
-------
the stripper column as a reflux. The acid gas stream leaving the
overhead accumulator then proceeds to the amine treating unit.
The operating conditions of the Gulfining and Hydrofining
units can vary widely depending on the feed composition. The
reactor temperature varies between 290° and 425°C (550° and
800°F) and the reactor pressure varies between 1480 and 10,440
kPa (200 and 1500 psig). The higher temperatures and pressures
are used during severe operations, such as the treating of high-
boiling, highly contaminated, or unsaturated stocks. Hydrocrack-
ing occurs under these conditions, and hydrogen saturates the
cracked material. The oxides of cobalt, molybdenum, tungsten, or
nickel can be used as catalyst.
4.10.2 Emission Sources
The Gulfining and Hydrofining units have two possible emis-
sion sources. The gas stream leaving the overhead of the accumu-
lator (Figure 4.10-1, point 1; Figure 4.10-2, point 1) contains
such impurities as H2S and NHg. Water leaving the accumulator
(Figure 4.10-1, point 2; Figure 4.10-2, point 2) also contains
BUS and NH.,. During regeneration of the catalyst, a steam-air
mixture is used to burn carbon off the catalyst. This procedure
releases large quantities of carbon monoxide for a short period.
The catalyst is regenerated about twice a year. The high operat-
ing pressure also creates a potential for hydrocarbon leaks from
these units.
4.10.3 Emission Controls
The gas stream leaving the overhead accumulator of the
Gulfining and the Hydrofining processes is sent to an amine
treating unit to remove H-S and NH~. The treated gas, which
contains light ends and hydrogen, then proceeds to the refinery
fuel gas system. Water leaving the accumulator is treated in a
sour water stripper to remove H2S and NH.,.
Petroleum Refinery Enforcement Manual Hydrotreating
3/80 4.10-5
-------
4.10.4 Instrumentation
The principal variables in the Gulfining and Hydrofining
processes are reaction temperature and hydrogen partial pressure.
In general, sulfur removal increases as temperature and hydrogen
partial pressure are increased.
The temperature of feed entering the reactor is regulated
between 290° and 425°C (550° and 800°F). The desulfurization
level increases with higher temperature. Coking reactions become
much more prevalent, however, when operating temperatures ap-
proach 415°C (780°F). Coke is deposited on the catalyst, reduc-
ing catalyst activity and necessitating regeneration, which
results in emissions.
The temperature of feed also depends on the type of catalyst
used. High-activity catalysts are available to increase desul-
furization capabilities and to decrease feed temperature, thus
reducing fuel consumption. The reduced fuel consumption causes
fewer particulate and sulfur dioxide emissions from heaters.
Hydrogen partial pressure affects desulfurization levels in
relation to the boiling range of the feed. For a given feed,
there exists a point above which increased hydrogen partial
pressure has little effect on desulfurization. Below this point,
however, desulfurization drops off rapidly as hydrogen pressure
is reduced. For each feedstock, the optimum reactor pressure is
selected from the range of 1480 to 10,440 kPa (200 to 1500 psig),
based on the duty required (percent desulfurization) and related
operating variables.
4.10.5 Startup/Shutdown/Malfunctions
The Gulfining and Hydrofining units are shut down about
twice a year to regenerate the catalyst.
During a malfunction, feed to the Gulfining and Hydrofining
units is usually stored until the units are back in operation.
Otherwise, the sulfur and nitrogen in the untreated catalytic
reformer and catalytic cracker feedstocks would poison the cata-
lyst.
Petroleum Refinery Enforcement Manual Hydrotreating
3/80 4.10-6
-------
4.10.6 References
1. Metzger, K. J., et al. Gulfining: A Flexible Distillate
Desulfurization Process API Proceedings, 1971. pp. 72-82.
2. Nelson, W. L. Petroleum Refining Engineering. McGraw-Hill
Book Company, New York, 1958. pp. 332-335.
3. Refining Process Handbook. Hydrocarbon Processing, Septem-
ber 1978. pp. 139.
Petroleum Refinery Enforcement Manual Hydrotreating
3/80 4.10-7
-------
WAX & GREASE
-------
4.11 WAX AND GREASE PRODUCTION
Petroleum waxes boil in the temperature range of lubricating
oils and cannot be separated by distillation. Because waxes
crystallize at low temperatures, they are undesirable in motor
oils and must be removed. Waxes are classified according to
physical form. Paraffin waxes have large crystals and are ob-
tained from light lubricating oils. Microcrystalline waxes have
small crystals and are obtained from residual oil and tank bot-
toms .
Most greases are formed by adding thickeners to lubricating
oils. Common thickeners are calcium, sodium, aluminum, barium,
lithium, and lead soaps. Calcium, barium, and aluminum soaps
produce greases resistant to water; barium and lead soaps produce
greases that are used in heavy duty service.
4.11.1 Process Description
Solvent Dewaxing
In the solvent dewaxing process, the mixture of oil to be
dewaxed and solvent is chilled. Wax separates out and can then
be removed by filtration. Modern processes use special solvents,
such as methyl ethyl ketone (MEK) in mixture with benzene and/or
toluene, trichloroethylene, ethylene dichloride and benzene
(Bari-Sol), propane, and urea. The MEK process, which is the
most widely used, is discussed in detail in the following sec-
tion.
Each of the components in the mixture of MEK, benzene, and
toluene has a specific function. The MEK causes the wax to
solidify in a crystalline and easily filterable form; the benzene
and toluene increase the capacity of the solvent for dissolving
oil. A typical MEK dewaxing process is shown in Figure 4.111.
The mixture of waxy oil feed and solvent is chilled to
crystallize the wax. The chilling is accomplished in two stages
in heat exchangers: first, by exchange with cold products;
second, by the use of a refrigerant such as ammonia (NH~). The
Petroleum Refinery Enforcement Manual Wax and Grease Production
3/80 4.11-1
-------
00 ft
O H
O
C?
Hi
H-
3
CD
H
B
S
Hi
O
n
o
CD
(D
N)
0)
FLUE
GAS <
PURGE
KETONE
FEED*
ROTARY
VACUUM
FILTER
RECEIVER
4 KETONE
I . n
O
H
(D
(u
en
n>
Figure 4.11-1. Typical dewaxing process using methyl ethyl ketone solvent.
O
g-
O
ft
H-
O
-------
chilled feed is then filtered continuously on rotary vacuum
filters to separate the crystallized wax from the oil-solvent
solution. A blowback of flue gas to the filters aids in drying
and removing the wax cake. While the cake is still on the fil-
ter, it is washed with solvent to remove the retained oil. The
wax cake, which contains water and also some solvent, is melted
and charged to a settler where the wax and water are separated.
The melted wax is sent to a flash drum and steam stripper to
recover the solvent, which is recycled.
The oil-solvent solution is collected in a receiver and
heated in exchangers. It is then pumped to a two-stage flash
drum and steam stripper for recovery of solvent for recycle.
The dewaxing temperature is equal to a few degrees below the
desired pour point. Low pressure exists throughout the process.
2
The solvent/oil ratio ranges between 1:1 and 4:1.
Grease Manufacturing
A typical grease manufacturing process is shown in Fig-
ure 4.112. The first step is the charging of oil feed to the
contactor. Soap slurry is then added, and saponification is
conducted in the contactor as the temperature increases to a
preset maximum of 65° to 73°C (149° to 163°F). The saponifica-
tion reaction takes 30 to 45 minutes. Excess water is removed
through a vacuum line, if necessary. The rest of the oil is then
charged to the contactor to complete the manufacture of the
grease. After completion, final portions of finishing oil are
added to lower the temperature of the grease and thereby increase
its viscosity to a given specification.
Heavier greases are normally finished in the scraper kettle
because of their high viscosity at lower finishing temperatures.
The finished grease from either the contactor or the 'scraper
kettle is packaged directly or further processed in a grease mill
or polisher, depending on the specification of the final pro-
duct.3
Petroleum Refinery Enforcement Manual Wax and Grease Production
3/80 4.11-3
-------
oo rt
o H
O
(D
H,
H-
W
o
(D
I
(U
(U
K"
(U
O
M
(D
«u
CO
(D
SOAP
SLURRY
OIL
FEED
WEIGH
TANKS
Y Y
CONTACTOR
SCRAPER
KETTLE
MILL
GREASE
POLISHER
PACKAGING
O
ft
H-
O
Figure 4.11-2. Typical grease manufacturing process.
-------
4.11.2 Emission Sources
Dewaxing processes use special solvents, such as benzene,
toluene, MEK, ethylene dichloride, trichloroethylene, and pro-
pane. These solvents are recovered and reused in the process.
Their volatility, however, can cause some solvent loss through
leaks in fittings, valves, and pumps. Small amounts of solvent
may also be entrained in products and process residues.
No major emission sources are present in grease manufac-
turing. Fugitive emissions through leaks in fittings, valves,
and pumps are negligible because the actual vapor pressure of the
hydrocarbons in the lubricating oils is very low.
4.11.3 Emission Controls
Solvent recovery is a closed system that requires no special
control measures. Fugitive emissions through leaks in fittings,
valves, and pumps can be controlled by good engineering and
manufacturing practices. No emission controls are used for the
small amount of solvent that may be entrained in products and
process residues.
4.11.4 Instrumentation
The ratio of solvent to oil feed, which is very important
for proper control of a dewaxing unit, ranges from 1:1 to 4:1
depending on the nature and viscosity of the oil feed. The ratio
is maintained by a ratio flow controller. The temperature of a
dewaxing process is regulated to a few degrees below the desired
pour point of the dewaxed oil.
In grease manufacturing, accurate measurements are made of
the oil feed and soap slurry charged to the contactor. Time
cycles of 30 to 45 minutes are required for saponification. The
manufacture of calcium grease typically takes 11/2 to 2 hours;
the manufacture of soda-based grease takes 2 to 3 hours. \
Petroleum Refinery Enforcement Manual Wax and Grease Production
3/80 4.11-5
-------
4.11.5 Startup/Shutdown/Malfunctions
Because startup, shutdown, and malfunctions do not generate
significant emissions, the inspector need not concentrate on
monitoring emissions during those periods.
4.11.6 References
1. Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill
Book Company, New York, 1958. pp. 66-69.
2. Kirk-Othmer Encyclopedia of Chemical Technology. Vol 15,
John Wiley & Sons, New York, 1968. pp. 92110.
3. Refinery Process Handbook. Hydrocarbon Processing, Septem-
ber 1978. pp. 224.
Petroleum Refinery Enforcement Manual Wax and Grease Production
3/80 4.11-6
-------
ASPHALT
-------
4.12 ASPHALT PRODUCTION1
The residue from vacuum distillation may be referred to as
asphalt, residuum, or flux. This bottom product is a mixture of
resins, asphaltenes, and oils. Resins are highly cross-linked
polymers. When heated, these polymers form additional cross-
linkages and thus become more rigid. Asphaltenes are high-mole-
cular-weight agglomerates that are insoluble in alkanes from
propane to heptane. Asphaltene molecules contain about five
aromatic rings arranged in a stack, plus nitrogen, oxygen, sul-
fur, and some free radical sites. Oils are less complex aromatic
compounds. In addition, trace metals such as vanadium and nickel
that are present in crude oil tend to become concentrated in
asphalt and other heavy oils. Asphalt may also be obtained from
solvent deasphalting processes.
The asphalt used in road paving is usually the bottoms from
vacuum or atmospheric distillation; they need no further process-
ing.
The asphalt used in shingles and composition roofing must be
harder than that used in paving. Air blowing is used to lower
the penetration and to raise the softening point of the asphalt.
The improved properties of airblown asphalt—increased hardness,
higher melting point, and greater resistance to weathering—
result from the oxidation reactions which occur during the blow-
ing process. When a very high melting point and extreme hardness
are desired, a catalyst (such as ferric chloride or phosphorus
pentoxide) is added to the asphalt before it is blown.
4.12.1 Process Description
Figure 4.12-1 is a diagram of an asphalt air-blowing pro-
cess. The feed from the vacuum distillation unit may be stored
or pumped directly to the asphalt plant. Asphalt coming directly
from the distillation tower is heated and may require cooling
before it enters the airblowing reactor vessel. Asphalt that has
been in storage must be heated before it enters the reactor.
Petroleum Refinery Enforcement Manual Asphalt Production
3/80 4.12-1
-------
oo
o
o
CD
50
Hi
H-
CD
M
I
O
§
D)
•d
cr
(U
KNOCKOUT
POT
COMPRESSED
AIR
RESIDUUM
FEED •
HEATER
(MAY BE
BYPASSED)
FUME INCINERATOR
•« • FUEL GAS
REACTOR
AIRBLOWN ASPHALT
o
rt
H-
O
Figure 4.12-1. Block flow diagram of asphalt air-blowing unit.
-------
When the feed has reached the proper temperature, it enters and
partially fills the vertical reactor.
Asphalt blowing is a batch process. After the reactor is
sufficiently filled, compressed air that has been passed through
a knockout pot is injected into the asphalt through a sparger at
the base of the reactor. The knockout pot removes water or other
liquids from the compressed air. The oxygen in the air reacts
with the asphalt, resulting in oxidation, polymerization, and
increased cross-linkage of the asphalt molecules. Blowing may
continue for 1 to 24 hours. Because the reactions are exother-
mic, the blowing process supplies its own heat. Temperature is
regulated by the airflow rate and by water cooling. The product
(airblown asphalt) is removed from the bottom of the reactor,
cooled, and loaded for shipping or sent to storage. A fume
incinerator is associated with the process to burn the hydrocar-
bon gases generated in the reactor.
4.12.2 Emission Sources
The gaseous stream from the reactor contains hydrocarbon
vapor and an aerosol of oil droplets. This stream used to be a
major source of emissions at refineries. Fume incinerators now
burn these hydrocarbons, but the incinerator itself is a poten-
tial source of hydrocarbon, sulfur oxide, and nitrogen oxide
emissions (Figure 4.12-1, point 1).
Hydrocarbon leaks from process unit equipment are minimal at
an asphalt plant because the feed and product have extremely low
volatility. The study on equipment leaks by the California Air
Resources Board does not report leaks from asphalt plants. Leaks
due to corrosion of rupture disks on the reactor and storage
tanks are possible sources of emissions.
4.12.3 Emission Controls
Proper operation of the fume (vent gas) incinerator should
minimize atmospheric emissions from the asphalt plant. Proper
maintenance of all equipment is important for this purpose.
Petroleum Refinery Enforcement Manual Asphalt Production
3/80 4.12-3
-------
4.12.4 Ins trumentati on
The air-blowing reactor is generally maintained at a temper-
ature of 205° to 315°C (400° to 600°F). The reactor temperature
and the rate of airflow into the reactor are continuously moni-
tored and should be noted by the inspector.
In a batch operation, the flow rate of asphalt into the
reactor is not significant in itself; however, the flow rate
multiplied by the time required to "load" (partially fill) the
reactor is equal to the operating capacity of the reactor. The
flow rate and the temperature of the asphalt entering the reactor
should be noted. The fume incinerator temperature should also be
noted. If the incinerator stack is monitored with an opacity
meter, the inspector should record that reading.
4.12.5 Startup/Shutdown/Malfunctions
Because asphalt air-blowing is a batch process, startups and
shutdowns are routine. No significant emissions occur during
these periods.
Construction products like asphalt are in seasonal demand;
it is common for refineries to shut down their asphalt plants
during the off-season. A turnaround for routine maintenance of a
process unit should pose no emission problems if vapors are
properly disposed.
Malfunction of the incinerator is the greatest potential
emission problem in an asphalt plant. This and other malfunc-
tions are infrequent, however, and can be corrected in a short
period of time.
4.12.6 Reference
1. Refining Process Handbook. Hydrocarbon Processing, Septem-
ber 1978. pp. 220.
Petroleum Refinery Enforcement Manual Asphalt Production
3/80 4.12-4
-------
COKING
-------
4.13 COKING1'4
Coking is a thermal cracking process, conducted under strin-
gent conditions, which converts low-value residual fuel oil to
higher value gas oil plus a byproduct of petroleum coke. Coke
with low sulfur and metal contents has recently become a valuable
raw material in the manufacture of electrodes and aerospace
components. Power plants also use low-sulfur coke for fuel
because of its heating value of 32,600 to 37,200 kJ/kg (14,000 to
16,000 Btu/lb.)
4.13.1 Process Description
Typical feeds to the coking process include reduced crudes,
vacuum distillation residues, tars, and catalytic cycle oil.
Products include gas, naphtha, gasoline, heavy and light gas oil,
as well as coke. There are two types of coking processes, delay-
ed and fluid; delayed coking is the more widely used. An addi-
tional coke processing step is coke calcining. Descriptions of
these processes follow.
Delayed Coking Process
In the delayed coking process, the feed enters the coker
tower (fractionator), where gas oil, gasoline, and lighter frac-
tions are flashed off and recovered. Figure 4.13-1 is a typical
flow diagram of a delayed coking process. The fractionator
bottoms are combined with a recycle stream and are heated to a
reaction temperature of 480° to 580°C (900° to 1080°F) in the
coker heater. Heater velocities are controlled by steam injec-
tion. Mild cracking and some vaporization occur in the heater.
The vapor-liquid mixture from the heater then enters the coke
drum, where the primary coking reaction takes place. The coke
drum provides the proper residence time, pressure, and tempera-
ture for coking. In the coke drum, the vapor portion of the feed
undergoes further cracking as it passes through the drum, and the
liquid portion undergoes successive cracking and polymerization
until it is converted to vapor and coke.
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-1
-------
CO hj
X0>
oo ft
on
o
n>
HI
H-
3
CD
M
O
0)
3-
rt
i^
• S
(-J si)
CO 0
I C
NJ pJ
TO COKER QUENCH
COKER GASOLINE <3
COKE DRUM
SUMP TANK
LIGHT
GAS OIL
HEAVY
*" GAS OIL
n
o
Figure 4.13-1. Flow diagram of delayed coking unit.
-------
Overhead vapors from the coke drum enter the coker tower and
are separated into gas, naphtha, and light and heavy gas oils,
which are withdrawn as products; a recycle portion flows to the
bottom of the tower, where it is combined with fresh feed for
another pass through the heater. The solid coke remains in the
coking drum. A coking unit has at least two coking drums. One
or more are in operation while the others are down for removal of
coke.
In removal of coke from the drum, steam is first injected
into the drum to remove the hydrocarbon vapors, which are cooled
to form a steam-hydrocarbon mixture that is separated into three
parts:
1. Water with coke particles that is added to the coke
removal stream.
2. Hydrocarbon liquid that is added to the slop oil sy-
stem.
3. Noncondensables that either go to the flare system or
to a heater to be used as fuel. This stream is primar-
ily fuel gas and usually contains some sulfur com-
pounds .
After the drum is filled with cooling water and then drain-
ed, the coke is cut out (broken free of the drum) by use of a
high-pressure (13,890 kPa; 2000 psig) water jet. The coke parti-
cles are separated from the water by the use of screens. Fine
particles remaining in the water are removed in a thickener, and
the water is recycled to the coke cutting process.
Fluid Coking Process
In the fluid coking process, the coking reaction is carried
out on a fluidized bed of hot coke particles. In the fluidized
bed, gas is circulated upward at a controlled velocity through a
bed of fairly uniform particles. The bed looks and behaves as if
it were liquid, in that it flows like a liquid and can be pumped.
An essential characteristic is a narrow range of particle sizes.
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-3
-------
Large particles sink and could clog the gas vents. Fine parti-
cles blown out of the bed are potential particulate emissions. A
fluidized bed reactor allows for very rapid and efficient heat
transfer.
Figure 4.13-2 is a flow diagram of a typical fluid coking
unit. The fresh feed, usually vacuum residuum, is dispersed into
the fluidized coke bed reactor, operating typically between 525°
and 590°C (975° and 1100°F). A portion of the feedstock is ther-
mally converted to vapors including gasoline-boiling-range frac-
tions, which leave the reactor as overhead vapors. The remainder
of the charge stock is converted to coke, which is deposited on
the fluidized coke particles already in the reaction zone. Heat
balance is maintained by circulating coke between the reactor and
the burner, where a portion of the coke is burned with blower air
to supply preheat and heat of reaction. A portion of the coke is
withdrawn as a product through an elutriator by countercurrent
stripping, from which fines are returned to the burner.
The gas and distillate products leave the reactor through
cyclones and enter a tower located above the reactor. In this
tower, called a scrubber because it removes any carryover of fine
particles, the vapors are partially condensed. The high-boiling
distillate is recycled to the reactor and coked. The remaining
vapors are fractionated into naphtha and light and heavy gas oil
products.
Coke Calcining
To increase the value of coke more petroleum refiners are
considering coke calcining. Coke is calcined to convert "green
coke" to the more valuable "needle coke" and to reduce the sulfur
content. A process flow diagram is shown in Figure 4.13-3. The
green coke produced from a coking unit arrives by belt conveyor
to one of two raw coke feeding bins. Two belt weigh-feeders lead
to the slightly inclined, cylindrical, rotary kiln calciner. The
calcination reaction is carried out between 1315° and 1480°C
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-4
-------
W htf
\tt>
oo r+
o n
o
M
fD
-------
OJ
03 rt
o M
O
M
(D
fD
H»
H-
w
0
Hi
o
H
O
0)
(D
BELT CONVFTOR TO
CALCINED COKE STORAGE
Figure 4.13-3. Flow diagram of coke calcination process.'
O
o
-------
(2400° and 2700°F). The kiln is refractory-lined and has speci-
fic internal structures to control coke movement and residence
time. The coke travels countercurrently to the combustion gases
coming from a burner fixed to the firing hood at the opposite end
of the kiln. The calcined coke leaving the kiln goes through a
transfer chute to a water spray cooler. The coke is then dis-
charged through the cooler discharge hood and conveyed by belt to
the calcined coke storage.
Gases coming from the cooler discharge end hood and convey-
ors are routed through a dust collecting chamber and then to the
cooler stack by a fan. The combustion gases from the upper end
of the kiln are treated in a dust chamber and a dropout chamber
to recover coke particles. The recovered coke is recycled to the
kiln by means of a collecting screw and an elevator. The par-
tially cleaned flue gas passes through an incinerator, where the
last coke particles are burned before the gas leaves the main
stack.
4.13.2 Emission Sources
The feedstocks in coking operations are richer in sulfur
than is the crude oil being processed. Consequently, streams
from coking units are potential sources of hydrogen sulfide (H2S)
and organic sulfur compounds. Finely divided coke is present in
the unit and some of it is further reduced in size by partial
combustion and friction. Because coke has a high ash content, it
is a potential source of particulate emissions both as unburned
material and as fly ash.
A. Delayed Coking Reactors
Potential points of sulfide emissions, all shown in
Figure 4.13-1, include:
1. Steam from the steamout operation (point 1)
2. Accumulator fuel gas (point 2)
3. Coker gasoline (point 3)
4. Water drawn from the overhead accumulator
(point 4)
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-7
-------
5. Water used in coke cutting (point 5)
6. The fired heater (point 6)
Potential points of particulate emissions include:
1. The fired heater (point 6)
2. Coking units. (These units, which are usually
covered with coke dust, must be cleaned and washed
often to prevent fugitive coke-dust emissions.)
B. Fluid Coking Reactors
Potential points of sulfide emissions, shown in
Figure 4.13-2, include:
1. Accumulator fuel gas (point 1)
2. Naphtha (point 2)
3. Light gas oil (point 3)
4. Heavy gas oil (point 4)
5. Reactor scrubber (point 5)
6. Burner or CO boiler (point 6)
Potential sources of particulates, shown in Figure
4.13-2, include:
1. Reactor scrubbers (point 5)
2. Burner or CO boiler (point 6)
3. Product coke recovery (point 7)
C. Coke Calcination
Potential sources of sulfides, shown in Figure 4.13-3,
include:
1. Gases from stacks (points 1 and 2)
2. Gases from the kiln (points 3 and 4)
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-8
-------
Potential sources of particulates, shown in Figure
4.13-3, include:
1. Conveyor belts (points 5 and 6)
2. Stacks and the kiln (points 1, 2, 3, and 4)
4.13.3 Emission Controls
In the delayed coke process, large quantities of steam and
hydrocarbons may be released to the atmosphere when the coke drum
is opened. More steam may be produced by vaporization of the
cutting water and by release of pockets of trapped steam/hydro-
carbon vapors from cutting operations. These hydrocarbon emis-
sions can be minimized by venting the quenching stream to a vapor
recovery or blowdown system. Flaring of orgariics containing
sulfur in a blowdown system may produce SO emissions. When the
X
drum has cooled to 100°C (212°F), the steam purge can be replaced
by a water flood. Allowing further cooling to approximately
ambient temperature will minimize vaporization and escape of
steam and hydrocarbons when the drum is opened.
In the fluid coking process, the gas from the burner (Figure
4.13-2, point 6) contains carbon monoxide and sulfur-bearing
hydrocarbons. Since this waste gas has value as a fuel, a CO
boiler can be used to generate steam for use on the unit and to
control the emissions.
In coke calcining, multicyclones and a CO incinerator are
the most common emission controls.
4.13.4 Instrumentation
Temperatures are measured in the coking reactors, the coke
drums, the distillation column, and the coking towers. Process
steam temperatures and/or pressures are also measured. Rates of
feed to and discharges from the process are measured and con-
trolled.
A gas flow rate above the recommended operating range would
lead to particulate emissions that could overwhelm control mea-
sures. Temperature fluctuations may affect coke conversion and
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-9
-------
yields as well as the amount of material being recycled. The
resultant emissions would be significant only if they increased
to a point that the control measures were not designed to handle.
4.13.5 Startup/Shutdown/Malfunctions
Scheduled shutdowns for maintenance are requisite in the
delayed coking process. Of particular concern are the coking
drums, which are subject to rapid heating and cooling cycles that
make them susceptible to cracking, warping of the shell, and
lining failure. Welded areas are particularly vulnerable. Ther-
mal stress is the primary cause of failure, rather than corrosion
from the sulfur content of the feed. A drum failure can cause
uncontrolled and significant releases of particulates and sulfur
compounds.
When the coke drums are overfilled by charging at rates
higher than the design rate, coke foam could go overhead to the
fractionator and necessitate a shutdown. During a shutdown,
hydrocarbon and sulfur compounds are emitted to the atmosphere.
The coke drum is cooled and decoked. The fractionator is also
shut down, cooled, and restarted.
Successful operation of fluid coking units depends on con-
tinuous circulation of coke between the reactor and burner. The
aeration taps on the transfer lines between the reactor and the
burner must operate properly. Loss of coke in the reactor shuts
down the unit. It is important also that the feed be properly
injected into the reactor. When the charge rate is too high,
fluidization is poor and the reactor must be shut down. A unit
shutdown can cause emissions of particulates, hydrocarbon, and
carbon monoxide. A time frame relative to these malfunctions is
not available. Their frequency depends on the type of feed and
on general operating practices. The startup and shutdown times
depend on the severity of the malfunction. Generally, emergency
downtime for this unit averages 11 days between turnarounds.
These downdays represent several shutdowns of varying lengths.
There are minimum downtimes. About 1 day is needed for shutdown
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-10
-------
of the unit, and 1.5 to 2 days for startup; thus the minimum
downtime is 2.5 to 3 days.
The other shutdown and startup operations would follow the
usual sequence of heating or cooling, venting to the refinery
flare, and flushing with inert gas and air. The 24 to 48 hour
cycle for coking drums is part of the process rather than a
startup/shutdown cycle.
The coking units are shut down on the average of once every
8 months for general inspection and maintenance (turnaround).
This may vary within a range of 3 to 14 months. The downtime for
a scheduled shutdown averages 16 days.
4.13.6 References
1. Russ, R. J. Coke Quality and How To Make It. Hydrocarbon
Processing, September 1971. pp. 132-136.
2. Reis, T. To Coke, Desulfurize and Calcine. Hydrocarbon
Processing, April 1975. pp. 144-150.
3. Refining Report. Here Is What's New In Delayed Coking. The
Oil and Gas Journal, April 6, 1970. pp. 92-96.
4. Refining Process Handbook. Hydrocarbon Processing, Septem-
ber 1978. p. 103.
Petroleum Refinery Enforcement Manual Coking
3/80 4.13-11
-------
AMINE
THEATER
-------
4.14 AMINE TREATER1
The amine treater removes the acidic impurities, mainly
hydrogen sulfide (H2S) and carbon dioxide (C02), from refinery
gas streams. In some refineries, the amine treater is part of
the sulfur plant rather than a separate unit. The amine treater
is also known as a gas sweetening unit, an acid gas treating
unit, or an amine scrubber.
4.14.1 Process Description
The amine treater is a single absorption/regeneration cycle
circulating an aqueous amine solution. The most frequently used
amines are monoethanolamine (MEA), diethanolamine (DBA), diglyco-
lamine (DGA), and diisopropanolamine (DIPA). The main advantage
of DGA is its ability to remove carbonyl sulfide (COS) and mer-
captans, thus eliminating the need for downstream liquid treating
units. The DGA is more expensive, however, than most of the
commonly used amines. Figure 4.14-1 is a flow diagram of a
typical amine treater.
The feed gas stream containing the impurities (such as H2S
and C02) is contacted countercurrently with an amine solution
that enters at the top of the packed or tray tower (absorber).
The feed gas stream enters at the bottom of the tower. The
treated gas stream leaving the absorber may either be further
processed in lightend recovery processes or may be charged as a
raw material to other refinery or petrochemical processes.
The rich amine solution from the bottom of the absorber is
flashed at a reduced pressure to remove the entrained gases,
including part of the acid gas, and then heated in a rich/lean
amine exchanger. The heated, rich amine stream then flows to the
stripper tower where the amine is regenerated. In the stripper,
absorption reactions are reversed, with heat supplied by strip-
ping steam that is generated in the reboiler. The acid gases are
separated from the amine solution by steam. The overhead stream,
consisting of acid gases and steam, flows to a condenser and
accumulator; the steam is separated from the acid gas and
Petroleum Refinery Enforcement Manual Amine Treater
3/80 4.14-1
-------
UJ
X.
oo
o
.CD
50
fl>
l-h
H-
3
0)
M
3
Hi
O
I-!
O
CD
0)
3
ft
3
J1J
H-
3
CD
1-3
M
(D
£U
rt
0)
hi
TREATED GAS <2,
CONDENSER
ABSORBER
FEED GAS
SOLUTION
COOLER
AMINE
CHARGE
PUMP
BOOSTER
PUMP
RICH/
LEAN
AMINE
EX-
CHANGER
FLASH
GAS
FLASH TANK
^ ACID GAS
TO FLARE
OR SULFUR
PLANT
REFLUX ACCUMULATOR
STRIPPER
STEAM
STEAM
IREBOILER
SURGE TANK
Figure 4.14-1. Flow diagram of a typical amine treater.
-------
returned to the stripper column as a reflux. Condensation of
steam from the acid gas in the accumulator leaves a concentrated
acid gas.
The lean amine solution from the bottom of the reboiler is
exchanged with the rich amine solution and pumped back to the
absorber to complete the process loop.
The operating conditions for an absorber can vary widely.
The absorber pressure ranges from slightly above atmospheric to
6995 kPa (1000 psig). The temperature of the amine entering the
absorber ranges from 40° to 60°C (100° to 140°F). The stripper
operates at near atmospheric pressure and a bottom temperature of
approximately 115°C (240°F). The amine circulation rate depends
on the feed rate and the partial pressure of the acidic compon-
ents.
4.14.2 Emission Sources
There are three emission sources in the amine treater. The
major emission source is the acid gas stream (Figure 4.14-1,
point 1). The treated gas stream may contain H2S (Figure 4.141,
point 2). The flash gas stream also contains H2S and C02 (Figure
4.141, point 3).
Additional components emitted to the atmosphere from the
stack include nitrogen, sulfur dioxide (S02), water, and oxygen.
4.14.3 Emission Controls
The acid gases from the reflux accumulator are burned in a
flare, heater, or other incinerating device. In cases of high
sulfur concentrations, the acid gases may be processed for sulfur
recovery. The treated gas is either processed in a liquefied
petroleum gas plant or sent to a refinery fuel gas system. The
flash gas stream is sent to a flare.
4.14.4 Instrumentation
The sulfur content of the treated gas stream is monitored
frequently—or perhaps continuously—to determine whether the
amine unit is operating properly. When the H2S content of the
Petroleum Refinery Enforcement Manual Amine Treater
3/80 4.14-3
-------
treated gas exceeds the allowable limit, fresh amine is added to
the lean amine solution to remove excess H2S from the feed gas.
When the acid gas is disposed of by combustion in a flare,
heater, or incinerator, the H2S content of the acid gas stream
should be monitored continuously. When the acid gas is processed
for sulfur recovery, the H2S content of the acid gas stream is
usually not monitored.
Control of the amine circulation rate in the absorber is
essential for proper operation of the treater. The circulation
rate of the amine solution is determined by the acid gas content
of the feed gas, concentration of the amine solution, and the
type of amine to be used.
The ratio of feed gas to amine is maintained by the amine
flow controller.
The solution cooler maintains the temperature of the lean
amine stream entering the absorber at 40° to 60°C (100° to
140°F). The reboiler maintains the stripper temperature at
approximately 115°C (240°F).
4.14.5 Startup/Shutdown/Malfunctions
The amine treater needs little maintenance work when com-
pared with a catalytic reforming unit; shutdown of the unit is
thus less frequent. In large refineries, the amine treater is
usually part of a sulfur plant and is shut down with that plant
once every 2 to 3 years.
The concentration of amine is continuously maintained at a
required level by adding fresh amine into the system, and shut-
down is not required to change the amine solution.
When hydrocarbons are carried over with the amine solution
in the stripper, the unit is shut down to drain the hydrocarbons
from the stripper. During the malfunction of the amine treater,
the refinery gas stream is bypassed to a flare, reboiler, or
other incinerating device, thus emitting large volumes of S02-
Petroleum Refinery Enforcement Manual Amine Treater
3/80 4.14-4
-------
4.14.6 Reference
1. GPA Explores H9S Removal Methods. The Oil and Gas Journal,
July 17, 1978. pp. 6673.
Petroleum Refinery Enforcement Manual Amine Treater
3/80 4.14-5
-------
GAS
PROCESSING
-------
4.15 GAS PROCESSING1'2
The gas processing section of a refinery is identified by
the following names: vapor recovery unit (VRU), light-ends unit
(L ends), or simply, gas plant. The purpose of the gas plant is
to recover valuable products from the refinery fuel gas produced
at most refinery units.
The vapor recovery products include methane used as feed-
stocks for petrochemical plants, butanes for gasoline blending,
and liquefied petroleum gas (LPG). The LPG is propane or butane,
or mixtures of both. The product that is recovered depends on
market conditions. Generally, LPG is recovered. The remainder
of this section is primarily directed at discussing the LPG
recovery process.
4.15.1 Process Description
Figure 4.15-1 is a flow diagram of a typical vapor recovery
unit. The feed stream consists of refinery gas from the follow-
ing units or conversion processes: crude distillation, catalytic
reforming, catalytic cracking, steam cracking, thermal cracking,
coking, visbreaking, polymerization, and alkylation. After
processing in the gas plant, the LPG yields from these processes
usually vary within a relatively wide range, as shown in
Table 4.15-1.
TABLE 4.15-1. LIQUEFIED PETROLEUM GAS YIELDS FROM CONVERSION PROCESSES
Process
Catalytic reforming
Catalytic cracking
Steam cracking
Polymerization/alkylation
Thermal cracking
Coki ng/vi sbreaki ng
LPG yield,
percentage
by weight
5 to 10
15 to 20
23 to 30
10 to 15
10 to 20
5 to 10
Petroleum Refinery Enforcement Manual Gas Processing
3/80 4.15-1
-------
CO hd
\0>
00 rt
oh
o
M
(D
METHANE. ETHANE
(D
3
HI
O
H
O
fl>
3
(D
1-1 P)
in 3
to (u
O
CD
CO
O
O
(D
CO
cn
H-
REFINERY GAS
OBTAINED FROM:
CRUDE DISTILLATION
CATALYTIC REFORMING
STEAM CRACKING
POLYMERIZATION/
ALKYLATION
THERMAL CRACKING
COKING/VISBREAKING
FINISHED PRODUCT
LPG
REFINERY
FUEL GAS
DEPROPANIZER
•- WATER
LPG
DEISOBUTAN1ZER
WATER
HYDROGEN SULFIDE
METHYL AND ETHYL
MERCAPTANS
ORGANIC SULFIDES
DISULFIDES
BUTANES_^ ISOBUTANE
NORMAL1 BUTANE
Figure 4.15-1. Flow diagram of vapor recovery unit.
-------
The conversion processes that create the feed stream to the
vapor recovery unit are summarized below. For a more detailed
description, refer to Sections 2.3 and 2.4.
Catalytic reforming reacts virgin naphtha from the crude oil
fractionating tower. The aromatics (C&/C7) that are produced are
used for gasoline blend stocks or chemical intermediates; LPG is
a possible byproduct. Sulfur must be removed from the naphtha
stream before reforming to avoid contaminating the reforming
catalyst. The sulfur is removed by converting it to hydrogen
sulfide over a molybdate catalyst.
Catalytic cracking units, referred to" as cat crackers, use a
feedstock of heavy gas oil to produce gasoline and unsaturated
gases. High temperature and silica-aluminum catalyst are needed
for the cracker reaction. The unsaturated gases are intermedi-
ates that undergo further chemical reaction. An "integrated"
refinery has both crackers and reformers to reduce production of
middle distillates. The fuel gas from this operation is sent by
pipeline to the gas plant.
Noncatalytic cracking processes that yield the LPG byproduct
include steam and thermal cracking, visbreaking, delayed coking,
and fluid coking.
The recovered refinery gas feed stream is highly compressed
before being sent to a deethanizer (distillation column). Over-
head products—methanes and ethanes—pass through an accumulator,
which removes the water and produces refinery fuel gas. The fuel
gas stream contains methane, ethanes, and propanes. This stream
may be further processed to remove the methane, a valuable petro-
chemical feedstock. The bottoms are further distilled in a
depropanizer, which separates the liquefied petroleum gas and the
butanes. The butanes are then sent either to gasoline blending
or to a deisobutanizer for separation into isobutane and normal
butane, which is piped to the gasoline blending unit; the over-
head contains isobutane, which is alkylation feedstock.
The overhead stream from the depropanizer contains the
liquefied petroleum gas, which is treated by removing the sulfur
Petroleum Refinery Enforcement Manual Gas Processing
3/80 4.15-3
-------
to make the gas noncorrosive and nontoxic. Hydrogen sulfide,
mercaptans, and elemental sulfur are removed by washing with
caustic soda, the Girbotal or Merox extraction processes.
In the caustic soda method, sodium or potassium hydroxide
react with hydrogen sulfide and mercaptans. The reaction prod-
ucts are removed from the LPG. The reaction is comparable to an
extraction reaction. Caustic solutions range in concentration
from 5 to 20 percent. The Girbotal process utilizes a packed
tower in countercurrent flow to extract sulfur compounds. Mono-
ethanolamine (MEA) or diethanolamine (DBA) are the extracting
agents. The Merox unit (developed by the Universal Oil Company)
converts mercaptans to disulfides by reacting them in air and
alkali in the presence of a chelated iron catalyst.
Sulfides can also be removed from the LPG by molecular sieve
adsorption. Synthetic metal aluminosilicates are made into
molecular sieve adsorption pellets. The sieve adsorbs molecules
having critical diameters of 10 angstoms. Molecular sieve ad-
sorption is advantageous because the sieves also dry the LPG.
After the treating process, the LPG is sent to the drying
unit and percolated through an adsorption tower packed with
calcium chloride, alumina, silica gel, or molecular sieves.
Calcium chloride is the least expensive drying method, although
it does present a disposal problem. The LPG is passed through
two towers connected in series. When calcium chloride is used in
the towers, heavy brine forms in the first tower. When the brine
concentration reaches 25 percent calcium chloride the first tower
is drained and recharged with brine and the LPG flows are re-
versed; the first tower thus becomes the second tower. The brine
is usually drained once in every 8-hour shift.
The finished LPG product is graded according to the Reid
vapor pressure and to the temperature at which 90 percent of the
LPG is evaporated. Grading requirements (from the Natural Gaso-
line Association of America) are listed in Table 4.15-2.
Petroleum Refinery Enforcement Manual Gas Processing
3/80 4.15-4
-------
TABLE 4.15-2. GRADING REQUIREMENTS FOR LIQUEFIED PETROLEUM GAS
Reid vapor pressure 68.9 to 234.4 kPa
(10 to 34 psia)
Percentage evaporated at 60°C (140°F) 25 to 85
Percentage evaporated at 135°C (275°F) Not less than 90
End point Not higher than
190.5SC (375°F)
Corrosion Noncorrosive
Doctor test Negative; sweet
Color Not less than
plus 25
4.15.2 Emission Sources
Major emissions associated with LPG recovery and production
are discussed in detail in the sections dealing with distillation
(4.1), catalytic cracking (4.2), hydrocracking (4.4), and reform-
ing (4.5). Emissions of fugitive volatile organic compounds (VOC)
are sometimes a problem around the processing equipment because
LPG is a vapor at ambient temperature and atmospheric pressure.
Hydrogen sulfide and sulfur dioxide emissions are also possible
pollutants. These are discussed in the sulfur recovery section
of the manual (4.16).
4.15.3 Emission Controls
Most of the emissions from the crude distillation cracking,
sulfur removal or sweetening process, and the reforming LPG
stream are fugitive VOCs. These emissions can be controlled by
using an active inspection and maintenance (I&M) program for pipe
fittings, valves, and pumps. The I&M program would use a VOC
analyzer, appropriate record keeping, and a maintenance program
to stop leaks.
Petroleum Refinery Enforcement Manual Gas Processing
3/80 4.15-5
-------
4.15.4 Instrumentati on
Temperature and pressure are the two significant control
parameters that determine product yield. The temperature and
corresponding pressure must be kept low to reduce losses, because
LPG is a gas at ambient temperature.
The instrumentation must be checked regularly for correct
calibration and operation so that VOC emissions are kept at a
minimum. The sections on catalytic cracking (4.2) and hydro-
cracking (4.4) discuss instrumentation equipment that is also
applicable to LPG manufacturing.
4.15.5 Startup/Shutdown/Malfunctions
As discussed previously, LPG is a byproduct stream produced
during gasoline cracking; it is also separated from crude oil
during distillation. Startup, shutdown, and malfunctions of LPG
processing are dependent on the method of gasoline cracking and
crude distillation. Refer to the information in the sections on
distillation (4.1.5), catalytic cracking (4.2.5), visbreaking
(4.3.5), hydrocracking (4.4.5), and catalytic reforming (4.5.5).
4.15.6 References
1. Williams, A. F., and W. L. Lorn. Liquefied Petroleum Gases:
A Guide to Properties, Applications and Usage of Propane and
Butane. John Wiley & Sons, New York, 1977. p. 397.
2. Sittig, M. Petroleum Refining Industry: Energy Saving and
Environmental Control. Noyes Data Corporation, Park Ridge,
New Jersey, 1978. p. 110.
Petroleum Refinery Enforcement Manual Gas Processing
3/80 4.15-6
-------
SULFUR
PLANT
-------
4.16 SULFUR PLANT
The Glaus process is the most widely used method of recover-
ing sulfur from acid gases. The degree of sulfur recovery ob-
tainable by a Glaus plant is dependent on the number of catalytic
reactors and on the concentration of hydrogen sulfide (H2S) in
the feed. Glaus units are generally constructed with two, three,
or four catalytic reactors. The best available control techno-
logy (BACT) requires three catalytic reactors. In a refinery
Glaus unit, the H2S concentration in the acid gas is generally
above 70 percent. Table 4.16-1 shows typical recovery percent-
ages for various concentrations of H9S in the acid gas feed at
1
plants with two, three, and four reactors.
4.16.1 Process Description
The acid gas stream, which may originate from an amine
treating unit, sour water stripper, or other gas sweetening pro-
cesses, is fed to the Glaus unit for recovery of sulfur. The
classic Glaus process consists of two basic steps. First, a
portion of the H2S is converted to sulfur dioxide (S02) by com-
bustion. Second, the remaining H2S reacts with the newly formed
S0~ to produce elemental sulfur. The following equations illu-
strate these reactions.
H2S + 1.502 -> S02 + H20 (thermal combustion) (Eq. 1)
2H2S + S02 -» | Sn + 2H20 (thermal and catalytic) (Eq. 2)
The symbol S represents elemental sulfur in the vapor form,
such as S2/ S4, S,-, and Sg.
The ideal ratio of EUS to S02 after the combustion oxidation
reaction is 2.0, as illustrated in Equation 2. The sulfur pro-
duced by this reaction is in the vapor form and is recovered by
cooling the gas to condense the sulfur.
In addition to these reactions, some sulfur is produced
directly by dissociation of H2S, as shown below:
H2S -> H2 + 0.5S2 (Eq. 3)
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-1
-------
TABLE 4.16-1. TYPICAL CLAUS PLANT SULFUR
RECOVERY AT VARIOUS FEED COMPOSITIONS'
H~S in sulfur plant
feed (dry basis),
%
20
30
40
50
60
70
80
90
Calculated recovery, %
Two reactors
92.7
93.1
93.5
93.9
94.4
94.7
95.0
95.3
Three reactors
93.8
94.4
94.8
95.3
95.7
96.1
96.4
96.6
Four reactors
95.0
95.7
96.1
96.5
96.7
96.8
97.0
97.1
Petroleum Refinery Enforcement Manual
3/80 4.16-2
Sulfur Plant
-------
This is a minor reaction, however, and does not contribute appre-
ciably to the overall sulfur recovery.
The typical Glaus process employing both noncatalytic (ther-
mal) and catalytic reactions is shown in Figure 4.16-1.
Some recent sulfur plant designs involve two separate,
individually fired combustion chambers in a thermal reactor. All
of the ammonia-bearing acid gas stream is burned completely in
one combustion chamber with a slight excess of air to create an
oxidizing atmosphere. The oxidizing environment and the reactor
temperature favor combustion of ammonia (NH3) to nitrogen (N,,).
Oxidation of ammonia prevents formation of ammonium-sulfur salts
which the plug the catalyst bed in the reactors. The "clean" or
non-ammonia-bearing acid gas stream is fed to the second combus-
tion chamber, where a small portion of it is burned to generate
the balance of the S02 required to produce elemental sulfur. The
effluents from the two combustion chambers enter the reaction
furnace, where their mixture allows formation of sulfur (Equa-
tion 2). The first combustion chamber is larger than the second
and provides longer retention time.
Generally about 50 to 60 percent of the feed sulfur is
recovered in the sulfur condenser following the noncatalytic or
thermal reaction. Additional combined sulfur is converted to
elemental sulfur by the reactions of Equation 2 in the catalytic
reactors downstream of the thermal reactor. After each reactor
stage the gases are passed through a condenser, which converts
the vaporous sulfur to molten sulfur.
Following the oxidation (combustion) reaction in the thermal
reactor, the hot gases, at a temperature of 1260° to 1370°C
(2300° to 2500°F), are fed to a waste heat boiler, where steam is
generated as the gases are cooled to about 300°C (600°F). The
pressure of steam generation in the boiler ranges between 350 and
4100 kPa (50 and 600 psig).
Gases from the waste heat boiler are fed to the first sulfur
condenser, where the elemental sulfur from the thermal reactor is
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-3
-------
\fl>
oo rt
OK
o
h- <
0)
f
0)
l-h
H-
13
(D
H
M
3
l-h
O
h
O
0>
0)
cn
3
£U
REHEATER
REHEATER
REHEATER
STEAM
ACID GAS
(MAY
CONTAIN
NH3)
AIR
2nd STAGE
REACTOR
/3rd STAGED
I REACTOR J
BOILER FEEDWATER
TO
INCINERATOR/
STACK
TO TAIL
GAS UNIT
STEAM
SULFUR
TRANSFER
PUMPQ
SULFUR PIT
LIQUID
SULFUR
Figure 4.16-1. Typical Claus sulfur recovery process.
-------
condensed. Steam is generated in the sulfur condenser at pres-
sures ranging between 140 and 690 kPa (20 and 100 psig).
The noncondensed gases leave the first sulfur condenser and
are heatedV'from 320° to 340°C (600° to 650°F) before they enter
the first catalytic reactor. The gases must be heated above the
sulfur dew point to prevent condensation of sulfur on the cata-
lyst and to yield the optimum sulfur recovery in the reactor. A
fixed-bed catalytic reactor with an activated alumina (A1203)
catalyst is used to improve the overall sulfur recovery.
Following the first catalytic reactor, the sulfur-laden
gases are fed to the second sulfur condenser for recovery of the
additional molten sulfur. The noncondensed gases are again re-
heated from 200° to 230°C (400° to 440°F) before they enter the
second catalytic reactor.
Following the second catalytic reactor, the sulfur-laden
gases are fed to the third sulfur condenser for recovery of the
additional molten sulfur. The noncondensed gases leave the
second catalytic condenser and are reheated from 190° to 200°C
(370° to 400°F) before they enter the third catalytic reactor.
Following the final catalytic reactor and sulfur condensa-
tion step, the remaining gases are fed to an incinerator. In the
incinerator all sulfur compounds in the Glaus unit tail gas are
converted to S02 by combustion before being discharged from a
stack to the atmosphere.
4.16.2 Emission Sources
Acid gases in a refinery usually contain measurable quanti-
ties of one or more impurities, including hydrocarbons, carbon
dioxide, water, and possibly ammonia, which come from sour water
strippers. These impurities can reduce the efficiency of the
Glaus process. In the combustion zone, these impurities some-
times produce materials that undergo side reactions.
The major pollutant from a Glaus unit is the S02 that re-
sults from incineration of the tail gases. The Glaus unit tail
gas contains H2S, S02, and elemental sulfur.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-5
-------
The concentration of S02 in the stack gases depends on the
degree of sulfur recovery by the Glaus unit, incineration tem-
perature, catalyst activity, and amount of excess air used in the
combustion. The concentration of S00 can range between 3,000 ppm
^ o
and 20,000 ppm, but normally is 5,000 ppm. '
Sulfur fires in the catalytic reactors are possible when the
reactor temperature exceeds 200°C (400°F), and when a fire occurs
a large volume of S02 is emitted to the atmosphere from the
stack.
Additional emissions from the stack after incineration are
generally considered to be innocuous. These include N2, C02,
H20, and 0--
4.16.3 Emission Controls
Numerous Glaus plant tail gas desulfurization systems are in
commercial operation in the United States and worldwide. Four of
the processes have demonstrated their ability to meet S02 compli-
ance levels. They are the Beavon process, the Shell Glaus off-
gas treating (SCOT) process, the Wellman-Lord process, and the
Institut Francais du Petrole (IFF) process. These are discussed
in detail in the following sections.
Beavon Process
The Beavon process was developed jointly by the
Ralph M. Parsons Company and the Union Oil Company of California*
and is licensed by the Union Oil Company. A schematic diagram of
the process is shown in Figure 4.16-2. The Glaus plant tail gas
is heated to reaction temperature by mixing with the hot combus-
tion products formed in the reducing gas (CO, H2) generator. The
combined gas stream is then passed through a cobalt-molybdenum
catalyst bed, where all sulfur compounds are converted to H2S by
*Ralph M. Parsons Co., Pasadena, California, 91124;
Union Oil Company of California, Brea, California, 92621.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-6
-------
00 ft
o n
o
M
0)
(D
H-
3
w
O
(D
CD (U
I 3
-4C
Q)
CLAUS TAIL GAS
AIR-
FUEL
GAS '
REDUCING GAS
GENERATOR
CLAUS TAIL
GAS
STRETFORD SOLUTION
RETURN
CATALYTIC
REACTOR
WASTE HEAT
BOILER
WATER
WATER
QUENCHING
TOWER
EXCESS CONDENSATE
TO SOUR WATER
STRIPPER
STEAM
FROTH FILTER
AND WASH
MOLTEN
SULFUR
Figure 4.16-2. Flow diagram of the Beavon process.
Hi
-------
hydrogenation and hydrolysis according to the following reac-
tions :
S02 + 3H2 -» H2S + 2H20
CS2 + 2H20 + 2H2S + C0
COS + H20 i H2S + C02
CO + H0 + C0 + H
After exiting the catalytic reactor, the gas stream is cooled in
a waste heat boiler and/or quench tower and then fed to a Stret-
ford absorber. The H2S is absorbed in an aqueous solution of
sodium carbonate (Na2C03), sodium metavanadate (NaV03), and
anthraquinone 2,7-disulfonic acid (ADA). The H2S is initially
absorbed in the alkaline solution in the following reaction:
H2S + Na2C03 •* NaHS + NaHC03
Sodium bisulfide (NaHS) and sodium bicarbonate (NaHCOo)
further react with NaVO- to precipitate sulfur.
NaHS + NaHC03 + 2NaV03 -> S + Na2V205 + Na2C03 + H20
The reduced vanadium is subsequently oxidized back to the penta-
valent state by blowing with air in the presence of the ADA,
which works as an oxidation catalyst:
205 + 1/2 02 -> 2NaV03
In the same operation, the finely divided sulfur appears as
a froth, which is skimmed off, filtered, and washed. The product
sulfur is then separated from the washwater and melted. The
Stretford solution is recirculated to the absorber from the
oxidizer and the sulfur filter.
The treated tail gas exits the system from the absorber
overhead. It is odorless and contains only a trace of H2S and
small amounts of carbonyl sulfide (COS) and carbon disulfide
(CS2), which are not converted in the catalytic reactor. The
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-8
-------
concentration of all sulfur compounds combined is less than 100
ppm. Incineration of the off-gas is not required.
SCOT Process
The SCOT process was developed by Shell International Re-
search Mij. B.V., The Netherlands, and is licensed in the United
States by Shell Development Company.* Figure 4.16-3 is a flow
diagram of this process. The sulfur compounds in the Glaus plant
tail gas are converted to hydrogen sulfide as in the Beavon
process; i.e., the Glaus off-gas is heated along with the addi-
tion of reducing gas (H2/ CO) and passed through a reactor con-
taining a cobalt-molybdenum catalyst. The gas is cooled by use
of a waste heat boiler for steam generation and a water quenching
tower. Excess condensate from the quench is routed to a sour
water stripper.
Gas from the quench tower is contacted countercurrently in
an absorption column with a di-isopropanolamine (DIPA) solution,
which absorbs all but trace amounts of the H2S plus about 30 per-
cent of the C02. The sulfide-rich DIPA is sent to a conventional
stripper, where the H2S is removed from the solution. The over-
head gas, mostly H2S, is recycled to the Glaus unit inlet. The
lean amine solution is returned to the absorber. The absorber
outlet gas, containing some unabsorbed H2S and residual organic
sulfides, is sent to the original Glaus tail gas incinerator
before discharge to the atmosphere. Typical concentrations of
S02 range from 200 to 500 ppm.
Wellman-Lord Process
This process, developed by Davy-Powergas, Inc., is illus-
trated in Figure 4.16-4. The Glaus tail gas stream is inciner-
ated, and the gas is then cooled in a waste heat boiler and
*Shell Development Company, Houston, Texas.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-9
-------
oo rt
o H
o
M
(D
H-
s
M
O
(D
(D
fU
O (I)
CO
S1
1-1
CLAUS
TAIL-
GAS
AIR.
REDUCING
GENERATOR
CATALYTIC WASTE
REACTOR HEAT
BOILER
CLEAN TAIL GAS
TO INCINERATOR
t
ABSORBER!
STEAM
REBOILER
EXCESS
CONDENSATE
TO SOUR WATER
STRIPPER
Figure 4.16-3. Flow diagram of SCOT process.
-------
CO >TJ
\tt>
oo rt
on
o
(D
H>
H-
s
(D
n
»<
w
3
S1
n
o
CO
c:
CLEAN TAIL GAS
TO STACK
CLAUS
TAIL INCINERATOR
GAS-*-
FUEL-*
AIR-*-
STEAM
WASTE
HEAT
BOILER
REFRIGERANT
CONDENSER
SEPARATOR
EVAPORATOR/
CRYSTALLIZER
S02 TO
CLAUS UNIT
CONDENSATE
SLURRY
TEAM T1
SODIUM
SULFITE
DISSOLVING MAKEUP
TANK
STEAM
(D
3
d-
Figure 4.16-4. Wellman-Lord SO^ recovery process flow diagram.
-------
direct- quench tower before entering the absorber. In the absorb
er, the gas stream is scrubbed with a lean Na2S03 solution to
form sodium bisulfite (NaHSCs) and sodium pyrosulfite (Na2S205)
by the following reactions:
S02 + Na2S03 + H20 -> 2NaHS03
2NaHS03 -> Na2S205 + H20
The rich bisulfite solution is fed to an evaporator/crystal
lizer regeneration system. Heat supplied to the evaporator
causes the decomposition of the bisulfite and pyrosulfite:
2NaHS03 -» Na2S03 + S02 + H20
The S0~ and water vapor pass overhead from the evaporator to
a primary condenser, where 80 to 90 percent of the water is re-
moved. The condensate is stripped with steam to remove dissolved
S02. Stripper overhead and condenser overhead vapors are mixed
and sent to a secondary condenser. Condensate is returned to the
stripper, and the vapor stream is recycled to the Claus plant.
The recycle is 90 to 95 percent S02.
The main problem with the Wellman-Lord process is the forma-
tion of nonregenerable sulfate and thiosulfate by the following
side reactions:
Na2S03 + 1/2 02 ->Na2S04
S02 + 3Na2S03 -» 2Na2S04 +
Na2S2°3 "* S + Na2S03
Because of the sulfate and thiosulfate formation, a portion
of the solution must be purged from the system, necessitating re-
placement of chemicals and disposal of wastes. Chemical require-
ments have been minimized by a system that selectively removes
the sulfate by crystallization. The concentrated purge stream
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-12
-------
can then be dried for sale or disposal. Davy-Powergas is cur-
rently developing processes that chemically reduce the sulfate
back to sodium sulfite.
IFP-1500 Process
The IFF process, developed by the Institut Francais du
Petrole, is shown schematically in Figure 4.16-5. This process
converts mixed hydrogen sulfide/sulfur dioxide streams to sulfur
and water by a liquid-phase Claus reaction using a proprietary
catalyst. The process is used primarily to clean Claus unit tail
gas. The technology is an extension of the Claus reduction
process but is carried out in the liquid phase.
The tail gas, at Claus unit exit pressure, is injected into
the bottom of a packed tower, which provides the necessary sur-
face area for gas-liquid contact. A low-vapor-pressure polyethy-
lene glycol solvent containing a proprietary carboxylic acid salt
catalyst in solution circulates countercurrently to the gas.
The catalyst forms a complex with H2S and S02, which in turn
reacts with more of the gases to regenerate the catalyst and form
elemental sulfur. The reaction is exothermic, and the heat
released is removed by injecting and vaporizing steam condensate.
Temperature is maintained at about 120° to 130°C (250° to 270°F),
high enough to keep the sulfur molten but not to cause much loss
of sulfur or glycol overhead. The sulfur accumulates in the
bottom of the tower and is drawn off continuously through a seal
leg. Overheads are incinerated.
The vendor claims that the IFP-1500 process is insensitive
to changes in gas flow rates. It has been shown to operate on
flows as low as 30 percent of design rate without adverse effect.
Another stated advantage is maintenance-free operation for about
24 continuous months. After this period, a shutdown is needed to
wash away spent catalyst deposited on the packing material. A
water wash is all that is required. Outlet S02 concentration is
1000 to 2000 ppm.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-13
-------
•*• CLEAN TAIL GAS TO INCINERATOR
PACKED
TOWER
CLAUS
PLANT
TAIL
GAS
STEAM
*1 SOLVENT I CIRCULATING SOLVENT
— STEAM CONDENSATE
« SOLVENT MAKEUP
SULFUR
STARTUP HEAT
EXCHANGER
MOLTEN SULFUR PRODUCT
Figure 4.16-5. IFP-1500 Claus tail-gas treatment.
Petroleum Refinery Enforcement Manual
3/80 4.16-14
Sulfur Plant
-------
4.16.4 Instrumentation
1) Ratio of Hydrogen Sulfide to Sulfur Dioxide
The H2S/S02 ratio is very important for the proper control
of a Glaus unit. Since H9S concentration in acid gas feed varies
£*
significantly, the H2S/S02 ratio must be monitored. The H2S/S02
ratio is controlled by a ratio controller that maintains a proper
ratio of acid gas to air in the reactor. A correct H-S/SO- ratio
indicates whether the stoichiometry of the Glaus reaction is
correct throughout the sulfur plant.
4
2) Temperature Control
The temperature of the noncondensed gases entering the cata-
lyst converters must be maintained above the sulfur dew point to
prevent sulfur condensation on the catalyst and to faciliate
optimum sulfur recovery in the reactor. An optimum temperature
for the converter must be established, although the optimum
temperature changes with catalyst aging. An approximation of the
desired reaction rate is maintained by increasing the temperature
to compensate for the drop in catalyst activity.
The temperature at the incinerator stack must be high enough
to ensure complete combustion of sulfur compounds to S02. The
usual incinerator temperature is about 1200°C (2200°F) but would
increase to 1400°C (2600°F) when the acid gas feed is bypassed
directly to the incinerator, thus increasing the SO- emission at
the stack. Hence, incinerator temperature is a good indicator of
the amount of acid gas bypassed. The stack gas temperature is
measured with a standard Type K (nickel, chromium-nickel, alumi-
num ) thermocouple.
Emission of S02 is continuously monitored at the stack.
Stack monitoring is useful in plant optimization studies since
trends in S02 emission indicate when operational changes are
successful. The analyzer is located at the base of the stack for
easy access during troubleshooting.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-15
-------
4.16.5 Startup/Shutdown/Malfunctions
Startup and shutdown of a Glaus sulfur unit require con-
siderable attention by the operator, since operation during these
critical phases can greatly affect the overall plant efficiency.
Once the Claus unit is onstream, however, little monitoring is
needed except in unusual circumstances.
Most of the Claus units installed today have refractory-
lined external combustion chambers. The most difficult startup
problems are associated with the external combustion chamber.
Carefully controlled curing of the refractory is necessary to
prevent spalling. If the refractory is heated too rapidly, water
in the refractory will vaporize rapidly, causing damage to the
refractory. Gradual heating of the refractory is especially
important during the initial startup. During the refractory
curing, it is imperative that the curing temperature be held
constant because temperature oscillations often lead to improper
curing and subsequent failure of refractories.
Before either the pilot or the main burner is ignited, the
waste heat boiler must be filled with water to prevent damage to
the tubes.
The most important part of the Claus sulfur plant operations
is the procedure to be followed for planned shutdowns. Stoichio-
metric combustion of fuel gas is used to purge the sulfur com-
pounds and also to cool the unit. Fuel gas is added to the
burner, and when the fuel gas flame is established, the acid gas
is shut off.
Airflow to the unit is increased to oxidize the fuel gas
stoichiometrically. Incomplete combustion of fuel gas because of
less than stoichiometric air can cause carbon formation that can
seriously foul the unit. Generally, the carbon is deposited on
the catalytic reactor and can sometimes block the flow through
reactors. Deposition of carbon on boiler and sulfur condenser
tubes can cause production of off-color sulfur. Thus, it is
important that adequate air is available and the fuel gas is
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-16
-------
fully oxidized. Natural gas is recommended for shutdown proced-
ures because the variable composition of fuel gas makes proper
oxidation difficult.
Control of the combustion temperature when stoichiometric
combustion conditions exist is also important. The stoichio-
metric combustion temperature ranges between 1650° and 2040°C
(3000° and 3700°F), depending upon the fuel gas composition.
This range is too high for the refractory in the external combus-
tion chamber. Inert gases such as nitrogen are used to reduce the
temperature of the stoichiometric products of combustion and to
maintain reasonable chamber temperatures. Excess air cannot be
used at this stage because sulfur ignites spontaneously in the
presence of oxygen at temperatures above 204°F (400°F). Reactor
temperatures usually exceed this level at the time of shutdown.
Therefore, excess oxygen of only 2 percent is used to ensure
proper combustion of the fuel gas and prevent spontaneous igni-
tion of sulfur in the reactor. Regular analysis of the combus-
tion products is required to maintain this close control because
sulfur fires can occur even with the small amount of excess
oxygen used for proper combustion. If a sulfur fire is detected,
the air should be promptly shut off. Inert gas such as nitrogen
should continue being fed to the unit. The nitrogen will extin-
guish the sulfur fire and continue to purge the unit of free
sulfur.
It is imperative that the sulfur be purged from the unit
prior to cooling because sulfur will solidify at temperatures
below 121°C (250°F). The presence of solidified sulfur can
necessitate replacement of the catalyst and manual cleaning of
the boiler and sulfur condenser tubes.
Emergency shutdowns often cause serious problems in a Glaus
unit if the proper precautions are not taken. If the burner
cannot be relit soon after an emergency shutdown, such as one
caused by a low level of water in the boiler, inert gas should be
fed to purge the reactor of sulfur. Otherwise the sulfur could
solidify and cause considerable damage to the plant.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-17
-------
Most of the problems in the operation of a tail gas unit
stem from Claus unit upsets and fluctuations. In the Beavon/
Stretford process, tail gas flow rates higher than the design
rates can cause solvent overloading. Mechanical problems have
also been encountered with the froth filter, which may be eli-
minated on future units. Excess S02 causes contamination of the
amine solution in a SCOT unit and corrosion of the quench water
pump and pipes. This problem can be prevented by monitoring the
pH of the quench water and by ensuring an excess of hydrogen in
the reactor by use of the reducing gas injection system. Emis-
sions of S02 and H2S caused by fluctuating tail gas flow rates
can be reduced or averted by proper flow controls on the Claus
unit.
4.16.6 References
1. Barry, C. B. Reduce Claus Sulfur Emission. Hydrocarbon
Processing, April 1972. pp. 102-106.
2. Communication between Ford, Bacon, and Davis, Dallas, Texas,
and Texas Air Control Board, Austin, Texas. June 25, 1975.
3. Communication between Ford, Bacon, and Davis, Dallas, Texas,
and U.S. Environmental Protection Agency, Raleigh, North
Carolina. September 9, 1971.
4. Grancher, P. Advances in Claus Technology. Hydrocarbon
Processing, September 1978. pp. 257-262.
5. Parnell, D. C. Claus Sulfur Recovery Unit Startups. Chemi-
cal Engineering Progress, August 1969. pp. 8892.
Petroleum Refinery Enforcement Manual Sulfur Plant
3/80 4.16-18
-------
SULFURIC
ACID
-------
4.17 SULFURIC ACID PLANT1"4
Crude oils contain elemental sulfur, hydrogen sulfide, and
other sulfur compounds. The sulfur must be removed because it
can contaminate catalysts during intermediate cracking and can
generate corrosive gases and sulfur dioxide emissions during fuel
oil, kerosene, and gasoline combustion.
One way to handle the sulfur produced as an oil refinery
byproduct is to build a sulfuric acid plant. Fifty-five percent
of the sulfuric acid produced is used in the refinery for the
alkylation unit. The production of sulfuric acid is not limited,
however, to the oil industry. Sulfuric acid is a necessary part
of the organic chemical, inorganic pigment, metal, fertilizer,
and detergent industries.
The standard contact process is used to manufacture about
90 percent of the sulfuric acid in the United States. Variations
in this conventional process are the acid recirculation process,
the Simonson-Mantius vacuum process, and the Chemico drum concen-
tration process. At the refinery, sulfuric acid is made from
recovered elemental sulfur, hydrogen sulfide from the amine
stripper, and spent acid from the alkylation units. Sulfuric
acid is also produced from sulfur obtained from the Glaus unit
tail gas described in Section 4.16.
4.17.1 Process Description
Standard Contact Process
Hydrogen sulfide or elemental sulfur is the raw material for
sulfuric acid production at refineries. Three basic reactions of
acid production are illustrated below:
s + °2 "* S02
Sulfur Oxygen Sulfur dioxide
2S02 + 02 -» 2S03
Sulfur Oxygen Sulfur trioxide
dioxide
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-1
-------
so3 -
Sulfur
trioxide
Water
H2S04
Sulfuric acid
In these reactions, the sulfur or hydrogen sulfide is first
burned to sulfur dioxide. The sulfur dioxide is then catalyti-
cally converted to sulfur trioxide, which is absorbed by a sul-
furic acid solution.
Figure 4.17-1 is a flow diagram of an elemental sulfur
burning plant for sulfuric acid production. Dry air scrubbed
with 95 percent H2SC>4 is used in burning elemental sulfur to
sulfur dioxide. A catalytic converter, using a vanadium pentoxide
catalyst, transforms the S02 to S03. The heat (energy) from this
exothermic reaction is usually directed to steam production. The
converter heater systems are of two types: internal heat ex-
changer, with cooling tubes embedded in the catalyst; or external
coolers installed between the converters.
The sulfur trioxide is cooled and transferred to an absorp-
tion tower where it is absorbed by a solution of 99 percent
H2S04. In some cases an oleum solution of uncombined S03 in
H2S04 is produced. This excess S03 is sent to another column for
further absorption. The oleum tower gases are recycled to the
first absorption column to remove any residual S03.
Spent acid regeneration in the contact process is becoming
more attractive as a solution to unwanted byproducts. High-
quality H2S04 can be produced by thermal decomposition of H2S04
at high temperatures to S00, and then conversion of the S09 to
Z* £*
concentrated H2S04 or oleum. The reactions in this spent acid
process are shown below:
H2S04
Sulfuric
acid
H20
Water
so3
Sulfur
trioxide
so3
Sulfur
trioxide
so2
Sulfur
dioxide
1/2 02
Oxygen
Petroleum Refinery Enforcement Manual
3/80 4.17-2
Sulfuric Acid Plant
-------
CO TJ
\0>
c» rt
oh
o
M
0>
c
3
H,
H-
3
0)
W
o
i
(D
I C
CO flj
H-
O
DRYING
TOWER
AIR
BLOWER
LIQUID
SULFUR
STORAGE
STEAM DRUM
SLOWDOWN
s?
ACID
COOLER
T f\r\ ft /"»r~ ™"»«™
SULFUR
PUMP
t
-o—o
-o—-o
STEAM TO
ATMOSPHERE
ABSORPTION
TOWER
FURNACE BOILER BOILER CONVERTER
BOILER FEEDWATER
r
WATER
-i-.
ACID
COOLER
ACID PUMP
TANK
•*• SULFURIC ACID
O
H-
CL
OJ
3
rt
Figure 4.17-1. Flow diagram of contact-process
sulfuric acid plant burning elemental sulfur.
-------
H2S04 -» H20 + S02 + 1/2 02
Sulfuric Water Sulfur Oxygen
acid dioxide
The first reaction step is conducted at temperatures above 500°C
(932°F). The second step requires even higher temperatures. The
efficiency of the whole process ranges between 60 and 70 percent.
Figure 4.17-2 is a flow diagram of an acid regeneration
plant. This acid decomposition unit is combined with a heat
recovery system for high-pressure steam production.
A rotary atomizer feeds spent acid into a vertical decom-
position furnace. The lower part of the decomposition furnace is
held at 100°C (212°F) for maximum efficiency. The decomposition
gases leaving the gas heat exchangers are cleaned in a venturi
scrubber and cooled to 90°C (194°F). The S02 gases are further
cooled in the countercurrent cooling tower with a water section
containing 1 percent H-SCL. The gases pass through the electro-
static precipitators for mist elimination.
The gas stream is then dried and discharged into a sulfur
trioxide converter. The gas from the converter flows to a tower
where a solution of 93 to 98 percent H2S04 absorbs the S03.
Another design for the heat recovery system of a regenera-
tion sulfuric acid plant includes a waste heat boiler. In this
design, the decomposition furnace has three combustion chambers
using heavy fuel oil and air preheated to a temperature of about
300°C (570°F).
The Simonson-Mantius Vacuum Concentration Process
In the Simonson-Mantius variation of the contact process,
steam heating vaporizes the water from the vacuum-maintained
acid. This method is more economical than the standard process
if low-pressure waste steam is available and if the operating
range is dilute. The vacuum method allows lower operating tem-
peratures to be used.
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-4
-------
to *xi
\(D
oo ft
o H
o
3?
H,
H-
0
CD
H
M
3
Hi
O
h(
O
n>
(D
MS
vj flJ
(1)
S1
H
H-
n
VENTURI INDIRECT MIST
SCRUBBER COOLER PRECIPITATORS
SPENT ACID WASTE
HEAT
FUEL
AIR
FUEL
BOILER
INTERMEDIATE
HEAT EXCHANGER
DECOMP
FURNACE
AIR
PREHEATER
SUPERHEATER
GAS HEAT EXCHANGER
*-TAIL GAS
TO STACK
+. H2S04 PRODUCT
*- OLEUM PRODUCT
-*• HIGH-PRESSURE
STEAM
o
H-
Figure 4.17-2. Flow diagram of acid regeneration plant.'
-------
Figure 4.17-3 is a simplified flow diagram of a vacuum
concentration process. The 30 percent feed acid is sent to the
first concentrator unit, which is held at 66°C (150°F) and 13.5
kPa (4 in. Hg). Steam heating is used to increase the concentra-
tion of acid to 50 percent. In the same manner, the acid is
further concentrated in two additional units to 93 percent. Each
concentrator unit is held at a lower pressure and a higher tem-
perature than the preceding one. The acid is then pumped through
an acid cooler to a product storage tank held at 43°C (110°F).
The Chemico Drum Concentration Process
The Chemico drum concentration process is similar to the
Simonson-Mantius process with the exception of the concentrator
unit. Figure 4.17-4 is a flow diagram of this process. The
water is removed from the acid in the concentrator drum, which is
operated at atmospheric pressure. The acid, sent through a
furnace fired with fuel gas, is directly in contact with the fuel
gas before it reaches the three stages of the concentrator drum.
One advantage of using the drum process is the cleaning of gases
in the venturi scrubber after leaving the drums. The concen-
trated acid is then cooled and stored. This process produces
acid at a concentration of 93 percent.
Contact Process With Single Absorption and Acid Recirculation
The Chemetics International process for a sulfuric acid
plant is a single absorption process using pressure to improve
catalysis and to recycle a substantial amount of S02 via a simple
acid circulating system. This process, which is shown in Figure
4.17-5, increases efficiency, lowers emissions, reduces equipment
size, and saves power. In the first step the inlet air is fil-
tered, dried by contact with sulfuric acid, and compressed to
between 505 and 1520 kPa (5 and 15 atm). The dry air passes
through a furnace where molten sulfur is burned to form a hot SO^
gas and cooled in a waste heat boiler. The S02 gas is then
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-6
-------
\0>
00 ft
O H
o
H-
§
H
S1
H
O
(D
W
ft
en
£
n
H-
O
COOLING WATER 27'C
STEAM 2170 kPa
Tl
TT
Tl
STEAM 1136 kPa
i i
I i
STEAM 446 kPa
CONCENTRATOR
13.5 kPa
ABS PRESS
66*C
CONDENSATE
TRAY
50% ACID
9%
CONCENTRATOR
8.5 kPa
w
80» ACID
93% ACID
PUMP
1
4
f ACID COOLER
931
ACID
~2^ ^^^
PRODUCT ACID
TANK
43°C
CONDENSATE
TANK
PUMP
O
H-
o.
(1)
£3
Figure 4.17-3. Flow diagram of vacuum concentration process.
-------
oo rt
O H
o
50
0)
HI
0)
h
H
O
0)
3
n>
OD
en
H-
O
O
H-
(U
3
ft
HIGH INTERMEDIATE
STAGE STAGE
PROCESS
WATER
AIR BLOWER
CONCENTRATED
ACID
CONCENTRATOR DRUM
COOLER SCRUBBER VENTURI SCRUBBER
DRUM ACID AND
PUMP SEPARATOR
1
COOLING
l— , c
^T^i ,j;
WATER 1
T
^..;.tt. ,.. X*
k
PRODUCT ACID
r
^±.
ACID MIX
TANK
STRONG ACID
PUMP TANK
AND
CIRC. PUMP
H
SEWER
COOLER
Figure 4.17-4. Flow diagram of Chemico drum concentration process.
3
-------
CO *Xf
\n>
oo rt
o n
o
M
(D
£
i-h
H-
H)
o
n
n
fD
0)
COMPRESSOR
TO
TAIL GAS STACK
EXPANDER
FURNACE
BOILER
PRIMARY
REACTOR
SECONDARY
REACTOR
ACID COOLER
PRODUCT
t-h
l-<
H-
O
Figure 4.17-5. Flow diagram of acid recirculation process.'
O
H-
-------
converted to S03, cooled, and absorbed in the acid. The exhaust
gas is reheated using process heat and passed to an expansion
turbine. The S02~free acid is sent to the top of the absorber.
In the absorber, it produces a warm, SCX^-rich acid stream, which
passes through the coolers to the drying tower. The S02 is
transferred to the inlet air while it is simultaneously being
dried. The S02-free acid is then recirculated to the absorber.
4.17.2 Emission Sources
Sulfur oxides, mainly dioxide, and acid mist are the primary
emissions of the acid plant. Sulfur dioxide emissions are pro-
portional to the conversion efficiency of S02 to S0_. Conversion
efficiency depends on the number of stages in the catalytic
reactor, the quantity of catalyst, reactor temperature and pres-
sure, and reactant concentrations. Single absorption plants
usually have efficiencies of 95 to 98 percent.
Most of the sulfur dioxide is emitted in the exit gases from
the absorber. There are some fugitive S02 emissions, however,
from tank vents while loading, and from process equipment leaks.
In a well-operated plant, there are minor fugitive emissions.
Acid mist is produced when sulfur trioxide combines with
water vapor below the sulfur trioxide dew point. Absorber exit
gases are the primary emitters of acid mist. The feedstock and
strength of the acid product determine the amount of acid mist
emitted. Clean elemental sulfur feedstock produces little acid
mist; spent acid and hydrogen sulfide, however, oxidize the water
vapor and the water combines with the sulfur trioxide to produce
acid mist.
The concentration of acid mist emissions is directly pro-
portional to the concentration of the acid product. For in-
stance, oleum plants produce more acid mist with higher stability
and finer particle size than do 99 percent sulfuric acid plants.
4.17.3 Emission Controls
Sulfur dioxide emissions can be reduced by dual absorption
or by the sodium sulfite-bisulfite process. These acid mist
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-10
-------
control methods produce no unwanted byproducts. When a dual
absorber is used for sulfuric acid production, the efficiency of
the conversion from S02 to SO., increases from about 96 (for a
single absorption process) to 99.7 percent or higher. The two
absorbers are run in series, and the increased operating effi-
ciency reduces S02 emissions.
In the sodium sulfite-bisulfite process, scrubbing is used
to remove S02 from the exit gases by a solution of sodium sul-
fite. The S02 is separated from the sulfite, and the sulfite is
recycled to the plant. Sulfite-bisulfite absorption can remove
99.8 percent or more of the S02 in the exit gases.
Acid mist emissions are reduced by an electrostatic precipi-
tation (ESP) or fiber mist eliminator. The ESP has been shown to
be 99 percent efficient with good operating and maintenance
practices.
The fiber mist eliminator is usually of the vertical tube,
vertical panel, or horizontal dual-pod type. Only small quanti-
ties of acid mist are removed by the absorber. Glass or fluoro-
carbon fibers are used to collect the acid mist from the exit gas
stream. The removal efficiency of these units usually exceeds
99.9 percent. This excellent control is achieved with minimal
maintenance because fiber beds do not have moving parts.
Certain problems, however, are associated with the mist
eliminator: entrainment of large particles; a persistent, visi-
ble plume; reduced capacity because of pluggage. Entrainment is
corrected by monitoring gas flow rates and conducting a physical
inspection of the unit, including the liquid seals. When a
visible plume is spotted, a sample is taken to determine whether
the plume is caused by unabsorbed S0~. If it is, changes are
made in the operation of the absorbing tower.
Pluggage is caused by a buildup of iron sulfate or sublimed
sulfur on the mist eliminator. The buildup of iron sulfate
results from water in the system; the sublimed sulfur results
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-11
-------
from improper operation of the sulfur burner. Correction in-
volves water washing the sulfate deposits and washing the sub-
limed sulfur with a 0.5 percent sodium sulfide solution after the
elements are neutralized with soda ash. Preventive measures
include keeping records of pressure drop, flow rate, operating
tower information, mist eliminator drain rate, and acid strength.
Mist formation can be regulated by keeping as little water
in the sulfur trioxide gas stream as possible. The water content
can be minimized by lowering the organic content of the sulfur,
thoroughly drying the process air stream, and increasing absorb-
ing tower acid strengths.
Mist eliminator problems are detected by inserting a clean,
wooden stick into a suspect gas stream. If problems are present,
the stick will show a certain number of black spots for a given
period of exposure. The stick tests should be carried out where
the gas velocity is in excess of 304.8 m/min (1000 ft/min).
Sampling is a more precise technique than the stick test,
but it is time consuming and does not distinguish between liquid
acid mist and sulfur trioxide vapor.
4.17.4 Instrumentation
Temperature, pressure, flow rate, and raw material influence
the efficiency of the acid production process. Temperature and
pressure are controlled and monitored closely. The temperature
varies (depending on the process) around 400°C (750°F). Spent
acid undergoes thermal decomposition, however, at about 1000°C
(1830°F). Heat must be removed from the process because the S03
formation is exothermic and the equilibrium constant becomes less
favorable as the temperature rises. Increasing the pressure
forces the system to react to sulfur trioxide, because 1.5 moles
of reactants form 1 mole of product, which requires less volume.
Increasing the oxygen content increases reaction efficiency.
Concentrations of oxygen and sulfur dioxide, which are the
reactants, must be monitored.
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-12
-------
4.17.5 Startup/Shutdown/Malfunctions
During acid plant startup, an energy (heat) source initiates
the conversion of sulfur dioxide to sulfur trioxide. When the
reaction has begun, the energy source is removed and the process
produces its own heat energy (plus excess energy for steam pro-
duction). Temperature is critical during startup, and should be
closely monitored.
Acid plant shutdown does not cause problems. Shutdown is
effected simply by shutting off the feedstock and oxygen supply.
Malfunctions might occur as a result of the corrosive nature
of the acid product. Nickel chromium alloys and polytetrafluo-
roethylene (PTFE) coating have reduced malfunctions.
4.17.6 References
1. U.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. AP-42, 1977. p. 5.17-2.
2. Sander, V., and G. Daradimos. Regenerating Spent Acid.
Chemical Engineering Progress, September 1978. p. 62.
3. Smith, G. M., and E. Mantius. The Concentration of Sulfuric
Acid. Chemical Engineering Progress, September 1978.
pp. 79-80.
4. Cameron, G. M., P. D. Nolan, and K. R. Shaw. The CIL Pro-
cess For Acid Manufacture. Chemical Engineering Progress,
September 1978. p. 49.
Petroleum Refinery Enforcement Manual Sulfuric Acid Plant
3/80 4.17-13
-------
BLENDING
-------
4.18 PRODUCT BLENDING1
Petroleum refineries increase operating flexibility and
profits by blending intermediate crude oil derivatives into a
variety of finished goods. Blending minimizes costs by combining
low-cost intermediates with higher cost materials to produce
incremental products at maximum profit.
Computers aid in formulating and metering the in-line blend-
ing of gasoline and other high-volume product operations. Data
about intermediate material inventories, costs, and physical
properties are stored in the computer. Operational research
techniques (linear programming) select the components that will
produce the required volume of a specified blended product at the
lowest possible cost.
4.18.1 Process Description
A pipeline, receiving tank, and metering pumps and valves
are usually the only equipment necessary for intermediate blend-
ing. In-line and tank mixers may also be used. Stream analyzers
are sometimes used to test the boiling point, specific gravity,
Reid Vapor Pressure (RVP), and octane of the blended product to
ensure that it is within specifications.
Blends are usually based on a few parameters. For instance,
gasoline is blended to obtain a specific RVP by using components
with boiling ranges within the product specification and adjust-
ing for octane values. A typical gasoline might consist of
light-straight-run (LSR) stock, reformate, alkylate, and FCC
gasoline blended with n-butane to arrive at the prescribed RVP
and octane level. Motor oil blends depend heavily on viscosity.
4.18.2 Emission Sources
Fugitive volatile organic compounds (VOC) are the most
common emissions from a product blending operation. Leaky
unions, fittings, pumps, and valves are the primary sources.
Tank loading emissions can be significant, especially where a
fixed-roof blend tank is filled with gasoline at a pressure of 69
Petroleum Refinery Enforcement Manual Product Blending
3/80 4.18-1
-------
kPa (10 psia). Lubricating oils emit low levels of VOC; fuel oil
emits slightly higher levels because it has a higher vapor pres-
sure.
4.18.3 Emission Controls
Pipefittings should be checked and replaced or tightened
whenever necessary to eliminate VOC emissions. Tanks built after
1971 and having vapor pressure between 10 and 76 kPa (1.5 and 11
psia) must be equipped with floating roofs to minimize emissions.
In some instances, emissions from tanks are controlled by vapor
recovery systems.
Valve and pump seals should be checked regularly and tight-
ened or replaced if leaking. Sampling ports and piping and
instrument lines should be checked and repaired as necessary.
4.18.4 Instrumentation
Volume measurement and control are the most important func-
tions in a blending operation. Volumes must be measured accur-
ately to control the blend and ultimate quality of a product.
Instrumentation is complicated if a computer is used to control
flow rates and volumes. Continuous sampling devices and testing
equipment are usually associated with the metering pumps and
valves. Parameters monitored include boiling point, vapor pres-
sure, octane number, and viscosity.
4.18.5 Startup/Shutdown/Malfunctions
Startup and shutdown of a blending operation create no
particular problems. The pipes, valves, and pumps are relatively
standard and do not present unfamiliar problems to the refining
industry.
Pumps, valves, and fittings should be carefully inspected
for VOC leaks during startup of a blending operation. Pump and
valve packing should be tightened or changed if a leak is detect-
ed. Fittings should be tightened or replaced as necessary.
If blend tanks are to be empty for any extended period, they
should be cleaned to minimize VOC emissions.
Petroleum Refinery Enforcement Manual Product Blending
3/80 4.18-2
-------
4.18.6 Reference
1. Nelson, W. L. Petroleum Refining Engineering. McGraw-Hill
Book Company, New York, 1958. pp. 141-146.
Petroleum Refinery Enforcement Manual Product Blending
3/80 4.18-3
-------
STORAGE
-------
4.19 CRUDE AND PRODUCT STORAGE1
4.19.1 Vessel Description
A refinery includes facilities for storage of large volumes
of crude oil, intermediates, and finished products. Storage
vessels provide a surge capacity and reservoir for refinery
operations. Vessels in a refinery include fixed-roof tanks,
pressure tanks, floating-roof tanks, and conservation tanks.
These are constructed in a variety of shapes, most commonly as
cylinders, spheres, or spheroids. Steel plate is the usual
material of construction, and sections of the shell are welded
together. Capacities range from a few thousand liters (gallons)
up to 79 million liters (500,000 barrels).
A New Source Performance Standard (NSPS) has been promul-
gated in 40 CFR Part 60 Subpart K, Standards of Performance for
Storage Vessels for Petroleum Liquids. This regulation specifies
the type of storage required for three volatility categories:
low, intermediate, and high. Table 4.19-1 defines volatility
categories in terms of vapor pressure and lists the types of
tanks acceptable for storage of liquids in each category. The
vapor pressures of various hydrocarbons and petrochemicals are
listed in Table 4.19-2. The inspector may refer to this table or
to Appendix E to determine the type of storage vessel required
for various refinery products.
The fixed-roof tank is the minimum accepted standard for
storage of low volatility liquids. A cylindrical steel tank
shell is topped by a fixed conical roof having a minimum slope of
6.25 cm/m (3/4 in./ft). The tanks are generally equipped with a
pressure/vacuum (p/v) vent designed to accommodate minor changes
in vapor volume. Fixed-roof tanks are used to store low-vapor-
pressure materials such as crude oil, middle to heavy distil-
lates, and asphalts. Figure 4.19-1 illustrates a fixed-roof
storage tank.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 . 4.19-1
-------
TABLE 4.19-1.. ACCEPTABLE STORAGE TANKS FOR PETROLEUM
LIQUIDS OF LOW, INTERMEDIATE, AND HIGH VOLATILITY
Volatility of
stored liquid
Vapor pressure range
kPa
psia
Storage tank0
Low
Intermediate
High
10 to 79
1.5 to 11.2
377
Fixed-roof tank
Floating-roof tank
Covered floating-roof tank
Variable-vapor-space tank (lifter
roof and flexible diaphragm) with
vapor controls for loading losses
Pressure tanks sealed or vented to
recovery systems:
Low pressure, 119 to 205 kPa
(17.2 to 29.7 psia)
Intermediate pressure, 205 to
308 kPa (29.1 to 44.7 psia)
High pressure. >308 kPa (44.7 psia)
Meeting minimum acceptable standard under NSPS.
Petroleum Refinery Enforcement Manual
3/80 4.19-2
Crude and Product Storage
-------
CO
00
O
TABLE 4.19-2. PHYSICAL PROPERTIES OF HYDROCARBONS
o
M
ft>
£
rt\
H-
n Fuels
H Gasoline RVP 13
H> Gasoline RVP 10
8 Gasoline RVP 7
| Crude oil RVP 5
•?. Jet naphtha (JP-4)
2 Jet kerosene
g Distillate fuel No. 2
M Residual oil No. 6
Vapor
molecular
weight
at 60°F
62
66
68
50
80
130
130
190
Product
density
Ib/gal
at 60°F
5.6
5.6
5.6
7.1
6.4
7.0
7.1
L_ 7'9
Vapor pressure in psia at:
40°F
4.7
3.4
2.3
1.8
0.8
0.0041
0.0031
0.00002
50°F -
5.7
4.2
2.9
2.3
1.0
0.0060
0.0045
0.00003
60°F
6.9
5.2
3.5
2.8
1.3
0.0085
0.0074
0.00004
70°F
8.3
6.2
4.3
3.4
1.6
0.011
0.0090
0.00006
80°F
9.9
7.4
5.2
4.0
1.9
0.015
0.012
0.00009
90°F
11.7
8.8
6.2
4.8
2.4
0.021
0.016
0.00013
100°F
13.8
10.5
7.4
5.7
2.7
0.029
0.022
0.00019
o
n
(D
0)
n
rt
o
h
fa
iQ
CD
-------
\fl>
00 ft
o n
o
i-"
(D
H>
H-
M
D
HI
O
n
a
i
CD
O
H
C
PRESSURE-VACUUM
VENT
GAUGE HATCH
MANHOLE
NOZZLE
O
a
£
O
Figure 4.19-1. Fixed-roof storage tank.
ft
o
vd
ID
-------
Floating-roof tanks are used for storing volatile material
with vapor pressures in the lower explosive range, such as gaso-
line and the liquid intermediates (alkylate, poly-gasoline,
reformate, catalytic cracker gasoline, etc.) used in the blending
of gasoline. A floating-roof tank reduces evaporative losses in
storage by minimizing vapor spaces. The tank consists of a
welded or riveted cylindrical steel wall equipped with a deck or
roof, which is free to float on the surface of the stored liquid.
The roof rises and falls with the level of stored liquid. So
that the liquid surface remains completely covered, the roof is
equipped with a sliding seal that fits against the tank wall.
Sliding seals are also provided at support columns and at all
other points where tank appurtenances pass through the floating
roof. Antirotational guides maintain the alignment of the roof.
The most commonly used floating-roof tank is the conven-
tional open tank. Because the open-tank roof deck is exposed to
the weather, provisions must be made for rainwater drainage, snow
removal, and protection of the sliding seal against dirt. Float-
ing-roof decks are of three general types: pontoon, pan, and
double deck.
The pontoon roof, shown in Figure 4.19-2, is a pan-type
floating roof with pontoons arranged to provide floating sta-
bility under heavy loads of water and snow.
The pan roof, shown in Figure 4.19-3, is a flat metal plate
with a vertical rim and stiffening braces to maintain rigidity.
The single metal-plate roof in contact with the liquid readily
conducts solar heat, with the result that vaporization losses are
higher than those from other floating-roof decks. The roof is
equipped with automatic vents for pressure and vacuum release.
As shown in Figure 4.19-4, the doubledeck roof consists of a
hollow double deck covering the entire surface of the tank. The
double deck adds rigidity, and the dead air space between the
upper and lower decks provides effective insulation from solar
heat.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-5
-------
ROOF SEAL
(NONMETALLIC)
WEATHER SHIELD,
NOZZLE
FLEXIBLE
ROOF DRAIN
LGUIDE
RODS
Figure 4.19-2. Single-deck pontoon-floating-roof storage
tank with nonmetallic seals.
Petroleum Refinery Enforcement Manual
3/80 4.19-6
Crude and Product Storage
-------
ROOF SEAL (METALLIC SHOE)
NOZZLE
WEATHER SHIELD.
FLEXIBLE
ROOF DRAIN
,
Figure 4.19-3. Pan-type floating-roof storage tank with metallic seals,
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-7
-------
NOZZLE
ROOF SEAL
(NONMETALLIC)
WEATHER SHIELD
FLEXIBLE
ROOF DRAIN
GUIDE
RODS
Figure 4.19-4. Double-deck floating-roof storage tank with nonmetallic seals,
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-8
-------
The covered floating-roof tank is essentially a fixed-roof
tank with a floating deck inside the tank (Figure 4.19-5). The
American Petroleum Institute (API) has designated the term
"covered floating roof" to describe a fixed-roof tank with an
internal steel pan-type floating roof. They have designated the
term "internal floating cover" to describe internal covers con-
structed of materials other than steel. Floating roofs and
covers can be installed inside existing fixed-roof tanks. The
fixed roof protects the floating roof from the weather, and no
provision is needed for rain drainage, snow removal, or seal pro-
tection. Antirotational guides must be provided to maintain roof
alignment, and the space between the fixed and floating roofs
must be vented to prevent the formation of a flammable mixture.
Variable-vapor-space tanks have not been built for several
years. Tank manufacturers report, however, that new orders for
variable-vapor-space tanks have been received. These tanks are
equipped with expandable vapor reservoirs to accommodate fluc-
tuations in vapor volume attributable to changes in temperature
and barometric pressure. A variable-vapor-space device is nor-
mally connected to the vapor space of one or more fixed-roof
tanks. The two most common types of variable-vapor-space tanks
are lifter-roof tanks and flexible-diaphragm tanks. Storage
vessels classified as conservation tanks include lifter-roof
tanks and tanks with internal, flexible diaphragms or internal,
floating blankets. These tanks are used in storage of volatile
fuel.
In a lifter-roof tank design, a telescoping roof fits loose-
ly around the outside of the main tank wall. The space between
the roof and the wall is closed by either a wet seal, which
consists of a trough filled with liquid, or a dry seal, which
consists of a flexible coated fabric in place of the trough
(Figure 4.19-6).
In a flexible-diaphragm tank, a flexible membrane provides
the expandable volume. Such a tank may be a separate gas-holder
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-9
-------
ROOF
SEAL
AIR VENTILATORS
NOZZLE
Figure 4.19-5. Covered floating-roof storage tank.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-10
-------
PRESSURE-VACUUM
VENT
ROOF SEAL
(LIQUID IN
TROUGH)
LIFTER
ROOF
NOZZLE |J
Figure 4.19-6. Lifter-roof storage tank with wet seal.
Petroleum Refinery Enforcement Manual
3/80 4.19-11
Crude and Product Storage
-------
unit or an integral unit mounted atop a fixed-roof tank (Figure
4.19-7).
Pressure tanks are designed to withstand relatively large
pressure variations without loss of stored materials. They are
constructed in many sizes and shapes, depending on the operating
pressure range. Noded spheroid tanks are accepted for operating
pressures up to 200 kPa (29 psia). Spheroids have been operated
at pressures up to 310 kPa (45 psia). High-pressure tanks,
either cylindrical, spherical, or blimp shaped, have been oper-
ated at pressures up to 1827 kPa (265 psia). Pressure tanks are
used to store such high-vapor-pressure materials as butane and
propane.
4.19.2 Emission Sources
Storage facilities represent the largest single potential
source of hydrocarbon emissions from refineries. Emissions of
hydrocarbon vapors result from the volatility of the stored
materials. The API has developed empirical formulas, based on
field testing, that correlate tank evaporative losses with the
following parameters:
True vapor pressure of the liquid stored
Temperature changes in the tank
Height of the vapor space
Tank diameter
Schedule of tank filling and emptying
Mechanical condition of tank and p/v valve seals
Tank design and type of exterior paint
These evaporative emissions are classified as breathing losses,
working losses, and standing losses (floating-roof tanks only).
Breathing losses are hydrocarbon emissions resulting from
changes in temperature and barometric pressure. The vapor space
in a tank contains air mixed with the vapor of the stored liquid.
Pressure relief valves and vacuum vents on top of the storage
vessels prevent pressure increase above the safe operating range
or operation under a vacuum. As the temperature rises during the
day, liquid vaporizes and mixes with the air and vapor in the
vapor space. As the pressure increases and exceeds the set value
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-12
-------
PRESSURE
VACUUM VENTS
NOZZLE
FLEXIBLE
DIAPHRAGM
LIQUID LEVEL
Figure 4.19-7. Flexible-diaphragm storage tank.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-13
-------
on the relief valve, the valve opens and vents the airvapor
mixture to the atmosphere. As the temperature drops, as at
night, the vapor space cools and contracts. Fresh air is drawn
in through the vacuum vents. Since this dilution upsets the
saturation equilibrium, more volatile hydrocarbons evaporate to
restore the equilibrium. This release of hydrocarbon vapors with
the diurnal changes in atmospheric temperature is referred to as
the tank's "breathing" cycle.
Working losses are associated with the filling and emptying
of a storage vessel. As a storage vessel is filled, the vapor
space is compressed, the pressure inside the tank increases, and
the pressure relief valve vents the air-hydrocarbon mixture to
the atmosphere. Conversely, as the tank is emptied, the vapor
space expands, creating a vacuum, and air rushes in through the
vacuum vents. Evaporation of volatile hydrocarbons restores the
saturation equilibrium.
Standing losses are associated only with a floating-roof
tank. These emissions result from the capillary flow of liquid
between the outer side of the sealing ring and the inner side of
the tank wall and subsequent evaporation. In addition to stand-
ing losses, other emissions from floating-roof tanks include
withdrawal Ipsses, losses from vents of a vapor recovery system,
and filling losses from a variable-vapor-space tank.
Withdrawal losses result from evaporation of stored liquid
that wets the tank wall as the roof descends during emptying
operations. These losses are small in comparison with other
types of losses.
Losses from a vapor recovery unit vent occur when inter-
mediate-volatility liquids are stored in a fixed-roof tank with a
vapor recovery system. (Subsection 4.19.3 fully discusses the
operation of a vapor recovery system.) The vapor recovery system
recovers the organic portion of tankage vapors and vents the air
portion back to the atmosphere. Because of inefficiencies in the
vapor recovery system, small quantities of volatile organics are
also vented with the air to the atmosphere. In many systems,
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-14
-------
however, the vapor stream is collected and burned with heavy ends
directly in a furnace. Such systems do not vent organic vapors
to the atmosphere.
Filling losses from a variable-vapor-space tank occur when
vapor is displaced by the liquid during filling operations.
Because the variable-vapor-space tank has expandable vapor stor-
age capacity, this loss is not as large as the filling loss
associated with fixed-roof tanks. Loss of vapor occurs only when
the vapor storage capacity of the tank is exceeded.
A pressure tank is generally a sealed, no-loss system.
Losses through relief vent openings can occur, however, when the
pressure inside the tank exceeds the design pressure. This
happens only when the tank is filled improperly or when abnormal
vapor expansion occurs. Losses can also occur during the filling
of low-pressure tanks that are not equipped with means for dis-
posing of excess displaced vapors. These losses do not occur
regularly, and the losses from pressure tanks storing volatile
liquids are not significant under normal operating conditions.
Storage of crude oil also generates liquid waste stream.
The residence time in the storage tank allows the settling out of
water containing dissolved salts. This is withdrawn from the
bottom of the vessel and sent to the wastewater facilities in the
refinery.
4.19.3 Emission Controls
Hydrocarbon emissions from fixed^roof, floating-roof, and
high-pressure storage tanks are controlled in several ways.
Breathing and working losses from fixed-roof storage tanks can be
controlled by the use of conservation vents. A conservation vent
is a pressure/vacuum relief valve that vents only when a set
pressure differential is exceeded. NSPS and RACT do not require
that emission control methods be applied to fixed-roof storage of
low-volatility liquids [less than 10.5 kPa (1.52 psia)]; there-
fore this discussion of emission control methods focuses on the
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-15
-------
control techniques applied to storage of intermediate-volatility
liquids.
Intermediate-volatility liquids can be stored in floating-
roof tanks, internal floating-roof tanks, variable-vapor-space
tanks with vapor recovery, or fixed-roof tanks with vapor recov-
ery. Although simple fixed-roof tanks have been used for storing
intermediate-volatility liquid in the past, NSPS and RACT do not
allow this practice.
In new construction for storage of intermediate-volatility
liquids, emissions can be controlled by selecting a form of
tankage with emission losses lower than those from fixed-cone-
roof tanks. Tanks with lower loss rates include floating-roof
tanks, internal floating covers, and variable-vapor-space tanks
equipped with vapor recovery systems.
A second approach to controlling losses from fixed-roof
storage of intermediate-volatility liquids involves retrofit
control technology, such as internal floating roofs and vapor
recovery systems. Internal floating roofs (Section 4.19.1,
Figure 4.19-5) can generally be installed inside existing fixed-
roof tanks of welded construction. Tanks of bolted construction
are difficult to retrofit.
Vapor recovery systems can also be installed on existing
fixed-cone-roof tanks. Figure 4.19-8 is a flow diagram of a
simplified vapor recovery system; the systems for tank farms,
terminals, etc., are more complex. Vapors generated in the
fixed-roof tank are displaced through a piping system to a stor-
age tank called a vapor saver. The vapor saver evens out surge
flows and saves a reserve of vapors to return to the storage tank
during in-breathing modes. In-breathing of saturated vapors in-
stead of air prevents the evaporation of additional volatile
organics. Several storage tanks can be connected by manifold to
a single vapor saver and vapor recovery system. Vapor recovery
systems usually are not as cost-effective as internal floating
roofs, particularly for tanks with high filling rates.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-16
-------
BLANKET
tt
STORED LIQUID
VENT
VAPOR PIPING
VAPOR
SAVER [
VAPOR RECOVERY
SYSTEM
Figure 4.19-8. Simplified vapor recovery system.
Petroleum Refinery Enforcement Manual
3/80 4.19-17
Crude and Product Storage
-------
Figure 4.19-9 illustrates a vapor recovery unit in more
detail. The recovered vapors are compressed, then flow to the
refinery fuel gas system or directly to a heater box. During
compression, the heavy ends are separated as liquids, which are
discharged to the heaters. A refinery has the option of recover-
ing the hydrocarbon vapors, provided that tanks storing the same
products are manifolded to one vapor recovery system. Figure
4.19-10 illustrates this option. After the recovered vapors are
compressed, the hydrocarbon gas is cooled. The resulting liquids
flow back to the storage tanks. The cooled vapors are introduced
into an absorption column, where the product (such as gasoline)
absorbs the hydrocarbons present in the vapor feed. The air
removed from the vapor feed is vented to the atmosphere through a
back pressure control valve. The product flows to a two-stage
flash separator, where dissolved air is removed from the product.
The product is returned to storage. The dissolved air removed in
the flash separator contains hydrocarbons and is piped to a flare
or fuel gas system.
Another means of emission control is use of pressure tank-
age. Low-pressure tanks operating between 117 and 200 kPa (17
and 29 psia) have been used for storage of motor gasolines,
pentanes, and natural gasolines having vapor pressures up to 200
kPa. With proper design, these low-pressure tanks can prevent
breathing losses from intermediate-volatility liquids. Working
losses occur during filling when the pressure of the vapor space
exceeds the pressure vent setting and vapors are expelled. These
losses, which depend on the pump-in rate, may be reduced by
increasing the vent setting; however, the higher cost of a high-
pressure tank to accommodate the higher setting may prohibit this
option. Vapor recovery systems may be needed to control working
losses.
High-pressure tanks represent the highest level of emission
control for storage of volatile liquids. There should be no need
for controls on high-pressure tankage. Any losses from high-
pressure tankage indicate that the tankage is misapplied or is
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-18
-------
00 rt
o n
O
M
n>
to
0)
HI
H-
0
CD
a
w
3
Hj
O
H
O
(D
(D
I 3
VO (1>
M
O
CONSERVATION
VALVE
/FLAME
\RRESTER
STORAGE TANK
OTHER
TANKS
NATURAL
GAS
DRY GAS
VALVES
SURGE
TANK
IXh
l>tp „ FUEL GAS
D
COMPRESSOR
Q.
(D
0)
Figure 4.19-9. Flow diagram of vapor recovery system.
h
o
o
ft
ft
o
I-!
(U
vQ
fD
-------
00 ft
OH
i-h
H-
(D
3
n
I
o
I
ts>
O
O
H
£
d
n>
O
ft
PRODUCT
VENT
COMPRESSOR
SURGE
TANK
ABSORBER
FLASH
SEPARATOR
CONSERVATION
VALVE
TO PRODUCT
STORAGE
COMPRESSOR
-• NATURAL GAS
-• OTHER TANKS
FLAME ARRESTER
TO FLARE
- OR FUEL
GAS SYSTEM
RECOVERED
HYDROCARBONS
TO
STORAGE
ft
O
H
(I)
vQ
(D
Figure 4.19-10. Vapor recovery system with absorption.
-------
not in working order. Good housekeeping and routine maintenance
are the primary controls available for these losses.
Hydrocarbon emissions can be further reduced by selection of
paint for the tank shell and roof; that is, the protective coat-
ing applied to the outside of the shell and roof influences the
vapor space and liquid temperatures. White or silver paint
greatly reduces the amount of heat absorbed. A cool roof and
shell also allows dissipation of heat retained in the stored
material. The condition of the paint also influences its effec-
tiveness in reducing emissions.
4.19.4 Instrumentation
Common measurements on storage tanks are liquid level, tem-
perature, and operating pressure. Where vapor recovery systems
are used, additional pressure readings are needed from the mani-
fold system and surge tank. Petroleum fractions and products are
stored below their normal boiling range, and tanks other than
pressurized vessels are operated at low positive pressures.
4.19.5 Startup/Shutdown/Malfunctions
Tank farm operations are normally smooth with very few
upsets. Filling and emptying rates are observed carefully be-
cause of the potential hazard from fire or explosion. In addi-
tion, filling rates are matched to the capacity of the vapor
recovery system to avoid excessive hydrocarbon emissions.
Periodic plant maintenance includes storage tank cleaning,
during which large amounts of hydrocarbons are released to the
atmosphere. The material in the tank is withdrawn while nitrogen
is introduced as an inert blanket to prevent explosive mixtures.
The nitrogen-hydrocarbon vapor mixture is then vented to the
atmosphere. The tank is usually cleaned chemically. Cleaning
operations can take from a few days to two weeks, depending upon
the accumulation of deposits in the tank. After the cleaning
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-21
-------
operations, the tank is again filled with nitrogen and the petro-
leum material is introduced. The nitrogen and evaporated hydro-
carbon mixture is again vented to the atmosphere. Periodically,
the seals are checked for cracking and are replaced as required.
4.19.6 References
1. Nelson, W. L. Petroleum Refinery Engineering. McGrawHill
Book Company, New York, 1958. pp. 271274.
2. U.S. Environmental Protection Agency. Compilation of Air
Pollutant Emission Factors. 3d ed. Supplement 8. AP42,
1978, p. 4.37.
Petroleum Refinery Enforcement Manual Crude and Product Storage
3/80 4.19-22
-------
HEATERS AND
BOILERS
-------
4.20 PROCESS HEATERS AND BOILERS1'2
Process heaters are used extensively in refinery operation
to heat and thermally crack fluids. When a process requires a
temperature above 204°C (400°F) or when hot streams are not
available for heat exchange, the refiner relies on process heat-
ers to supply the specific quantity of heat needed for the pro-
cess. These heaters are also called process furnaces, direct-
fired heaters, tube stills, or pipe stills.
A specific type of fired heater is the boiler whose function
is to produce steam. The steam is used in the refinery as a
heating medium, as a process fluid (hydrogen production and steam
stripping), or even to generate electricity.
A CO boiler is a specific type of boiler that is fueled with
waste gas.
4.20.1 Process Description
Process Heaters
Process heaters consist of two main sections: a radiant
section and a convection section.
In the radiant section, heat is transferred from the combus-
tion of fuel to the tubes containing the process fluid. In addi-
tion to this heat, the refractory walls become red hot at 540° to
1090°C (1000° to 2000°F) and emit heat, which is absorbed by the
tubes and transferred to the process streams within the tubes.
In the convection section, heat is exchanged between the hot
combustion gases and the convection tubes containing the process
fluid. Often additional tubes are added in this section of the
heater for superheating steam. The recovery of heat in this
section improves heater efficiency and reduces the temperature of
the flue gas exiting the stack.
Fuel is delivered to the furnace through the burners. The
function of the burner is to mix the fuel and air; maintain a
flame of proper shape, size, and stability; and ensure complete
combustion. The burners are normally mounted near the bottom of
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-1
-------
the heater but can also be side or end mounted. The heaters fire
a wide variety of fuels, both gaseous and liquid. Natural gas or
refinery gas is delivered to the burner at 120 to 240 kPa (3 to
20 psig). The fuel gas is mixed with air, and the mixture is
injected into the fire box (radiant section) of the furnace. Air
is drafted or forced through air registers into the fire box,
where combustion occurs. When heavy fuel oil (No. 6) is used for
firing the furnace, the oil must be atomized either by mechanical
means or by use of steam. In a steam-atomized burner, the steam
and oil are fed simultaneously into an oil gun at about 790 kPa
(100 psig). Steam and oil then form an emulsion-like mixture in
the oil gun, mix with air, and are injected into a fire box.
The flue gas leaves the furnace through the stack. The
stacks are designed to induce a draft (low-level vacuum) in the
fire box, so that the flue gases are discharged to the atmo-
sphere .
The size of a fired heater is defined in terms of its design
heat absorption capability or duty. The range is from 10.6 to
527.5 GJ/h (10 million to 500 million Btu/h).
There are many variations in the layout, design, and de-
tailed construction of fired heaters. A consequence of this
flexibility is that most fired heaters are custom-engineered for
a particular application.
Fired heaters can be classified into general service cate-
gories as follows:
Column reboilers—This is considered one of the least criti-
cal of heater applications, since differentials between the inlet
and outlet temperatures across the heater are relatively small.
Depending on the particular application, the outlet temperatures
of reboiler fluids range from 205° to 290°C (400° to 550°F).
Fractionating-column feed heaters—These are the workhorses
of many process operations. The charge stock is sent to the
process heater before it enters distillation equipment. A typi-
cal example of this service is a feed heater for an atmospheric
distillation column. Crude oil entering the heater as a liquid
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-2
-------
at 230°C (450°F) might exit near 370°C (700°F) with about 60 per-
cent of the charge stock vaporized. A typical small heater is
shown in Figure 4.20-1.
Reactor-feed preheaters—Process heaters in this application
raise the charge stock temperature to the level needed to main-
tain a chemical reaction in reactor vessels. The following
examples illustrate the diversity of applications of reactor-feed
preheaters:
Single-phase/multicomponent heating, such as the heating of
mixtures of vaporized hydrocarbons and recycle gas prior to
catalytic reforming. In this service the charge stock
enters the process heater at about 430°C (800°F) and exits
at approximately 540°C (1000°F).
Mixed-phase/multicomponent heating, such as the heating of
mixtures of liquid hydrocarbons and recycle hydrogen gas for
reaction in a hydrocracker. Fluid enters at approximately
370°C (700°F) and exits at approximately 455°C (850°F).
Heaters of heat-transfer media—A process heater in this
service is generally used to raise the temperature of a recircu-
lating heat-transfer medium, such as heating oil, Dowtherm, or
water. Fluids flowing through the heater in these systems almost
always remain in liquid phase from inlet to outlet.
Fired reactors—In heaters of this category a chemical
reaction occurs within the tube coil. As a class, these units
represent the heater industry's most sophisticated technology.
The following two applications typify the majority of fired
reactor installations.
Hydrocarbon reformer heaters - The tubes of the combustion
chamber function individually as vertical reaction vessels
filled with nickel-bearing catalyst. In reformers, the
fluid outlet temperatures range from 790° to 900°C (1450°F
to 1650°F).
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-3
-------
TO STACK
PETROLEUM STREAM
AIR PREHEAT
HEAT EXCHANGER
TUBES
PETROLEUM STREAM OUT
•a
o o o o
3 O O O O O
O O O O O
) O O O O O
o o o o
CD CD CD
BURNERS
FUEL GAS
OR OIL
Figure 4.20-1. Typical vertical refinery process heater.
Petroleum Refinery Enforcement Manual
3/80 4.20-4
Process Heaters & Boilers
-------
Pyrolysis heaters - Pyrolysis heaters are used to produce
olefins from gaseous feedstocks such as ethane and propane
and from liquid feedstocks such as naphtha and gas oil. In
cracking heaters, where chemical reactions occur in the
coil, the tubes and burners are arranged so as to assure
pinpoint firing control. Fluid outlet temperatures in
heaters designed for liquid feedstocks range from 815° to
900°C (1500° to 1650°F).
Fired heaters can also be grouped according to the methods
of combustion-air supply and flue gas removal. A flow of combus-
tion air into a fired heater can be induced when the buoyancy of
hot flue gases creates "draft" (less than atmospheric pressure).
Since this draft results from a natural stack effect, it is
termed natural draft. Most fired heater installations are the
natural-draft type, in which a stack effect introduces the com-
bustion air and removes the flue gas. It is the function of the
stack to generate sufficient draft to maintain a negative pres-
sure throughout the heater.
An induced-draft heater incorporates a fan, in lieu of a
stack, to maintain a positive pressure and to induce the flow of
combustion air and the removal of flue gas. A forced-draft-fired
heater is one wherein the combustion air is supplied under posi-
tive pressure by means of a fan. The flue gases are removed by
the stack effect and all parts of the fired heater are maintained
under negative pressure. A forced-draft/induced draft heater
uses a fan to supply combustion air and a fan to remove the flue
gas and maintain the heater under negative pressure. Most fired
heaters equipped with air preheaters are of the forced-draft/
induced-draft type.
Steam Boilers
A typical high-pressure/high-temperature boiler is shown in
Figure 4.20-2. Typical operating conditions are 10,443 kPa (1500
psig) and 540°C (1000°F). This boiler may be fired by either
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-5
-------
Figure 4.20-2. Typical high-pressure/high-temperature boiler.'
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-6
-------
natural gas or oil, which is ignited by burners. As a result of
combustion, heat is liberated. Transfer of this heat to water in
the furnace tubes produces steam. All the steam is generated in
the furnace, superheater, and economizer, but primarily in the
furnace tubes. The convection surface consists of a superheater,
economizer, and air heater.
In the superheater, heat is transferred from hot flue gases
to steam in the tubes. This superheated steam can be used in a
turbine for production of electricity.
In the economizer, the boiler feedwater is preheated. Hot
flue gases flow vertically across horizontal tubes containing the
boiler feedwater. Fins, projections, or extended surfaces may be
added to the tubes in the economizer to increase the heat trans-
fer area without affecting the flow of fluid. The fins on the
outside of the tubes run vertically so as to retain a minimum of
soot and fly ash from the flue gases. Soot blowers placed at
right angles to the water tubes blow either steam or air to keep
the tubes clean.
The air heater recovers heat from the exiting flue gases and
preheats the combustion air. It provides high combustion air
temperatures and reduces the temperature of the flue gas to the
minimum allowable stack temperature. The intent is to keep the
exiting flue gas temperature above the dew point of the products
of combustion.
In a boiler operating at subcritical pressure, the tempera-
ture of the flue gases leaving the steam-generating surfaces of
the boiler is determined essentially by the saturation of the
boiling water. The higher the steam pressure, the higher will be
this saturation temperature. Temperature of the flue gases must
be high enough, usually 370° to 540°C (700° to 1000°F), to permit
transfer of heat from the gases to the steam-generating surfaces.
If the flue gases were exhausted to the atmosphere at such high
temperatures, the boiler efficiency would be reduced significant-
ly. The feedwater on its way to the boiler at temperatures
substantially below saturation and the air on its way to the
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-7
-------
furnace absorb much of the heat from the flue gases, thus sub-
stantially improving the overall efficiency.
A CO boiler is essentially a gas-fired steam generating
boiler. Waste gases from the fluid catalytic cracking unit
and/or the fluid coker contain CO and other combustibles, mainly
hydrocarbons; these gases are mixed with supplemental fuel and
burned to utilize the heat from the combustion of CO and the
sensible heat from the other waste gases. A minimum furnace
temperature of 980°C (1800°F) is needed to maintain CO combustion
and ensure stable operations. The CO boiler is normally equipped
with a forced-draft fan. Capacities of CO boilers range from
22,700 kg/h (50,000 Ib/h) of steam to more than 227,000 kg/h
(500,000 Ib/h).
4.20.2 Emission Sources
Most emissions associated with process heaters and boilers
come from the fuels used for combustion. Particulates, sulfur
oxides, carbon monoxide, nitrogen oxides, hydrocarbons, and
aldehydes are potential emissions from the stack. Hydrocarbons
are emitted from leaking valves or flanges on the process fluid
side of a heater. Any sludge from treatment of boiler feedwater
constitutes a solid waste.
4.20.3 Emission Controls
Emissions of particulate, nitrogen oxides, and hydrocarbon
from process heaters are rarely if ever controlled, except by
proper design and operation of the heater to ensure complete
combustion. These heaters usually burn oil or natural gas, which
are fairly clean fuels. Therefore, with proper operation, no
control is required.
Emissions of sulfur dioxide are normally controlled by
burning low-sulfur distillate oils and natural gas. Since this
results in low sulfur dioxide emissions, post-combustion treat-
ment is rarely used to remove sulfur dioxide from the flue gases.
Sulfur compounds such as hydrogen sulfide and mercaptans can
be removed from fuel gas by amine scrubbing and from oil by
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-8
-------
hydrodesulfurization followed by amine scrubbing of the resulting
gas. Hydrogen sulfide is stripped from the amine solution and
converted to elemental sulfur in a Glaus process.
4.20.4 Instrumentation
Close monitoring of the key variables is very important for
optimum performance of a process heater or a steam boiler. The
important key variables are the amount of excess air and the flue
gas temperature.
Process heaters and boilers are normally operated with a
small amount of excess air (5 to 10 percent above the theoretical
minimum) to allow for small variations in fuel compositions and
flow rates. Control of excess air is achieved by the use of air
blowers and stack dampers. The quantity of excess air may be
monitored by observing the oxygen content of the stack gases,
either by analysis of samples drawn from the stack manually or
use of fixed instruments with continuous monitoring.
Measurement of flue gas temperature leaving the radiant
section serves as an index to the firing balance in the fire box.
Flue gas temperatures also provide an indication of overfiring
conditions and of heater efficiency.
4.20.5 Startup/Shutdown/Malfunctions
Startup of process heaters and boilers creates excessive
emissions because the heater efficiency is low until line out.
This inefficiency is caused either by too much excess air (which
causes consumption of extra fuel) or by too little excess air
(which causes incomplete combustion of the fuel). Line out is
usually accomplished within a few hours. When dual-fired units
are switched to oil, particulate emissions usually increase
because of carbon deposits on the atomizing tips of the burners;
these units may actually smoke until combustion air is adjusted
and/or the carbon deposits are burned off.
Malfunctions of process heaters and boilers include flame-
outs, hot tubes, and air leaks. Flameouts, caused by positive
pressure in the firebox, lead to an increase in hydrocarbon
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-9
-------
emissions and are dangerous because of the risk of explosion from
the buildup of uncombusted fuel. A hot tube is the result of
coking of the inside of a tube, which causes the tube to turn
cherry red. A hot tube could also be caused by metal failure due
to excess thermal stress. Hot tubes necessitate shutdown for
replacement of the worn tubes, which may take 2 days. Air leaks
into the heater give incorrect readings of the amount of excess
oxygen in the flue gas. Attempts to correct for the erroneous
reading could lead to incomplete combustion and an increase in
hydrocarbon emissions.
4.20.6 References
1. Berman, H. L. Fired Heaters, I. Chemical Engineering,
June 19, 1978. pp. 99-104.
2. Babcock and Wilcox. Steam: Its Generation and Use. 38th
ed., New York, 1972. p. 16-10.
Petroleum Refinery Enforcement Manual Process Heaters & Boilers
3/80 4.20-10
-------
WASTEWATER
TREATMENT
-------
4.21 WASTEWATER TREATMENT1'2
The major uses of water in petroleum refining are steam
generation and heat transfer. The volume of water coming into
direct contact with process streams is small when compared with
the volume used for indirect cooling and heat transfer. Almost
every major refining operation, however, produces a wastewater
stream containing various pollutants. The following streams are
waste sources: crude desalting, atmospheric distillation, pen-
tane deasphalting, deasphalted oil, hydrogen desulfurization,
asphalt blowing (partial oxidation), hydrocracking, fluid cataly-
tic cracking, hydrofluoric alkylation, sulfur recovery, cooling
towers, steam generation, and electric power generation. Waste-
water treatment methods remove pollutants so that the water may
be reused or discharged to a municipal sewer system or a water-
way.
Refinery wastewater typically contains oil, phenols, sul-
fides, ammonia, and dissolved and suspended solids. Some refin-
ery wastes contain other organic and inorganic chemicals, includ-
ing toxic chemicals. The treatment processes vary with the types
and concentrations of contaminants and with effluent quality
requirements. Figure 4.21-1 illustrates a typical wastewater
treatment system.
Wastewater treatment processes can be separated into five
general categories: inplant pretreatment, primary treatment,
intermediate treatment, secondary treatment, and tertiary treat-
ment. Inplant pretreatment processes are applied to individual
aqueous streams before those streams are combined with effluent
flowing to primary treatment facilities. For example, sour water
stripping in sulfur recovery can be considered pretreatment.
Primary treatment processes are usually designed for oil/
water separation and for removal of settleable solids from the
water. Primary treatment may be performed at the unit or at a
central wastewater treatment plant. Two widely used designs are
the American Petroleum Institute (API) separator and the corru-
gated plate interceptor (CPI) separator. Both processes utilize
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-1
-------
co hd
\n>
00 ft
O H
o
M
(D
s?
Hi
H-
D
(B
SOUR
iUUK r- -i
CONDENSATE [_SULFUR RECOVERY_J-
(-( HWftbt
M
H,
0
£j OILY WASTES
CD
3
CD
2 OILY WASTES
0) CONTAMINATED
0 WITH HS
£
(U
M
NONOILY
^ WASTES
3^4
CO
ft
CD
£
ft
CD
h
iHHIIAKI HHiltiT1 . . . .- — . _
PRECIPITATION RUNOFF~|
_ DEASPHALTING J
GRAVITY DI"?oVED B'OLO
"ATMOSPHERIC DISTILLATION" ~*" SEPARATION —• FLO?A?ION -* oxiw
GICAL
TION
DE ASPHALTED OIL HDS I 1
PARTIAL OXIDATION SQUR
HYDRUCKACKING "" WATER
FLUID CATALYTIC CRACKING STRIPPER
HF ALKYLATION
L_ _J
1
-»
SEDIMENTATION
RECYCLED '
SLUDGE
SLUDGE
r- *n ,„_ __
STEAM GENERATION \ ^, ,„,.
POWER GENERATION •" nf.,,rfB,Hr
PRECIPITATION RUNOFFj DEWATtRINb
1
SLUDGE
DISPOSAL
»
1
TERTIARY
TREATHENT
-
DISCHARGE
(D
Figure 4.21-1. Wastewater treatment flow diaaram.
n>
P
rt
-------
gravity separation techniques to remove oil, oily sludge, and
grit from incoming wastewater before further treatment. Sludge
generated from these and other processes is usually treated in a
solids dewatering process.
Intermediate treatment consists of an equilibrium holding
basin having several hours of retention time to allow leveling of
hydraulic and contaminant concentration surges. The basin mini-
mizes shock loading to the secondary treatment facility. Dis-
solved air flotation units are sometimes used to remove addition-
al suspended matter from the water before secondary treatment.
Secondary treatment processes utilize biological oxidation
to degrade soluble organic contaminants in wastewater. In the
biological processes, microorganisms and oxygen convert the solu-
ble organic and inorganic matter to carbon dioxide (C02), sulfur
dioxide (S02), nitrogen (N2), and water (H20), thereby reducing
the biological oxygen demand (BOD) of the wastewater. The con-
centration of biodegradable contaminant is measured by the BOD of
the wastewater. Several biological processes are in widespread
use. Oxidation ponds, usually associated with low BOD wastes,
depend completely on biological oxidation without mechanical
aerators. Aerated lagoons utilize mechanical mixing and aeration
to handle larger BOD loadings. The trickling filter process and
its variations handle relatively large BOD loadings. The acti-
vated sludge process and its variations treat wastewater with
high BOD loadings. Trickling filter and activated sludge pro-
cesses require a clarification step to remove biological sludge
from the effluent.
Tertiary treatment processes are not now widely used but may
be required as effluent quality regulations become more restric-
tive. Processes in limited use or in development include chlori-
nation, ion exchange, membrane separation, activated carbon
adsorption, and filtration.
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-3
-------
4.21.1 Process Description
Sour Water Stripping
Sour waters are produced in a refinery when steam is used as
a stripping medium in the various cracking processes. Hydrogen
sulfides (H2S), ammonia (NH3), and phenols distribute themselves
in the condensate between the water and hydrogen phases. The
concentrations of these pollutants in the water vary widely
depending on the type of crude and processing involved. The
purpose of treating sour water is to remove H2S and polysulfides
before the wastewater enters the refinery sewer.
Sour water strippers are designed to achieve 85 to 99 per-
cent removal of sulfides. Phenols and cyanide contaminants can
also be stripped depending upon the wastewater pH, temperature,
and partial pressure.* The stripper bottoms usually go to the
desalter, where phenols are extracted. Chemical oxygen demand
(COD) and BOD of the sour water are reduced by stripping out
oxidizable sulfur compounds and by phenol removal.
Heated sour water is stripped with steam or flue gas in a
single- or double-stage packed or tray column (Figures 4.21-2 and
4.21-3). If the wastewater contains NHo/ it is neutralized with
acid before steam stripping. The waste liquid passes down the
stripping column while the stripping gas passes upward. Stripped
H2S is recovered as sulfuric acid or sulfur or is burned in a
furnace. The bottoms have a concentration of sulfide low enough
to permit discharge into the wastewater system for secondary or
tertiary treatment. Refiners can incinerate the acid gases from
the stripper, thereby converting the hydrogen sulfide to sulfur
oxide and the ammonia to nitrogen and traces of nitrogen oxides.
An alternative is to send the acid gases to a dual-burner Glaus
*If acid is not required for sulfide stripping, NH3 will also be
stripped, the percentage varying with the stripping temperature
and pH. If acid is added to the wastewater, virtually none of
the NH3 will be removed.
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-4
-------
oo rt
o h
o
H-1
CD
n>
HI
H-
M
3
Hi
O
H.
O
(D
(D
ft)
$
en
ft
0)
rt
(D
SOUR WATER
FLASH
DRUM
VAPOR TO SULFUR PLANT i-
C
REFLUX AND
SURGE TANK
OR INCINERATOR
LOW-PRESSURE STEAM
WATER TO DESALTER OR
PROCESS WATER TREATMENT
\J
^SOUR WATER
* STRIPPER
tt>
I
-------
oo rt
OH
o
M
CD
CD
Hi
H-
0
fD
H
W
0
S1
l-i
O
CD
I
N)
0)
(U
CO
HYDROGEN SULFIDE PRODUCT
DEAERATED
RECYCLE
~>v CUNUE
K
H2S
NSATE
AMMOI
STRIP
STRIPPER
* 7
r>r .
>
I-' '
S
>
V^
~s
4 f-
( .ACCUMULATOR
\ r
RECYCLE TO
FEED
* 1
00 ^
y
DEGASSED SOUR WATER
FROM STORAGE TANK
JS
STRIPPER WATER TO FEED
AMMONIA
IFICATI
SECTION
AMMONIA
PRODUCT
rt
0)
H
hj
0)
(D
0
rt
Figure 4.21-3. Double-stage sour water stripper.
-------
plant where the hydrogen sulfide and ammonia are converted to
sulfur oxides and nitrogen oxides.
A second stripper is occasionally added in series for ammo-
nia removal (Figure 4.21-3). The use of two strippers allows for
the production of high purity sulfide and ammonia offgases, which
can be recovered and discarded more readily. Ammonia, if re-
covered in the aqueous or anhydrous form, can be sold as a by-
product of the stripping operation.
Gravity Separation
The oily wastes from the process unit or from the sour water
stripper are processed by gravity separators. Gravity separators
remove 60 to 99 percent of the free oil found in refinery waste-
waters. They are the most economical means of separating free
oils from water. A gravity separator does not separate substan-
ces in solution or break emulsions. Its effectiveness depends on
the wastewater feed temperature, the density and size of the oil
globules, and the amount of suspended matter. Obviously, the
greater the difference in specific gravities, the better will be
the separation of oil and water.
Typical gravity devices consist of chambers equipped with
influent and effluent distribution elements and with oil skimming
and sludge collection devices. Grit or settling chambers may be
used as preseparators. Given adequate residence time under calm
conditions, the solids settle to the bottom of the separator
while the oil floats to the surface. Skimmers or weirs collect
the oil and other materials. Pumps move the various components
to designated disposal or processing points. Gravity units often
use baffles or corrugated plates to minimize turbulence, increase
surface area, and achieve satisfactory throughput.
Continuous systems are usually fitted with weirs at the
outlets to permit uninterrupted removal of the free oil layer.
Drains allow clarified water and solid particles to be removed
from the bottom. Weir heights and slopes are usually adjustable
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-7
-------
to allow optimum performance for the type and amount of oil in
the stream.
Batch operations are advantageous for intermittent, low-flow
waste streams. Wastewater fills the collection tanks, the oil is
skimmed or decanted, and clean water and sediments are removed.
The API separators are the most widely used (Figure 4.21-4).
They are usually long, rectangular tanks divided into multiple
basins that maintain continuous laminar flow. Scrapers are often
used to move oil to the downstream end of the separator, where it
is collected in a slotted pipe or drum. The scrapers return
upstream along the bottom of the basins, carrying the solids to
collection troughs.
Another type of separator finding increasing use in refin-
eries is the parallel plate separator or corrugated plate inter-
ceptor (CPI) shown in Figure 4.21-5. The separator chamber is
subdivided by parallel plates set at 45 degree angles and less
than 15.24 cm (6 in.) apart. This placement increases the oil
collection area, thus decreasing the overall size of the unit.
As the water flows through the separator, the oil droplets coal-
esce on the underside of the plates and travel upwards for col-
lection. The CPI effluents contain less oil than the API efflu-
ents. The CPI can be used as a primary gravity separation device
or can follow an API separator.
Separator skimmings contain excess amounts of solids and
water and must be treated before reuse. Concentrations of 1
percent solids generally interfere with processing. The sludge
that settles in the separator may be pumped to an incinerator,
removed by tank truck for disposal, or processed further by
solids dewatering.
Dissolved Air Flotation
Dissolved air flotation is used by many refineries to treat
the effluent from the oil separator and oil emulsions. The
dissolved air flotation process consists of saturating a portion
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-8
-------
\fl>
oo rt
O H
O
M
fD
JO
fD
HI
H-
0
fD
W
3
Hi
O
H
O
I
to
M pj
I P
voC
0)
CO
rt
fD
rt
fD
Hi
fD
g
fD
TO WATER
DISPOSAL
SLOP OIL TANK
TO HATER DISPOSAL
TOP VIEW
REFINERY
WASTEWATER
BAFFLES
FLOATING DECKS
BAY 4
BAY 3
BAY 2
OUTLET GATE
Q
STRAW
BOX
I SKIMMING
| PIPE
OIL SUCTION
LINE
OIL/WATER
IN
SIDE VIEW
Figure 4.21-4. Top and side views of API separator.
-------
U) hcJ
\fl>
oo rt
Ohj
O
t-J
(D
H-
3
(D
hf
^
W
0
51
H
O
(D
fl)
ADJUSTABLE
OUTLET WEIR
OIL SKIMMER
I
OUTLET --{*
CONCRETE
ADJUSTABLE
INLET WEIR
I
INLET
-CONCRETE
PLATE ASSEMBLY CONSISTING
OF 24 OR 1R CORRUGATED
PARALLEL PLATES
CO
rt
(D
sr
Figure 4.21-5. Corrugated plate interceptor (CPI) separator.
(D
3
rt
-------
of the wastewater feed or recycled effluent with air. The waste-
water or recycled stream is held at 380 to 515 kPa (40 to 60
psig) pressure for 1 to 5 minutes in a retention tank and then
instantaneously released to the flotation chamber at atmospheric
pressure. The sudden reduction in pressure results in the forma-
tion of microscopic air bubbles that attach themselves to oil and
suspended particles.
Because of the entrained air, the oil and particulates have
greatly increased vertical rise rates of 15 to 30 cm/min (0.5 to
1.0 ft/min). They agglomerate, rise to the surface, and form a
froth layer. Specially designed flight scrapers or other skim-
ming devices continuously remove the froth.
The retention time in the flotation chamber is usually 10 to
30 minutes. The effectiveness of the dissolved air flotation
process depends on the attachment of bubbles to the suspended oil
and other particles. The attraction between the air bubble and
the particle depends on the particle surface and bubble size
distribution.
Chemical flocculating agents, such as salts of iron and
aluminum, with or without organic polyelectrolytes, are often
helpful in improving the effectiveness of the air flotation
process and in providing a high degree of clarification. (De-
tails on flocculation are given in the subsection on Coagulation-
Sedimentation. )
The froth skimmed from the flotation tank can be combined
with other sludges (such as those from a gravity separator) for
treatment and disposal. Clarified effluent from a flotation unit
generally receives further treatment in a biological unit such as
an activated sludge unit or a trickling filter. A discussion of
the activated sludge and trickling filter processes follow.
Trickling Filters
A trickling filter is an aerobic biological process that
greatly reduces the concentration of dissolved and finely sus-
pended organic matter in a wastewater stream. The trickling
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-11
-------
filter can be used either as the complete treatment system or as
a roughing filter. Most refiners use it as a roughing device to
reduce the loading on an activated sludge system.
The trickling filter has spray lines that rotate slowly over
a bed of stones 3 to 6 feet thick, continuously distributing the
polluted water (Figure 4.21-6). As the water trickles through
the bed, the biodegradable organic contaminants are consumed or
metabolized by a layer of biomass attached to the stones. A
fastmoving food chain is set in motion. Various forms of bateria
consume molecules of hydrocarbons. Protozoans consume the bac-
teria and reduce high-energy chemicals to a lower energy state.
Activated Sludge
Activated sludge processes are preferred to trickling fil-
ters for petroleum refinery wastewater treatment (Figure 4.21-7)
because a high rate and degree of organic stabilization is possi-
ble. Primary treated sewage is pumped to an aeration tank, where
it is mixed with air and activated sludge. The tank has a reten-
tion time ranging from 5 to 7 hours. Activated sludge metabol-
izes the biodegradable organics, thereby reducing the BOD of the
wastewater. The treated waters flow to a sedimentation tank,
where the sludge biomass settles out and is recycled to the
aerator. Some of the growing sludge mass must be removed or
"wasted" to maintain steady-state conditions.
The completely mixed, activated sludge (CMS) plant uses
large mechanical mixers to mix and aerate the influent wastewater
with the contents of the aeration basin. This contact stabiliza-
tion process is useful where the oxygen demand is in the suspend-
ed or colloidal form and where land costs are high or land is not
available.
The activated sludge process has some disadvantages. Because
of the amount of mechanical equipment involved, the operating and
maintenance costs are higher than those of other biological
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-12
-------
oo rt
o n
O
I--
tt>
50
H-
£3
tfl
3
H,
O
h
o
§
(D
to 3S
Tg
(U
en
ff
<
ft)
rt
(D
l-i
(D
(U
SPRINKLING HEADER
-STONE BED
OUTLET
INLET
Figure 4.21-6. Trickling filter.
(D
3
rt
-------
\(D
00 ft
Ot-i
O
I-1
CD
CD
l-h
H-
CD
3
M
O
0)
3
fD
fU
en
WASTEWATER
AIR
AERATION TANK'
SEDIMENTATION
TANK
PURIFIED WATER
••••••V
ACTIVATED SLUDGE
WASTE SLUDGE
rt
-------
systems. This process is more subject to upsets than either the
trickling filter, oxidation pond, or aerated lagoon.
Shock loadings have less impact on the trickling filter
process than on the activated sludge process. The high concen-
tration of material contained in a shock loading destroys more
organisms in the activated sludge unit than in the trickling
filter. Consequently, most refineries maintain a basin upstream
of the activated sludge unit to equilize the loadings.
Coagulation-Sedimentation
The activated sludge effluent water is further treated by
coagulation-sedimentation. In the coagulation-sedimentation
process, colloids are destabilized, aggregated, and bound to-
gether for ease of sedimentation and removal from the waste
stream. With sufficient addition of chemicals, this process
reduces the concentration of phosphate by over 95 percent.
Phosphorus is an algal nutrient.
Coagulation-sedimentation involves the formation of chemical
floes that absorb, entrap, or otherwise bring together suspended
matter. The chemicals commonly used are alum, A12(S04)3 * ISH^O;
copperas, FeS04 * 7H20; ferric sulfate, Fe(S04)3; ferric chlo-
ride, FeCl3; chlorinated copperas, a mixture of ferric sulfate
and chloride; and polyelectrolytes (polar, synthetic, water-
soluble, organic polymers of high molecular weight).
After the chemicals have been blended with the watewater,
the stream passes through flocculation tanks where the smaller
particles and colloids floe together into larger masses. The
larger particles settle out when the effluent reaches the sedi-
mentation or clarifier tanks.
Effective coagulation depends primarily on the wastewater
pH, as well as on the amount and nature of the coagulant used.
The success of sedimentation depends on sufficient retention time
to permit settling. Retention ranges from 20 to 45 minutes.
Flocculating agents can agglomerate oil as well as other
organic particles and suspended matter; however, capital and
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-15
-------
operating costs that are higher than for both CPI and API proc-
esses make coagulation-sedimentation less attractive for oil
removal.
Solids Dewatering
The sludge generated by gravity separation, dissolved air
flotation, biological oxidation, and sedimentation is treated in
solids dewatering.
Tertiary Treatment
Tertiary processes can further improve the quality of the
wastewater effluent by removing residual pollutants. In a petro-
leum refinery, tertiary treatment processes include oxidation
ponds and aerated lagoons. A discussion of these processes
follows.
The oxidation pond is practical where land is plentiful and
inexpensive and BOD loadings are relatively low. An oxidation
pond has a large surface area and a shallow depth, usually not
exceeding 1.8 m (6 ft). These ponds have long retention periods
that range from 11 to 110 days.
The shallow depth allows the oxidation pond to be operated
aerobically without mechanical aerators. Algae in the pond
produce oxygen through photosynthesis. This oxygen is then used
by the bacteria to oxidize the wastes. Because of the decreased
BOD loadings, little biological sludge is produced, and the pond
is fairly resistant to upsets caused by shock loadings. Some
refineries use ponds to polish the final effluent.
The aerated lagoons is smaller and deeper than an oxidation
pond. It is equipped with mechanical or diffused aeration units.
The addition of oxygen enables the aerated lagoon to have a
higher concentration of microbes than the oxidation pond.
The retention time in aerated lagoons is usually 3 to 10
days. If the biota concentration is low, aerated lagoons are
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-16
-------
operated without final clarification. When the biota concentra-
tion is high, additional treatment is necessary. Biota dis-
charged in the effluent, results in a high BOD and solids dis-
charge which pollutes the stream or river.
Tertiary treatment processes may also include chlorination,
ion exchange, membrane separation, activated carbon, and filtra-
tion.
Chlorination is the most commonly used process for chemical
treatment of water. Chlorine, calcium hypochlorite, and sodium
hypochlorite are used to chlorinate the effluent. Chlorine
compounds, injected into the effluent 15 to 30 minutes before
final discharge, can kill more than 99 percent of the harmful
bacteria. Chlorine is suspected, however, of reacting with
hydrocarbons to form polychlorinated biphenyls (PCB) and other
chlorinated hydrocarbons.
Ion exchange removes the inorganic ions and nutrients from
the wastewater. Three common nutrients removed are nitrates (90
percent), phosphates (70 percent), and ammonia (93 to 97 per-
cent). Zeolite resin is the main ion exchange medium used.
Tertiary membrane treatment processes use a semipermeable
membrane to concentrate the waste stream. Variations in driving
force across the membrane and degree of separation desired define
the specific membrane process. Examples of membrane processes
include electrodialysis, reverse osmosis, ultrafiltration, and
microfiltration. Particulates that can be removed from the
_3
wastewater range in diameter from 10 to 10 microns.
Activated carbon processes use granular activated carbon to
adsorb pollutants from wastewater. Adsorption is a function of
the molecular size and polarity of the adsorbed substance. Acti-
vated carbon preferentially adsorbs large nonpolar organic mole-
cules. The process has sometimes been adopted for removal of
specific compounds from waste streams. The activated carbon
units are usually preceded by a sand filtration process. Sand
filters remove suspended solids from the wastewater, and thus
prevent plugging of the carbon pores. From the sand filter the
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-17
-------
wastewater flows to a bank of carbon columns arranged in series
or parallel. As the water flows through the columns, pollutants
are adsorbed by the carbon, gradually filling the pore sites.
Portions of the carbon are removed to a regeneration furnace,
where the adsorbed substances are burned off. The regenerated
carbon is reused in the columns.
Filtering is another method of tertiary wastewater treat-
ment. Methods include slow and rapid sand filters, multimedia
filters, and moving-bed filters. As mentioned above, filtering
sometimes precedes carbon adsorption.
Slow sand filters consist of a layer of sand 15 to 38 cm (6
to 15 in.) thick that is placed over a layer of coarser material
of similar thickness. The filters give about 60 percent removal
of suspended solids and 40 percent removal of BOC at hydraulic
o
loading rates of 61 to 102 liters/h per m (1.5 to 2.5 gal/h per
2
ft ). Rapid sand filters are constructed much the same as slow
sand filters but are designed for loading in the range of 81 to
2 2
244 liters/mm per/m (2 to 6 gal/min per ft ). These loadings,
and the use of coagulants, give about 70 percent removal of
suspended solids and 80 percent removal of BOD.
Multimedia filters give "in-depth" filtration of wastewater.
In-depth filtration is the filtering of wastewater within the
sand filter, not just on the surface (as is obtained with slow or
rapid single-component sand filters). Multimedia filtration can
tolerate larger loadings of suspended solids than can single-
component sand filters, because the solids are dispersed through-
out the filtering media.
The moving-bed filter is a new method of sand filtration. A
sand filter is moved countercurrently to incoming wastewater by
means of a hydraulically activated diaphragm. The sand is clean-
ed in a wash tower and recycled back to the sand filter. Because
operation is continuous, it does not stop for backwashing (as a
conventional unit does).
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-18
-------
4.21.2 Emission Sources
Atmospheric emissions from oil/water treatment systems pri-
marily result from the evaporation of volatile organic compounds
(VOC). Uncovered API separators, corrugated plate interceptors,
dissolved air flotation units, and associated sumps and drains
contribute to VOC emissions. Separators with fixed roofs and
vapor spaces are also subject to VOC leaks at sampling and main-
tenance hatches and vents. Floating roof separators may also
leak around hatches and vents, as well as around the roof seal.
Other atmospheric emission sources include sour gas from the
sour water stripper, stack gas from the sludge combustion incin-
erator, and, if activated carbon treatment is used, the vent gas
from the carbon regenerating system.
Water pollutant discharge may include dissolved solids,
oils, sulfides, phenols, ammonia, and several trace elements.
4.21.3 Emission Controls
Floating roofs are the best method for controlling hydrocar-
bon emission from oil/water separation units. An alternative
control method is a fixed-roof cover with a vapor recovery system
or a gas-blanketed vapor space. Floating roofs are recommended
over fixed roofs, however, because they do not have a vapor space
in which explosive mixtures can form.
In a sour gas stripping unit, the primary emissions are the
sour gases (S02) that are removed from the effluent. The sour
gases are either sent to a sulfur recovery unit where elemental
sulfur is extracted and sold as a byproduct, or to an incinerator
where the sour gases are burned.
Particulates are the primary emissions from a sludge combus-
tion incinerator. The incinerator should be equipped with either
a scrubber, bag filters, or an electrostatic precipitator. The
type of emission control depends on the amount of sludge incin-
erated and its contents. Sludge charactertistics vary according
to the type of crude used. The ash from the incinerator is
usually suitable as landfill.
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-19
-------
The carbon regenerating incinerator is mainly a source of
carbon monoxide emissions, which can be controlled by after-
burners. The afterburner brings the carbon monoxide into reac-
tion with excess air and heat to yield carbon dioxide, which is
then discharged to the atmosphere.
4.21.4 Instrumentation
The refinery generally monitors phenolic compounds, sul-
fides, several organic compounds, ammonia, pH, total dissolved
solids, and trace elements. For hydrocarbon emissions, the
phenolic compounds and the test performed for specific organic
compounds are of prime importance for the inspector.
4.21.5 Startup/Shutdown/Malfunctions
No special problems arise during a well-planned startup of a
wastewater treatment facility; emissions do not increase appre-
ciably. Wastewater treatment units are usually shut down for
cleaning, which can result in emissions of foul odors, especially
in the sludge production and treatment units. Gases containing
sulfur usually emit the most noxious odors. During maintenance
and repairs, surge capacity should be available in the form of
auxiliary tanks or ponds for storage of untreated waste streams.
Untreated waters should not leave the plant site. Sufficient
surge capacity should also be available during periods of heavy
rains, or the rainwater and wastewater should be separated. Mal-
functions can result from insufficient surge capacity. Large
quantities of heavy metals (such as arsenic, cobalt, cyanide,
copper, and chromium), acids, bases, and organics (phenols) kill
the bacteria that treat the wastewater. As a result, contaminat-
ed water may be discharged from the wastewater treatment facil-
ity.
4.21.6 References
1. Barnhart, E> L. The Ability of Biological Systems To Assim-
ilate Oils. American Petroleum Institute Proceedings, 1970.
pp. 436-465.
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-20
-------
2. Guide To Selecting Equipment For Oil/Water Separation.
Pollution Equipment News, December 1978. pp. 65-66.
Petroleum Refinery Enforcement Manual Wastewater Treatment
3/80 4.21-21
-------
SLOWDOWN
SYSTEMS
-------
4.22 RELIEF AND SLOWDOWN SYSTEMS1
4.22.1 Process Description
Pressure relief and blowdown systems in a petroleum refinery
provide for the safe handling and disposal of liquids and vapors.
The pressure relief system is designed to prevent pressures in
equipment from reaching levels at which rupture or mechanical
failure may occur. It operates automatically, releasing material
held within the protected piece of equipment until the pressure
falls to safe limits. The blowdown system, on the other hand, is
usually manually operated. In an emergency it is used to remove
part or all of the contents of the protected piece of equipment.
It is also used for purging the equipment by removing and dis-
posing of most of the accumulated liquids and vapors before
normal shutdown for inspection or cleaning.
The process description is divided into a discussion of the
relief system, blowdown system, and handling of relief and blow-
down discharges.
Relief System
Almost all process equipment (regardless of size or service)
that contain fluids can be subjected to conditions that will
raise the pressure above normal design levels. Process equipment
requiring overpressure protection include tanks or pressure
vessels, furnace coils, heat exchangers, pumps, and others. Most
of these units involve flowing streams, the application or inter-
change of heat, or operations in which pressure changes occur
quickly.
Various conditions can raise pressure to exceed normal
levels, and not all of these conditions can be anticipated and
accommodated by design and operating practices. Operators may be
unable to control a rapid pressure rise in equipment during an
emergency. It is for this reason that pressure relief systems
are designed to operate automatically.
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-1
-------
Many types of pressure relieving devices are on the market,
including relief valves, safety valves, rupture or frangible
discs, and relief hatches. A discussion of each of these devices
follows. Of these, relief and safety valves are the most widely
used on the process equipment.
Relief valves—Relief valves begin releasing at a set pres-
sure, reaching their maximum discharge rate when the pressure has
risen to 110 or 125 percent of the set pressure. They are pri-
marily used for liquid service.
Relief valves may be springloaded, lever and weight, or
pilot operated. Conventional spring-loaded types (Figures 4.22-1
and 4.22-2) are the most extensively used. Force due to back
pressure at the valve outlet may be subtracted from or added to
the force applied to the seating disc by the spring. The vari-
able back pressure on the disc may cause wide variations in the
set pressure of conventional relief valves because under these
conditions the pressure is not controlled by the compression
spring alone. Springloaded relief valves are commonly used where
the valve discharges to the atmosphere through a short length of
pipe.
Figure 4.22-1 shows a nozzle-type, spring-loaded valve that
promotes streamline flow and, consequently, a higher flow co-
efficient. The result is maximum flow for a given size of open-
ing. Figure 4.22-2 shows a wing-guided, spring-loaded valve.
The valve stem and seat are guided by wings extending downward
from the valve disc. Lacking the nozzle, the wing-guided relief
valve is less efficient in streamlining the flow.
When the pressure against the disc of either the nozzle or
wing-guided relief valve reaches the set pressure, the valve
rises from its seat against the spring, thus permitting the flow
of material through the valve and outlet port. As the pressure
beneath the disc increases above the set pressure, the disc rises
further, until the maximum opening and discharge capacity of the
valve is reached. Maximum opening occurs at 110 percent of the
set pressure when discharging vapor and 125 percent of the set
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-2
-------
SPRING
DISK
NOZZLE
PROCESS SIDE
Figure 4.22-1
Nozzle-type, spring-loaded conventional
relief valve.
Petroleum Refinery Enforcement Manual
3/80 4.22-3
Relief & Blowdown Systems
-------
Figure 4.22-2. Wing-guided, spring-loaded conventional relief valve.
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-4
-------
pressure when relieving liquids. When the pressure falls below
that level, the valve gradually closes until the pressure reaches
the set pressure, arid the valve is again tightly closed.
Relief valves are used in vapor and liquid service. Relief
valves designed for use in liquid service are generally simpler
than valves for handling vapor (Figure 4.22-3), although in
principle of operation they are the same.
Safety valves—The characteristic of safety valves that
distinguishes them from relief valves is rapid opening to maximum
flow at low over pressures. A safety valve in vapor service is
usually fully opened at 103 percent of the set pressure. Instead
of gradually opening like a relief valve, the safety valve opens
with high initial flow and closes again sharply at approximately
96 percent of the set pressure. This difference between the set
pressure and the resetting pressure of a valve is known as its
blowdown. Figure 4.22-1 illustrates the components and assembly
used in the nozzle-type safety valve.
Figure 4.22-4 shows a balanced safety valve. The bellows
vent to the atmosphere so that the net force on the seating disc
due to back pressure is approximately zero. The back pressure is
extended on equal areas of the top and bottom of the disc; thus,
the effect of back pressure is cancelled and the set pressure is
controlled entirely by the compression in the spring that con-
trols the disc.
Rupture disc—The rupture disc, sometimes known as a frangi-
ble disc or safety head, is composed of a preformed diaphragm
that will rupture at a predetermined pressure level. The dia-
phragm or disc is held between two special flanges (Figure
4.22-5). The rupture disc is used where pressure must be quickly
reduced, such as in the protection of pressurized combustion
systems. When the pressure in the protected equipment reaches
the level at which the disc is designed to rupture, it gives way,
and the rate at which pressure is then reduced is limited more or
less by the size of the disc and relief piping.
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-5
-------
SPRING
BELLOWS
DISK
NOZZLE
PROCESS SIDE
Figure 4.22-3. Bellows-type balanced
pressure relief valve.
Petroleum Refinery Enforcement Manual
3/80 4.22-6
Relief & Slowdown Systems
-------
Figure 4.22-4. Relief valve for liquid service.
Petroleum Refinery Enforcement Manual Relief & Slowdown Systems
3/80 4.22-7
-------
RUPTURE
DISC
SPECIAL
FLANGES
PROTECTED
EQUIPMENT
DISCHARGE
PIPING
Figure 4.22-5. Typical rupture disc installation.
Petroleum Refinery Enforcement Manual Relief & Slowdown Systems
3/80 . 4.22-8
-------
Relief hatch—The relief hatch, explosion hatch, or explo-
sion door consists of a specially designed closure capable of
opening under relatively low differential pressure and releasing
large quantities of vapor. These devices are used to provide
pressure relief on tanks, combustion chambers, and vessels that
operate under relatively low pressure and where large quantities
of material must be released. The set pressure of the relief
hatch is usually determined by the weight of the closure itself.
This method of pressure setting prevents the firm resetting of
the valve; as a result, relief hatches are not suited for liquid
service.
Figure 4.22-6 shows typical relief hatches. The choice of a
specific hatch is determined by the situation where it will be
applied. Relief hatches are the most effective way to release
large quantities of vapors from low-pressure equipment.
Blowdown System
The blowdown system includes the relief valves, safety
valves, manual bypass valves, blowdown headers, knockout vessels,
and holding tanks. It releases quantities of vapor or liquid by
self-generating pressure from equipment for one or more of the
following purposes:
Reduction of pressure or control of unusual pressure surges,
as from a chemical reaction
Removal of system contents under emergency conditions
Purging of equipment preparatory to maintenance work
The blowdown system supplements but does not replace auto-
matic relief valves. Blowdown equipment is typically provided on
such vessels as fractionators or reactor tubes and on other
pieces of equipment. Proper blowdown equipment is of great
importance on process equipment, especially when volatile materi-
als are being handled under high pressure. The equipment and
vessels discharging to blowdown systems are usually segregated
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-9
-------
TOP VIEW
ANGLE
IRON
GUIDES
GASKET
CENTER GUIDE
SUPPORTS
PORTS
CENTER GUIDE
.HATCH
(SHOWN OPEN)
CUTAWAY, SIDE VIEW
a. GUIDED PRESSURE RELIEF HATCH
\,}
S r*
SIDE VIEW
FRONT VIEW
b. EXPLOSION DOOR
IOOD
PRESSURE
HATCH
WEIGHT
VACUUM
HATCH
TOP VIEW
CUTAWAY, SIDE VIEW
c. LEVER-AND-WEIGHT COMBINATION PRESSURE
AND VACUUM RELIEF HATCH
Figure 4.22-6. Typical relief devices for the handling of large volumes
of vapor, for use on low-pressure equipment where firm seating
is not required.
Petroleum Refinery Enforcement Manual Relief & Slowdown Systems
3/80 4.22-10
-------
according to their operating pressure for reasons of safety and
economy. For example, high-pressure blowdown systems serve units
with working pressure over 690 kPa (100 psig); low-pressure sy-
stems serve units with working pressure below 690 kPa (100 psig).
Butane and propane are usually discharged to a separate blowdown
drum, which is operated above atmospheric pressure to increase
the recovery of liquids.
The most widely used blowdown valve is the ordinary gate
valve, sometimes with minor modifications. The gate valve gives
a relatively free and unobstructed flow when open. Cocks, globe
valves, and diaphragm valves have also been used for blowdown
purposes.
Cocks are of some advantage in manual operation because they
open fully in a quarter of a turn. Globe valves are subject to
sticking, which restricts their utility for blowdown purposes.
Diaphragm valves do not possess the desirable flow characteris-
tics of the gate valve.
In many applications, blowdown equipment must be able to
operate under such emergency conditions as exposure to fire.
Several types of operating mechanisms (including long extension
stems, cable and drum arrangements, air motor drive, and electric
motor drive) may be provided to permit the valve to be operated
from a remote location.
Disposition of Relief and Blowdown Discharges
The materials discharged from relief and blowdown systems
are directed to one of the following: the atmosphere, a flare, a
blowdown stack or tank, a sewer, or lower pressure portions of
process systems. Table 4.22-1 summarizes standard practices for
disposition of relief discharges. Individual circumstances may
result in practices differing from those reported in the table.
Because of varying wind conditions, the flare is the best way to
disperse vapors to the atmosphere while preventing ground accumu-
lations throughout the refinery. The handling of discharges of
toxic materials presents a variety of special problems.
/
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-11
-------
U) *tf
\n>
oo rt
o n
O
H
(D
0>
Mi
H-
3
(D
h
Hi
O
H
O
(D
3
rt
•t*
• S
N> (U
to 3
TABLE 4.22-1. DISPOSITION OF PROCESS VAPORS FROM
RELIEF VALVES, BLOWDOWN VALVES, VENTS, AND DRAINS
Materials and conditions
PROCESS VAPORS
Flammable, nontoxic vapors from relief
valves and vents:
Lighter than air
Heavier than air and remaining vapors at
atmospheric conditions, accompanied by
steam as dispersant
Noncondensing, heavier than air
Vapors condensable at atmospheric con-
ditions, accompanied by steam dispersant
or above 300°FC
Vapors condensable at atmospheric con-
ditions, below 300°F
Flammable, toxic vapors from relief valves
Nonflammable, nontoxic vapors from relief
valves
Nonflammable, toxic vapors from relief
valves
Noncondensable
Condensable
Vapors from blowdown valves
Flammable, noncondensable
Flammable, condensable
Nonflammable, noncondensable, nontoxic
Nonflammable, noncondensable, toxic
Nonflammable, condensable, nontoxic
Nonflammable, condensable, toxic
Liquid and vapor mixtures (e.g.,
heater steamout)
Discharge
directly to
atmosphere
Xa
a
xa
a
Xa
Xd
X
j
xd
xa
Discharge
to flare
system
X
Xc
f '
Xf
p
xe
f
XT
Discharge to
blowdown
system
X
Xe
XP
Xe
Xe
Q
xe
xe
xe
p
xe
Return to
process
system
Discharge
to
sewer
H-
(D
Hi
W
H1
I
i
3
tn
ft
CD
3
en
-------
£ TABLE 4.22-1 (continued)
oo rt
o h
O
M
(D
Hi
H-
13
(D
Hi
O
H
O
(D
• 3
M ft)
NJ 3
i d
f_i £D
U) I-1
0)
M
H-
0)
Hi
w
M
i
en
K:
w
rt
CD
3
CO
Materials and conditions
PROCESS VAPORS (continued)
Gas, excess process
Flammable toxic or nontoxic
Nonflammable, toxic
Nonflammable, nontoxic
PROCESS LIQUIDS
Liquids9 from relief valves
Liquids from blowdown valves
Liquids from drains'-'
Process liquids
Water
Relief valve drains
STEAM AND MISCELLANEOUS
Excess or exhaust steam release
Boiler blowdown
Steam trap condensate
Reboiler steam condensate
Surface drains
Discharge
directly to
atmosphere
X
X
Discharge
to flare
system
Xf
Xf
Discharge to
blowdown
system
Xe
Xh
xe
X
Return to
process
system
X1
Discharge
to
sewer
\f
XK
k
xj
Xk
X
X
X
aWith relief valve discharge properly isolated from surrounding equipment. This generally requires at least
10 ft of elevation above the highest tower or building top within a 50-ft radius.
"Condensable" signifies that approximately 50 percent or more of the material is condensable at atmospheric
temperature and pressure.
GNo liquid present in the valve discharge.
Under some conditions, if accompanied automatically by steam dispersant, small quantities of noncondensable
toxic vapors can be vented to the atmosphere if sufficiently remote from people.
-------
gff TABLE 4.22-1 (continued)
o
n> ePossibly requires supplementary absorption or neutralization provisions for toxic materials.
a f
3 Preferable to pass vapors through a burning flare if decomposable by heat without information of toxic
£» products.
pl ^Materials liquid at atmospheric pressure and temperature.
ro Heat exchanger relief valves may discharge separately to a drum vented to the blowdown stack, by which
>< leakage of valves may be checked and oil kept out of plant sewers. Valves likely to discharge large
w amounts connect directly to blowdown systems.
3 1
HI Applies particularly to the discharges of hot oil pumps, which relieve back into the suction line. Relief
° valve discharges returned to system must enter zones of approximately same temperature. Opportunity should
g not be afforded for hot returned material to cause excessive vaporization in the zone to which returned nor
3 for material to be returned to zones where it will be heated or vaporized excessively by the temperature
3 therein.
f*' ••'Contemplates very small quantities, not withdrawn continuously (except water) from valves generally
tooT measuring 1 in. and smaller.
to 3 i,
^£ If toxic, corrosive, or otherwise dangerous, disposal in sewers may not be permissible. Liquids from
J^M sampling of liquefied petroleum gases should not be drawn to sewers.
CD
H-
Hi
O
a
Q
cn
^<
cn
rt
0>
cn
-------
Only certain vapors may be discharged from relief valves to
the atmosphere; in these cases, the discharge lines must be
elevated (Footnote a, Table 4.22-1). The relief valve may never
discharge near the air intakes of air compressors, since the
discharge could be drawn into the air intake stream and cause a
fire.
Figure 4.22-7 shows a system of handling liquids having a
high vapor pressure and containing gases such as propane. Enter-
ing liquids are segregated in the separation drum and the evolved
gases pass through the stack to be burned. The drum separates
out the liquids that do not vaporize at atmospheric pressure, and
these liquids are pumped to proper storage. Air is excluded from
the flare stack by continuously bleeding gas to the drum. A
pilot (flame) at the top of the stack provides a source of igni-
tion. Complete combustion and smokeless burning are obtained by
injecting the gas stream in the combustion zone of the flare,
thereby providing turbulence and the inspiration of air. Steam
injection reduces nitrogen oxide emissions by lowering the flame
temperature. The flare stack itself may vary in height from 100
to more than 200 feet, depending on location and proximity to
other equipment.
Blowdown systems discharge to a pressure storage tank. The
tank is maintained under pressure by means of a back-pressure
control valve on the vapor line leaving the tank. This control
valve regulates the vapor flow rate to the flare.
When condensable vapors and hot heavy oils are being dis-
charged, the materials enter the blowdown drum and are quenched
by water streams in the line, drum, and stack (Figure 4.22-8).
This system is essentially a contact condenser and cooler from
which the condensables and oil are sent to slop.
4.22.2 Emission Sources
Relief and blowdown systems are potential sources of emis-
sions of sulfur and hydrocarbons. Sulfur emissions are generated
by mercaptans and vapors containing hydrogen sulfide that are
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-15
-------
\0>
00 ft
on
o
0>
3
50
(D
Hi
H-
fl>
M
Hi
® MCIDMAI MALT PAr
h{ INUKrlAL MAK-t bAo .
O
(B
3
0)
rt
• 2
^j Qj
^O i*
^S INLETS FROM RELIEF VALVES
<*^ AND SLOWDOWN
. H-
ffl ^^ .
\v /-
2 (
^ LIQUID TO SLOP ^
o I
Q- i — urn*
Q S-i^Vi1*
§ 1 1
i
1
PURGE
GAS '
FT
SEPARATOR
i
X
>
OT SLOP PUMP DRAIN
rt
1
r
r
r
5
?
DRUM
A
L
FLARE
\flHIGH LEVEL
/{J ALARM
J-
•
Y
0 PILOT
I
\
*^
V\ — • P ft r
\^™ bno
ff \
DRAIN |
Figure 4.22-7. Flow diagram of a typical flare installation for safe disposition of
flammable vapors, including separator drum for collection of condensate.
-------
CO
\
oo
O
NJ
o
3 SLOWDOWN
£ STACK
Ml
H-
£ WATER QUENCH
§ SPRAYS
2. SLOWDOWN DRUM
PROVIDED WITH HEATING COILS WHEN
§? NECESSARY TO PREVENT FREEZING
» \ VAPORS ^n_
£, SLOWDOWN LINES \ ,. ~ ^
-^ \ LI^UlUo _
o> 1 \ -, — p _LJ^
1^ . WW \ 1 1 " M ._
S' ( '„ „ )
R1 OIL TO SLOP ^-T — . [] . [] /
! ^ _,, , Y " /
2 1 1 Y /
H^^
^
7
OISPERSANT STEAM
DISTRIBUTOR
^
STEAM
_ WATER
^ SLOP PUMP DRAIN 1
w ^ -WATER '
§•
3
-------
discharged to the atmosphere or flare. These sulfur compounds
are converted at the flare to sulfur oxides, which are emitted to
the atmosphere. The emission rate in a blowdown system is a
function of the amount of equipment manifolded into the system,
the frequency of equipment discharge, and the blowdown system
controls.
Relief and blowdown systems are sources of hydrocarbon
emissions when the discharges are vented to the atmosphere. Some
fugitive emissions are caused by leaking valves. These systems
are well maintained, however, so that they will provide an effi-
cient release of vapors in an emergency. Leaks are thus the
exception rather than the rule.
4.22.3 Emission Controls
Hydrocarbons emissions can be reduced effectively by flaring
the vapors. The relevant Control Technique Guideline recommends
that the vapors be discharged to a flare, refinery fuel system,
heater box, or vapor recovery unit until the vessel is at 35 kPa
o
(5 psig). After that point, the vapors can be discharged to the
atmosphere. The ability of refineries to vent to the atmosphere
at the recommended pressure cannot be determined without site-
specific data. The inspector should determine the blowdown
procedure used at each refinery and assess its compliance with
RACT.
Section 4.22.1 describes the use of flares for handling
relief and blowdown discharges, and the use of blowdown systems
and process units for controlling hydrocarbon emissions.
4.22.4 Instrumentation
Oxygen analyzers offer continuous monitoring of air leakage
from plant areas into the flare system. When the analyzer shows
zero to 0.3 percent oxygen by volume, the flare is operating
safely. Between 0.3 and 1.0 percent oxygen by volume, the re-
finery should institute a procedure to eliminate oxygen from the
system because an explosion could result.
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-18
-------
Anemotherm gas flowmeters are located at strategic points on
flare systems. These meters serve two purposes: they provide
continuous monitoring of gas flow in major laterals to verify
that adequate sweep gas is being maintained, and they measure the
magnitude of safety leaks and flare dumps. Pressure gauges are
also located in flare systems to detect potential plugging and
ensure safe operation.
The only indication that the blowdown and relief systems are
discharging emissions is to observe that the valves are open.
Escaping gas cannot be noticed by odor alone because pronounced
odors are usually found around process equipment. Visual indi-
cations of gas escape include the frosting of points of leakage
and the wavy appearance of the air due to the changed index of
refraction (as with the displaced airflows from an automobile
gasoline tank during filling, or the "heat waves" observed on
highways). When large quantities of liquids that are vaporous at
atmospheric pressure and temperature are released to the air, a
distinct, visible cloud may be formed by the condensation of
moisture and the droplets of unvaporized material remaining after
pressure release. A hydrocarbon detector is used to detect these
fugitive emissions.
4.22.5 Startup/Shutdown/Malfunctions
Relief and blowdown systems are used during shutdown or mal-
functions of process units.
The only malfunction that might occur in the relief and
blowout systems is a flameout at the flare. This malfunction is
very dangerous because it can result in an explosion. The flare
is relighted as soon as possible.
4.22.6 References
1. Armistead, G. Safety in Petroleum Refining and Related
Industries. 2d ed. John G. Simmonds & Co., New York, 1959.
pp. 196-235.
Petroleum Refinery Enforcement Manual Relief & Blowdown Systems
3/80 4.22-19
-------
2. U. S. Environmental Protection Agency. Office of Air Qua-
lity Planning and Standards. Control Technique Guideline
for Volatile Organic Vapors from Process Turnarounds. Decem-
ber 1978.
3. Carruthers, J. E., and J. L. McClure. Overview Survey of
Status of Refineries in the United States with RACT Require-
ments. Prepared for the U.S. Environmental Protection
Agency by PEDCo Environmental, Inc., under Contract No.
68-01-4147, Tasks 65 and 74. 1979.
Petroleum Refinery Enforcement Manual Relief & Slowdown Systems
3/80 4.22-20
-------
ENFORCEMENT
PROCEDURES
-------
SECTION 5
ENFORCEMENT PROCEDURES
Each petroleum refinery is designed, engineered, construct-
ed, and operated to process specific crude oils and produce
specific products. This results in each petroleum refinery being
unique in the complexity and number of processes employed. Since
there is no typical refinery, a standard procedure for conducting
the inspection does not exist. This section describes approaches
to conducting an inspection rather than describing a standard
procedure for the inspector to follow.
5.1 INTRODUCTION
This section describes the various levels of enforcement in-
spections and lists the process units and other emission sources
that are to be inspected on those levels.
A thorough search should be conducted of the file for the
refinery to be inspected to determine what process units are
there, to note compliance history and trends, and to collect
other pertinent data. The inspection checklists (which are given
in Appendixes J through M) should be filled out as much as possi-
ble from file data. The data can then be verified and additional
data collected during the inspection. The checklists are merely
a means of organizing data; they are not official forms.
The inspector should be as informed as possible before
entering the refinery, and one way to accomplish this is to
review the descriptions of the various refining processes (Sec-
tion 4). The inspector should review the subsections pertaining
to those units that will be inspected. Appendix B and Appendix C
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-1
-------
provide additional background on the chemical engineering princi-
ples applicable to petroleum refining. The more an inspector
knows about an industry he is inspecting, the better he will be
able to communicate with plant personnel and the better the
inspection will be. The inspector is cautioned not to appear to
possess more knowledge of a subject than he actually has; by
doing so, he may miss getting important information or discredit
himself if plant personnel detect an area of ignorance. An
honest, questioning approach is generally the most effective.
It is important that the inspector be assertive in order to
assess compliance. The inspector should guide the course of the
inspection and be persistent in getting and verifying important
data. For example, the inspector may have a list of process
units and their feed rates. Rather than accepting the word of
the plant personnel aiding in the inspection, the inspector
should ask to see production sheets or a logbook that will verify
these data. An inspector should be confident that correct data
are collected. This approach, although time consuming, is effec-
tive in uncovering additional compliance problems.
The following subsections describe three levels of inspec-
tion, which increase in degree of intensity and follow different
time schedules. The Level I inspection is aimed at obtaining
continuing compliance of a limited number of units. These units
are the most likely to cause emission problems. The purpose of a
Level II inspection is to obtain compliance with particulate,
sulfur oxide, nitrous oxide, and some hydrocarbon emission regu-
lations. In a Level II inspection more units are investigated
than on a Level I inspection. The Level III inspection is aimed
at obtaining strict compliance with hydrocarbon emission regula-
tions. The number of fugitive emission sources monitored on a
Level III inspection is much greater than the number monitored on
a Level II inspection. Level II and III inspections are similar
in the number of sources investigated for compliance with parti-
culate, sulfur oxide, and nitrous oxide emission regulations. In
the future, a fourth or very detailed inspection may be added.
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-2
-------
This manual does not rule out that possibility, which would
result from new state and Federal policies.
5.2 LEVEL I INSPECTION
It is recommended that a Level I inspection be performed
once every 2 to 4 months. The actual frequency depends on the
workload and manpower available at local, state and Federal
offices. The duration of the inspection depends on the size of
the refinery and the number of inspectors. A two-man inspection
team can investigate a 30,000 barrel per day refinery in 2 to 3
hours.
Note the overall condition of the refinery during this
inspection. Dust from the unpaved roads is a source of particu-
late emissions, and pools of oily water are a source of hydrocar-
bon emissions. Observe all heater and boiler stacks to monitor
opacity. When a heater or a boiler stack is out of compliance
with the state visible emission standard, complete the the visi-
ble emission observation form. (This form is illustrated here in
Figure 5-1.)
Review and investigate the following units:
Unit Pollutant
Fluid catalytic cracking Particulates; sulfur dioxide
Sulfur recovery Sulfur dioxide
The pollution control equipment that may be present at the
Fluid Catalytic Cracking (FCC) unit includes a CO boiler, an
electrostatic precipitator (ESP), and internal and external
cyclones. Note the type of control equipment that is used and
also note whether the CO boiler or ESP is bypassed during the
inspection. (A refinery that does not have a flare, bypasses the
CO boiler to the FCC sump stack.)
Sulfur dioxide emissions from a sulfur plant are continu-
ously monitored at incinerator stacks by recording the incinera-
tor temperature. The usual incinerator temperature is about
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-3
-------
SOURCE NAME
ADDRESS
VISIBLE EMISSION UDSEKVATIOH FORM
OBSERVER
DATE
Point of Emission
OBSERVATION
POINT
STACK: DISTANCE FROM
WIND-SPEED
HEIGHT
DIRECTION
SKY CONDITION:
COLOR OF EMISSION:
RELATIVE HUMIDITY:
BACKGROUND:
AMBIENT AIR TEMPERATURE:
CERTIFICATION DATE:
SUGARY OF AVERAGE OI'ACITY
Set
Number
„
Time
Start — End
Observer >-.
Sun<^. Hind — ^
Sou
c
Obse
•ce
i
•ver
V
Opacity
Sum Average
Plume I Stack
—
Remarks:
Evaluator's Signature:
0
1
2
3
4
5
6
7
8
9
10
II
12
n
14
15
16
17
18
19
20
21
22
23
24
25
2G
27
28
29
0
15
30
45
30
31
32
33
34
35
36
37
33
39
40
41
42
43
44
45
0
46
47
48
49
50
51
52
53
54
55
56
57
50
59
15
30
45
I have received a copy of these opacity
readings
Title: Date:
Figure 5-1. Visible Emission Observation form.
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-4
-------
1204°C (2200°F). This temperature increases, however, to about
1427°C (2600°F) when the acid gas feed bypasses the Claus and
tail gas unit and is routed directly to the incinerator, thus
increasing S02 emissions at the stack. The incinerator tempera-
ture is a good indicator of the amount of acid gas being bypass-
ed.
Completion of the Level I checklist is further discussed in
Section 5.7.
5.3 LEVEL II INSPECTION
It is recommended that a Level II inspection be performed
once every 6 to 9 months. The actual frequency depends on the
workload and manpower available at the agency. The duration of
the inspection depends on the size of the refinery and the number
of inspectors. It takes a two-man team 1 to 2 days to inspect a
30,000 barrel per day integrated refinery. Before the inspec-
tion, obtain the data listed below for the units being inspected;
during the inspection, review the data with refinery personnel.
Process flow diagram
Process information
Heater and boiler data (type of fuel, heater duty, exit
temperature, and stack data)
Storage tank data
Wastewater separator data (type of separator, type of cover,
condition of cover)
Some fugitive emissions are monitored by a hydrocarbon detector,
in addition to the monitoring of particulates and SO,, emissions.
Review and investigate the following units:
Unit Pollutant
Fluid catalytic cracking Hydrocarbon vapors; particu-
lates; sulfur dioxide
Sulfur recovery Sulfur dioxide
Watewater treatment Hydrocarbon vapors
(continued)
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-5
-------
Unit Pollutant
Isomerization Hydrocarbon vapors, particu-
lates
Alkylation Hydrocarbon vapors, particu-
lates
Storage Hydrocarbon vapors
Loading Hydrocarbon vapors
Light-ends/gas processing Hydrocarbon vapors
The survey of oil refineries by the California Air Resources
Board in April 1978 showed that isomerization, alkylation, stor-
age, loading, light ends/gas processing, and FCC units accounted
for about 40 percent of the fugitive hydrocarbon emissions. The
CARB study also identified the items that contributed most to
fugitive emissions: valves, pump seals, and compressor seals.
For each process unit listed, use a hydrocarbon detector to in-
spect a certain number of the key emission contributors (Table
5-1). A screening procedure for monitoring fugitive emissions is
provided in Appendix H. Appendix G contains operating instruc-
tions for a Century Organic Vapor Analyzer, hydrocarbon detector.
5.4 LEVEL III INSPECTION
It is recommended that a Level III inspection be performed
once every 12 to 18 months. The frequency and duration depends
on the workload and manpower available at the agency. The dura-
tion of the inspection depends on the size and complexity of the
refinery. It takes a four-man team about one week to inspect a
30,000 barrel per day integrated refinery. It is a very detailed
inspection of the following units:
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-6
-------
TABLE 5-1. LEVEL II LEAK DETECTION PROGRAM
Process unit
Isomerization
Alkylation
Storage
Loading
Gas processing
FCC
Valves (in gas service)
Sample
size
20
20
20
20
20
8
Accept
No.*
5
5
5
5
5
2
Pump seals
Sample
size
5
8
8
8
5
Accept
No.*
1
2
2
2
„ 1
Compressor seals
Sample
size
2
2
2
Accept
No.*
1
1
1
*The accept number is the maximum number of leaks detected in the sample size
that results in statistically approving the sample. This number is based on
varying quality levels and statistics. Appendix E explains the derivation of
these numbers.
Petroleum Refinery Enforcement Manual
3/80 5-7
Enforcement Procedures
-------
Unit
Pollutant
Fluid catalytic cracking
Sulfur recovery
Wastewater treatment
Distillation: Vacuum
Distillation: Atmospheric
Isomerization
Alkylation
Storage
Loading
Light-ends/gas processing
Hydrocracking
Reforming
Visbreaking
Hydrotreating (Hydrodesul-
furization, or HDS)
Hydrocarbon vapors; particu-
lates, sulfur dioxide
Sulfur dioxide
Hydrocarbon vapors
Hydrocarbon vapors; particu-
lates
Hydrocarbon
lates
Hydrocarbon
lates
Hydrocarbon
lates
Hydrocarbon
Hydrocarbon
Hydrocarbon
Hydrocarbon
lates
Hydrocarbon
lates
Hydrocarbon
Hydrocarbon
particu-
particu-
particu-
vapors;
vapors;
vapors;
yapors
vapors
vapors
vapors; particu-
vapors; particu-
vapors
vapors
Again, the CARB study determined that the process units listed
above comprise about 52 percent of the fugitive hydrocarbon
emissions. For each process unit listed, use a hydrocarbon
sniffer to inspect a certain number of the key emission contri-
butors (Table 5-2). The operating instructions for using a
Century Organic Vapor Analyzer to monitor fugitive emissions is
provided in Appendix G. Appendix H contains a screening proced-
ure for monitoring fugitive emissions.
5.5 INSPECTION SCHEDULE
Table 5-3 shows a proposed schedule of inspections by level
for an individual refinery; it can be used as a guideline for
planning an inspection program. The inspector may decide to
Petroleum Refinery Enforcement Manual
3/80 5-8
Enforcement Procedures
-------
TABLE 5-2 LEVEL III LEAK DETECTION PROGRAM
Process unit
Isomerization
Alkylation
Storage
Loading
Gas Processing
FCC
Visbreaking
Hydrotreating*
(HDS)
Hydrocracking
Reformer
Distillation:
Atmospheric
Distillation:
Vacuum
Valves (in c
Sample
size
20
50
50
50
50
20
20
20
20
20
20
20
as service)
Accept
No.
2
5
5
5
5
2
2
2
2
2
2
2
Pump seals
Sample
size
8
20
20
20
8
8
8
8
8
8
8
Accept
No.
1
2
2
2
1
1
1
1
1
1
1
Compressor seals
Sample
size
3
3
3
3
3
3
3
Accept
No.
0
0
0
0
0
0
0
*A refinery has hydrotreating units for several feedstreams, some of which are
listed below:
HDS--reformer feed
HDS--light gas oil
HDS--heavy gas oil
Vacuum--(Residue) gas oil
Coker~-Naphtha
Petroleum Refinery Enforcement Manual
3/80 5-9
Enforcement Procedures
-------
TABLE 5-3 EXAMPLE OF AN INSPECTION SCHEDULE FOR AN INDIVIDUAL REFINERY
Month
February
April
June
July
September
November
Inspection level
Level I
Level II
Level I
Level III
Level I
Level II
Petroleum Refinery Enforcement Manual
3/80 5-10
Enforcement Procedures
-------
perform a higher level of inspection on the basis of recurring
violations or specific problems. For example, an inspector may
notice a problem with the FCC unit while conducting a Level I
inspection. The inspector identifies the problem by obtaining
additional Level III information, then proceeds with the Level I
inspection of the other units.
5.6 INSPECTION REPORT FORM
Complete an Inspection Report form, as shown Figure 5-2, on
a separate sheet. This form is used as a cover page for each
inspection report. Attach to the sheet the completed unit check-
lists. The cover sheet, the completed checklists, and any perti-
nent notes, comments, or records constitute your complete inspec-
tion report. The local, state, or federal policies may dictate
the information on these proposed checklists be transferred to a
designated form.
5.7 COMPLETION OF LEVEL I CHECKLIST
A blank checklist of a Level I inspection is shown in Figure
5-3. A copy is also provided in Appendix J. Sample checklists
have been completed to show the result before and after the
inspection.
From a file search prior to the inspection, the inspector
knows the number and type of cracking and sulfur units in the
refinery. A hypothetical refinery has one fluid catalytic crack-
ing unit with a refinery identification of 212, as shown in
Figure 5-4. The types of control, as found during the inspection
and shown in Figure 5-5, are one ESP, six internal cyclones in
the reactor, six internal cyclones in the regenerator, and a CO
boiler. The opacity of the FCC sump stack is also recorded in
the checklist at this time. The control equipment that is not
operating at the time of the inspection should be listed in the
checklist.
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-11
-------
LEVEL _ INSPECTION
AQCR Date(s) of Inspection
Time In Out
Company Name
Mailing Address
Location of Facility
(Include County or Parish)
Type of Industry
Form of Ownership
Corporate Address
Company Personnel Name Title Phone
Responsible for
Facility
Responsible for
Environmental
Matters
Company Personnel
Contacted
Confidentiality
Statement given to
EPA Personnel
State or Local
Agency Personnel
Figure 5-2. Inspection report form.
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-12
-------
]. Heater and Boiler Information
Identi fication
Number
Heater description
including unit location Opacity Comments
11. Catalytic Cracker
Identification Type of
Number or Name Process
Pollution Control FCC Sump
Equipment Stack
CO ESP Cyclones Opacity CommenU
Boiler
III. Sulfur Plant
Identification
Number or Name
Pollution Control
Equipment
Incinerator
Temperature
Incinerator
Stack
Opacity Comments
IV. General Comments
(Note the general housekeeping practices of the refinery.)
Figure 5-3. Level I inspection checklist.
Petroleum Refinery Enforcement Manual
3/80 5-13
Enforcement Procedures
-------
I. Heater and Boiler Information
Identification
Number
H-l
H-2
H-3
H-4
H-5
B-l
B-2
Heater description
including unit location
Crude unit
Crude unit
FCC
Reformer
Reformer
Steam Generation
Steam Generation
Opacity Comments
11. Catalytic Cracker
Identification Type of
Number or Name Process
Pollution Control FCC Sump
Equipment Stack
CO ESP Cyclones Opacity
Boiler
FCC 212
Fluid
III. Sulfur Plant
Identification Pollution Control Incinerator Incinerator
Number or Name Equipment Temperature Stack
(°F) Opacity Comments
SP 300
IV. General Comments
(Note the general housekeeping practices of the refinery.)
Figure 5-4. Example Level I inspection checklist
after file research.
Petroleum Refinery Enforcement Manual
3/80 5-14
Enforcement Procedures
-------
I. Heater and Boiler Information
Identification
Number
H-l
H-2
H-3
H-4
H-5
B-l
B-2
Heater description
including unit location Opacity
Crude unit 0
Crude unit
FCC 10
Reformer 0
Reformer 0
Steam Generation 0
Steam Generation 0
Comments
Not operating-
II. Catalytic Cracker
Identification Type of
Number or Name Process
FCC 212
III. Sulfur Plant
Fluid
Pollution Control FCC Sump
Equipment Stack
Cyclones Opacity
6 cyclones regenerator 0
6 cyclones reactor
Identification Pollution Control Incinerator Incinerator
Number or Name Equipment Temperature Stack
(°F) Opacity Comments
(X)
SP 300
IV. General Comments
Roads were not paved.
Claus unit
2200°F
10
Figure 5-5. Example Level I inspection checklist
after inspection.
Petroleum Refinery Enforcement Manual
3/80 5-15
Enforcement Procedures
-------
The Level I data needed for the checklist for a sulfur plant
includes the unit number or name, the control equipment, the
incinerator temperature (°F), and the incinerator stack opacity.
At the time of the inspection, the inspector should ask plant
personnel about the type of control equipment, temperature, and
stack opacity.
Heater and boiler description and unit location can usually
be obtained in the state files prior to an inspection. At the
time of the inspection, the inspector should verify the heater
and boiler information and record the opacity of the stacks. In
the hypothetical refinery, one of the heaters was not operating
during the inspection. This should be noted on the checklist (as
shown in Figure 5-5).
5.8 COMPLETION OF LEVEL II CHECKLIST
A Level II checklist includes a more detailed description of
each process unit, storage tank data, and wastewater treatment
facilities, in addition to heater and boiler information. Blank
and completed checklists are presented in Appendixes K and L.
Prior to the inspection, an inspector may be able to search
files for descriptions of process units, storage tanks, and
loading facilities. During the inspection, the inspectors should
observe each of the process units to verify the process descrip-
tions obtained in the file search. All heaters and boilers
should also be observed to record opacity. The data on storage
tanks should be verified. Appendix D contains the vapor pressure
of common petrochemical compounds found in petroleum refineries.
This information is useful in completing the "Storage Tank Data"
sheet of the checklist. While inspecting the wastewater treat-
ment facility, the inspector should note on the checklist any
odors and whether the separator is adequately covered.
The second part of the inspection includes the screening of
selected units with a hydrocarbon detector. The data are record-
ed on a leak detection survey log (appearing as blank forms in
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-16
-------
Appendix K and as a completed form in Appendix L). All the
information on the form must be completed while at the refinery.
5.9 COMPLETION OF LEVEL III CHECKLIST
The completion of the Level III checklist provides a very
detailed description of the refinery. This checklist includes
all the information from the Level II checklist plus a screening
survey of 10 units in the refinery and additional process data.
The checklist and leak detection survey log are completed in
the same manner as the Level II checklist shown in Appendix L. A
blank checklist for a Level III checklist is presented in Appen-
dix M.
Petroleum Refinery Enforcement Manual Enforcement Procedures
3/80 5-17
-------
TRENDS
-------
SECTION 6
TRENDS IN INSPECTION DATA
In addition to preparing for the inspection by reviewing the
files and the Petroleum Refinery Enforcement Manual, the inspec-
tor should be informed of the trends in refinery growth and in
emissions from the various units. An easy way to correlate
important inspection data is to present them in a table or graph.
An example is shown in Figure 6-1.
Two items of comparative data that should be noted are the
type of crude oil and its sulfur content. As more high-sulfur
crude is used, SO emissions will increase and additional sulfur
X
plants and sour gas treating units will be built.
Another trend to note is the process throughput of a unit.
If throughput increases significantly when compared with a previ-
ous visit, the inspector should note the opacity reading of the
heater stack at the unit. Heater duty increases with process
throughput, producing higher opacity reading at that heater
stack.
The summation of all the heater duties recorded during each
inspection should be noted for future reference. This informa-
tion is helpful in defining one of the reasons for increased
visible emissions.
Violations, such as a high opacity reading, should also be
included in the trend table. The table will provide a brief
summary check of compliance.
If the refinery has a sulfur plant, the inspector should
record the incinerator temperature of the plant on the trend
table. Incinerator temperature is a good indicator of the amount
of acid gas bypassed and the reasons for changes in S02 emis-
sions.
Petroleum Refinery Enforcement Manual Trends
3/80 6-1
-------
Table 6-2 illustrates the trends observed at a petroleum
refinery. This table shows that the crude being processed at
this 100,000 barrel per day refinery has a higher sulfur content
in 1979 and 1980 than that processed in 1977 and 1978. The total
heat input has increased by 20 percent over four years. This in-
creased heat requirement could be the result of the refinery
meeting the increased demand for gasoline. Accompanying this in-
crease in heater duties is an increase in the number of opacity
violations occurring at this refinery.
The feedrate to the crude unit, fluid catalytic cracking
unit (FCCU), and reforming unit increased over the four years.
Accompanying this increased rate was an increase in the opacity
observed at the FCCU.
The increase in the sulfur plant incinerator temperature
indicates that the refinery is having difficulty processing the
higher sulfur crudes (i.e. more hydrogen sulfide is not being
converted). Therefore, more sulfur oxides are being emitted to
the atmosphere.
Petroleum Refinery Enforcement Manual Trends
3/80 6-2
-------
TABLE 6-1. EXAMPLE TREND TABLE.
TREND TABLE
Crude oil :
Type
Sulfur, %
ZHeater
duties
Opacity
violations
Process
throughput
(list
applicable
processes)
Process
opacity
Sulfur
plant
incinerator
temperature
Year of inspection
1977
1978
1979
1980
1981
Petroleum Refinery Enforcement Manual
3/80 6-3
Trends
-------
TABLE 6-2. SUMMARY OF TRENDS OBSERVED AT REFINERY A.
Crude oil:
Type
Sulfur, %
IHeater
duties
Opacity
violations
Process
throughput
crude unit
FCCU3
reformer
Process
opacity
Sulfur
plant
incinerator
temperature
Year of Inspection
1977
Foreign
2.0
320 MM Btu1
1
98,000*
50,000*
30,000*
FCCU3
15
2150°F
1978
Foreign
2.0
330 MM Btu1
1
100,000*
50,0002
30,000*
FCCU3
15
2200°F
1979
Foreign
2.5
370 MM Btu1
2
102,000*
51,000*
30,000*
FCCU3
20
2300°F
1980
Foreign
2.5
385 MM Btu1
2
105,000*
52.0002
32,000*
FCCU3
20
2300°F
1981
Btu = million Btu.
*Expressed in barrels per day.
3FCCU = Fluid Catalytic Cracking Unit.
Petroleum Refinery Enforcement Manual
3/80 6-4
Trends
-------
APPENDICES
-------
APPENDIX A
The following tables list operating refineries located in
the United States as of January 1, 1979. The designations of
refineries in attainment or nonattainment areas for oxidants are
based on EPA designations as published in the Federal Register
and conversations with EPA regional personnel. Supplemental
information has been included to explain additions to and emis-
sions from the tables.
The data in this appendix were taken from a PEDCo report
entitled "Overview Survey of Status of Refineries in the U.S.
with RACT Requirements," which was prepared for the U.S. EPA
Division of Stationary Souce Enforcement under Contract
No. 68-01-4147, Task Nos. 65 and 74.
Petroleum Refinery Enforcement Manual Appendix A
3/80 A-l
-------
U) 13
\ fl>
00 ft
O I-!
O
M
(D
(D
Hi
H-
3
CD
H
Hi
O
H
O
fD
I
to
TABLE A-l. OPERATING PETROLEUM REFINERIES IN THE UNITED STATES'
EPA
region
I
II
III
IV
V
VI
VII
VIII
IX
X
Totals
Total
refineries
1
11
16
21
40
108
13
34
46
12
302
Total capacity,
bbl/day
13,400
1,790,820
1,028,660
699,800
Refineries in
attainment
areas
0
4
3
14
2,841,398 10
7,541,560
571,339
642,898
2,537,420
477,500
18,144,795
54
11
25
5
7
133
Refineries in
nonattainment
areas
- 1
7
13
7
30
54
2
9
41
.5
169
The data presented in the tables of Appendix A were compiled
in January 1979. Possible changes in number and status of
refineries since that time are indicated in Supplemental
Information, pp. A-80 through A-84.
(D
H-
X
-------
OJ t)
\(D
00 ft
O H
O
M
CD
(D
Hi
H-
3
(D
M
3
HI
O
H
O
(D
3
rt
TABLE A-2. BREAKDOWN OF OPERATING REFINERIES IN REGION I.
Connecticut
Maine
.Massachusetts
New Hampshire
Rhode Island
Vermont
Totals
Total
refineries
0
0
0
1
0
0 ,
1
Total capacity,
bbl/day
0
0
0
13,400
0
0
13,400
Refineries in
attainment
areas
0
o
0
0
0
0
0
Refineries, in
nonattainment
areas
0
0
0
1
0 .
0
1
13
H-
X
-------
00 ft
oh
O.
H
(D
50
^REGION: I
H-STATE:. Connecticut
TABLE A-3. BREAKDOWN OF OPERATING REFINERIES IN CONNECTICUT
g — =====
n
MName and address of refinery
Mi
O None
h
O
(D
ft
^ *«?
P)
^p
I-1
T3
t)
(D
P-
tl' Totals 0
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
-------
U> "XI
\(D
00 ft
O K
o
M
(D
TABLE A-4. BREAKDOWN OF OPERATING REFINERIES IN MAINE
Hi
£• REGION: I
fp STATE: Maine
3 Name and address of refinery
HI
0
£ None
fl>
rt
ui 3
d
0)
H
(D.
H-
* Totals 0 .
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0 -
-------
OJ IX)
\ n>
00 ft
O h(
o
M
(D
TABLE A-5. BREAKDOWN OF OPERATING REFINERIES IN MASSACHUSETTS
£. (REGION: I
[j1 STATE: Massachusetts
Name and address of refinery
tn
hh None
O
0
(D
3
(D
3
H
'O
(D
£1 Totals 0
County
.--;
AQCR No.
i
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
> . '
-------
oo rt
^^ ^
o .
(D
TABLE A-6. BREAKDOWN OF OPERATING REFINERIES IN NEW HAMPSHIRE
2> 'REGION: I
p- STATE: New Hampshire
§=
1 3
M
ro
pi Totals 1
County
Rockingham
AQCR No.
121
Capacity
bbl/day
13,400
13,400
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
1
-------
\ CD
oo rf
o i-!
O
M
(D
C
fD
Hi
H-
3
(D
td
13
Hi
O
K
O
fD
il
e
fa
(D
H-
X
TABLE A-7. BREAKDOWN OF OPERATING REFINERIES IN RHODE ISLAND
REGION: I
STATE: Rhode Island
Name and address of refinery
None
Totals 0
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
-------
OJ
00 ft
o i-i
O
I-1
(D
hh
H-
3
0)
hi
M
3
Hi
O
H
O
(D
3
ft
>S
I p»
vo3
C
p,
13
13
(D
TABLE A-8. BREAKDOWN OF OPERATING REFINERIES IN VERMONT
REGION: I
STATE: Vermont
Name and address of refinery
None
Totals 0
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
. oxidant standards
0
-------
\ o>
oo rt
o H
O.
M
CD
(D
hti.
H-
M
O
Hi
O
h(
O
(D
ft
s
TABLE A-9. BREAKDOWN OF OPERATING REFINERIES IN REGION II.
New Jersey
New York
Puerto Rico
Virgin Islands
Totals
Total
refineries
4
3
3
1
11
Total capacity,
bbl/day
644,000
135,020
283,800
728,000
1,790,820
Refineries in
attainment
areas
0
0
3
1
4
Refineries in
nonattainment
areas
4
3
0
0
7
(D
H-
X
-------
u> >d
\ CD
CO ft
O I-!
o
H
CD
M
TABLE A-10. BREAKDOWN OF OPERATING REFINERIES IN NEW JERSEY
REGION: II
STATE: New Jersey
Name and address of refinery
Chevron USA, Inc.
1200 State Street
Perth Amboy 08861
Exxon Co. , USA
P.O. Box 222
Linden 07036
Mobil Oil Corp.
Paulsburo 08066
Texaco, Inc.
P.O. Box 98
Westville 08093
Totals 4
County
Middlesex
Union
Gloucester
Gloucester
AQCR No.
043
043
045
045
Capacity
bbl/day
168,000
290,000
98,000
88,000
644,000
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
4
TJ
V
CD
3
O-
I-1-
-------
\ (D
CO ft
o i-i
O
fD
Hi
H-
3
(D
h
HI
O
H
O
§
(D
TABLE A-ll. BREAKDOWN OF OPERATING REFINERIES IN NEW YORK
REGION: II
STATE: New York
Name and address of refinery
Ashland Oil , Inc.
N. Tonawanda 14120
Cibro Petroleum
Port of Albany 12202
Mobil Oil Corp.
Buffalo 14240
Totals 3
County
Niagara
Albany
Erie
AQCR (to.
162
161
162
Capacity
bbl/day
64,020
28,000
43,000
135,020
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
3
0)
(D
3
-------
U) TJ
\ fl>
oo rt
o i-!
O
TABLE A-12. BREAKDOWN OF OPERATING REFINERIES IN PUERTO RICO
SO
(D
Hi
P-
3
W
3
i-h
O
h
o
(D
3
rt
REGION: II
Puerto Rico
Name and address of refinery
Caribbean Gulf Refining Corp.
G.P.O. Box 1988
San Juan 00936
Cormonwealth Oil & Refining Co.
(CORCO)
Penuelas at Guayanilla Bay 00731
Yubucoa Sun Oil Co., Inc.
P.O. Box 186
Yubucoa 00767
Totals 3
County
AQCR No.
244
244
244
Capacity
bbl/day
37,800
161,000
85,000
283,800
Attainment area
for photochemical
oxidant standards
X
X
X
3
Nonattainment area
for photochemical
oxidant standards
0
(D
P-
X
>
-------
00
O
O
M
(D
s?
Hi
w
3
O
H
O
(D
ft
5* 3»
I P
i—i 3
i&.£
TABLE A-13. BREAKDOWN OF OPERATING REFINERIES IN VIRGIN ISLANDS
REGION: II
Virgin Islands
Name and address of. refinery
Amerada Hess Corp.
St. Croix 00850
Totals 1
County
At}CS No.
247
Capacity
bbl/day
728,000
728,000
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
0
0)
H-
X
-------
oo rt
o N.
•> o
TABLE A-14. BREAKDOWN OF OPERATING REFINERIES IN REGION III.
CD
Hi
H-,
P
(D
H
H
3
Hi
O
H
O
CD
3
ft
0)
Delaware
Maryland
Pennsylvania -
Virginia
West Virginia
Washington D.C.
Totals
Total
refineries
1
1
10
1
3
0
16
Total capacity,
bbl/day
140,000
15,000
801,210
53,000
19,450
0
1,028,660
Refineries in
attainment
areas
0
0
0
1
2
0
3
Refineries in
nonattainment
areas
1
1
10
0 •
1
0
13
CD
H-
X
-------
CJ ^
\(D
00 ft
o h
O
H
(D
(D
Hi
H-
td
3
HI
O
H.
O
(D
13
rt
TABLE A-15. BREAKDOWN OF OPERATING REFINERIES IN DELAWARE
REGION: III
STATE: Delaware
Name and address of refinery
Getty.: Oil Co.
Delaware City 19706
Totals 1
County
New Castle
-
AQCR No.
045
Capacity
bbl/day
140,000
140,000
Attainment area
for photochemical
oxidant standards
'
0
Nonattainment area
for photochemical
oxidant standards
X
1
13
(D
-------
co cl-
ou
O
M
(D
g
TABLE A-16. BREAKDOWN OF OPERATING REFINERIES IN MARYLAND
CD REGION: III
HI STATE: Maryland
H-
(D
M-
(D
(D
S3
rt
? S
Name and address of refinery
Amoco Oil Co.
3901 Asiatic Ave.
Baltimore 21226
Totals 1
County
Baltimore
AQCR No.
115 '
Capacity
bbl/day
15,000
15,000
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
.X
1
V
(D
-------
U) *V
\ CD
00 ft
o H
O
M
ro
Hi
p-
3
(D
TABLE A-17. BREAKDOWN OF OPERATING REFINERIES IN PENNSYLVANIA
REGION: III
STATE: Pennsylvania
w.
2. Name and address of refinery
rh
O :
••* Ashland Oil , Inc.
£ Freedom 1 5042
fl> Atlantic Richfield Co.
3 3144 Passyunk
^ Philadelphia 19145
3
0) B.P. Oil, Inc. (subsidiary of
g Standard Oil Co. of Ohio)
§ P.O. Box 428
!-• Marcus Hook 19061
Gulf Oil Corp.
P.O. Box 7408
Philadelphia 19101
Pennzoil Co.
Rouseville 16344
Quaker State Oil Refining Corp.
Emlenton 16373
Quaker State Oil Refining Corp.
•p Farmers Valley 16749
'O Sun Petroleum Products Co. (Div.
2 of Sun Oil Co. of Pa.)
& P.O. Box 426
p- Marcus Hook 19061
County
Beaver
Philadelphia
Delaware
Philadelphia
Venango
Venango
McKean
Delaware
AQCR No.
197
151
151
151
178
178
178
151
Capacity
bbl/day
6,790
185,000
164,000
207,600
12,000
3,320
6,500
165,000
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
X
>
M
CO
(continued)
-------
to h3
\ fl>
CO ft
o h
O
c:
HI
H-
w
d
Hi
O
M
O
(D
TABLE A-17. (continued)
REGION: III
STATE:, Pennsylvania (continued)
Name and address of refinery
United Refining Co.
P.O. Box 780
Bradley and Dobson Sts.
Warren 16365
Witco Chemical Corp.,
Kendall Refining Div.
77 N. Kendall Ave.
Bradford 16701
Totals 10
County
Warren
McKean
AQCR No.
178
178
Capacity
bbl/day
42,000
9,000
801,210
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
10
(D
-------
\ (D
oo rt
o i-i
O
M
(D
(D
Hi
H-
3
h
W
O
o
(D
ft
I S
TABLE A-18. BREAKDOWN OF OPERATING REFINERIES IN VIRGINIA
REGION: III
STATE: Virginia
Name and address of refinery
Amoco Oil Co.
P.O. Box 578
Yorktown 23490
Totals 1
County
York
AQCR No .
223
Capacity
bbl/day
53,000
53,000
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
0
H-
>
-------
00 ft
O H
O
i
0)
l-h
H-
3
(D
Hi
O
H
O
n>
TABLE A-19. BREAKDOWN OF OPERATING REFINERIES IN WEST VIRGINIA
REGION: III
STATE: West Virginia
Name and address of refinery
Elk Refining Co.
(Div. of Pennzoil Co. )
P.O. Box 68
Falling Rock 25079
Quaker State Oil Refining Corp.
P.O. Box 336
Newell 26050
Quaker State Oil Refining Corp.
St. Marys 26170
Totals 3
County
Kanawha
Hancock
Pleasants
AQCRNo.
234
181
179
Capacity
bbl/day
4,900
9,700
4,850
19,450
Attainment area
for photochemical
oxidant standards
X
X
2
Nonattainment area
for photochemical
oxidant standards
X
1
(U
13
(D
H-
>
-------
oo rt
O M
O
M
(D
TABLE A-20. BREAKDOWN OF OPERATING REFINERIES IN DISTRICT OF COLUMBIA
^ .REGION: III
H- Washington, D.C.
(D
H
Name and address of refinery
W
HI None
O
H
0
(D
it Manual Appenc
A-22
H- Totals n
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
-------
\o>
00 ft
O I-!
O
H
CD
(D
Hi
H-
3
(D
H
Hi
O
1-1
O
(D
3
ft
TABLE A-21. BREAKDOWN OF OPERATING REFINERIES IN REGION IV.
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Totals
Total
refineries
6
1
2
4
6
1
0
1
21
Total capacity,
bbl/day
108,300
6,000
20,000
169,000
340,700
11,900
0
43,900
699,800
Refineries in
attainment
areas
3
1
1
2
6
1
0
0
14
Refineries in
nonattainment
areas
3
0
1
2
0
0
0
1
1
(D
H-
>
-------
u> *d
\tt>
OO ft
o h
O
H
(D
»
(D
Hi
H-
3
(D
H
*<
W
3
Hi
O
t-!
O
fD
3
rt
=r?
Kg
PJ
TABLE A-22. BREAKDOWN OF OPERATING REFINERIES IN ALABAMA
REGION: IV
STATE: Alabama
Name and address of refinery
Hunt Oil Co.
P.O. Box 1850
Tuscaloosa 35402
Louisiana Land & Exploration Co.
Saraland 36571
Marion Corp.
P.O. Box 526
Theodore 36582
Mobile Bay Refining Co.
P.O. .Box 11526
Chickasaw 36611
Vulcan Asphalt Refining Co.
P.O. Box 80
Cordova 35550
Warrior Asphalt Co. of Alabama,
Inc.
Holt 35401
Totals 6
County
Tuscaloosa
Mobile
Mobile
Mobile
Walker
Tuscaloosa
AQCR No.
004
005
005
005
004
004
Capacity
bbl/day
29,000
41,300
20,000
10,000
5,000
3,000
108,300
Attainment area
for photochemical
oxidant standards
X
X
X
3
Nonattainment area
for photochemical
oxidant standards
X
X
X
3
n>
H-
x
-------
OJ
oo rt
o h
O
\->
0>
c
n>
HI
H-
3
(D
H
W
V
Hi
O
H.
O
§
(D
> g
I fl)
to 3
Ul d
TABLE A-23. BREAKDOWN OF OPERATING REFINERIES IN FLORIDA
REGION: IV
STATE: Florida
Name and address of refinery
Seminole Asphalt Refining, Inc.
P.O. Box 128
St. Marks 32355
Totals 1
County
Wakulla
AOCR No.
049
Capacity
bbl/day
6,000
6,000
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
0
(D
H-
X
-------
CO ft
O I-!
O
I-1
fl>
TABLE A-24. BREAKDOWN OF OPERATING REFINERIES IN GEORGIA
H\ REGION: IV
H- STATE: Georgia
fl>
f-^
<
Name and address of refinery
H
H)
O Amoco Oi 1 Co.
% P.O. Box 1881
jp Savannah 31402
(D Young Refining Corp.
£. P.O. Box 775
Douglasville 30134
H
n>
&
H- Totals 2
County
Chatham
Douglas
AQCR Ho.
058
056
Capacity
bbl/day
15,000
5,000
20,000
Attainment area
for photochemical
oxidant standards
X
-
Nonattainment area
for photochemical
oxidant standards
X
1 1
>
CTl
-------
00 ft
o M
o
i-1
(D
TABLE A-25. BREAKDOWN OF OPERATING REFINERIES IN KENTUCKY
(D REGION: IV
STATE: Kentucky
(D
K
"^ Name and address of refinery
^— — — — — ^— — —
3
••h Ashland Oil , Inc.
° Catlettsburg 41129
O
g Ashland Oil , Inc.
3 224 East Broadway
3 Louisville 40202
rt-
Kentucky Oil & Refining, Inc.
pft Rt. 1, P.O. Box 63
1 3 Betsy Lane 41605
"^ ^ Somerset Refinery, Inc.
Somerset 42501
(D -
3
^.Totals 4
County
Boyd
Jefferson
Floyd
Pulaski
AOCR No.
103
078
101
105
Capacity
bbl/day
135,800
25,200
3,000
5,000
-
169,000
Attainment area
for photochemical
oxidant standards
.
X
X
2
Nonattainment area
for photochemical
oxidant standards
X
X
2
-------
CO
CO ft
O h
O
M
fD
£
3
(D
Hi
H-
3
(D
Ml
O
H
O
fD
ft
> &>
I 3
00 P>
REGION: IV
STATE: Mississippi
TABLE A-26. BREAKDOWN OF OPERATING REFINERIES IN MISSISSIPPI
Name and address of refinery
Amerada Hess Corp.
P.O. Box 425
Purvis 39475
Chevron USA, Inc.
P.O. Box 1300
Pascagoula 39567
Ergon, Inc.
Vicksburg 39180
Southland Oil Co.
Lumberton 39455
Southland Oil Co.
Sandersville 39477
Southland Oil Co.
Yazoo City 39194
Totals 6
. County
Lamar
Jackson
Warren
Lamar
Jones
Yazoo
AQCR No.
005
005
005
005
005
134
Capacity
bbl/day
30,000
280,000
10,000
5,500
11,000
4,200
340,700
Attainment area
for photochemical
oxidant standards
X
X
X
X
X
X
6
Nonattainment area
for photochemical
oxidant standards
0
(D
3
a*
H-
X
-------
oo rt-
o H
O
TABLE A-27. BREAKDOWN OF OPERATING REFINERIES IN NORTH CAROLINA
& REGION: IV
S, STATE: North Carolina
H-
n>
LJ
k
-------
OJ tJ
\ (D
00 ft
O 1-!
O
H
(D
(D
Hi
P-
TABLE A-28. BREAKDOWN OF OPERATING REFINERIES IN SOUTH CAROLINA
REGION: IV
STATE: South Carolina
(D
W Name and address of refinery
HI
° None
0
(D
ft
S
H
(0
3
p-
X Totals 0
County
AQCR No.
Capacity
bbl/day
1
Attainment area
for photochemical
oxidant standards
0 0
Nonattainment area
for photochemical
oxidant standards
0
-------
\ (D
00 ft
O H
O
TABLE A-29. BREAKDOWN OF OPERATING REFINERIES IN.TENNESSEE
1-h
H-
3
(D
U
3
Hi
O
M
O
i
rt
3
p,
REGION: IV
STATE: Tennessee
Name and address of refinery
Delta Refining Co. (Div. of Earth
Resources Co. ) ,
P.O. Box 9097
Memphis 38109
Totals 1
County
Shelby
AQCR No.
018
Capacity
bbl/day
43,900
43.900 .
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
1
(D
3
0.
H-
X
-------
00 ft
O I-!
O
M
0>
(D
Hi
td
3
HI
O
H
O
(D
3
rt
> S
I 0>
TABLE A-30. BREAKDOWN OF OPERATING REFINERIES IN REGION V.
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Totals
Total
refineries
14
8
7
3
7
1
40
Total capacity,
bbl/day
1,201,200
605,900
185,955
217,943
590,400
40,000
.2,841,398
Refineries in
attainment
areas
7
3
0
0
0
0
10
Refineries in
nonattainment
areas
7
5
7
3
7
1
30
13
-------
OJ >tf
•\(D
oo rt
o H
O
(D
Ml
H-
2
(D
H
H)
o
n
o
(D
3
rt
TABLE A-31. BREAKDOWN OF OPERATING REFINERIES IN ILLINOIS
REGION: V
STATE: Illinois
Name and address of refinery
Amoco Oil Co.
P.O. Box 182
Wood River 62095
Bi-Petro, Inc.
Pana 62557
Clark Oil & Refining Corp.
P.O. Box 297
Blue Island 60406
Clark Oil & Refining Corp.
P.O. Box 145
Hartford 62048
Dillman Oil Recovery, Inc.
Robinson 62449
Marathon Oil Co.
Robinson 62454
Mobil Oil Corp.
P.O. Box 874
Jol iet 60434
Richards, M. T. , Inc.
P.O. Box 429
Crossville 62827 .
County
Madison
Christian
Cook
Madison
Crawford
Crawford
Will
White
AQCR No.
070
075
067
070
074
074
067
074
Capacity
bbl/day
105,000
1,500
70,000
55,000
1,200
195,000
180,000
700
Attainment area
for photochemical
oxidant standards
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
(D
H-
>
(continued)
-------
OJ >ti
\ 0>
00 ft
O H
O
I-1
CD
SO
CD
hh
H-
2
CD
W
3
Ml
O
n
O
CD
3
ft
> P
1 3
co P
*. P
TABLE A-31. (continued)
REGION: V
STATE: Illinois ( continued)
Name and address of refinery
Shell Oil Co.
P.O. Box 262
Wood River 62095
Texaco, Inc.
P.O. Box 311
Lawrenceville 62439
Texaco, Inc.
P.O. Box 200
Lockport 60441
Union Oil Co. of California
P.O. Box 339
Lemon t 60439
Wireback Oil Co.
Plymouth 62367
Yetter Oil Co.
Coluiar 52327
Totals 14
County
Madison
Lawrence
Will
Cook
Hancock
McDonough
AOCR No.
070
074
067
067
065
065
Capacity
bbl/day
283,000
84,000
72,000
151,000
i 1,800
1,000
.1,201,200
Attainment area
for photochemical
oxidant standards
X
X
X
7
Nonattainment area
for photochemical
oxidant standards
X
X
X
7
CD
P-
>
-------
\ (D
00 ft"
O H
O
TABLE A-32. BREAKDOWN OF OPERATING REFINERIES IN INDIANA
ro
HI
H-
3
(D
M
"•<
w
0
Hi
O
H
O
REGION: V
STATE: Indiana
Name and address of refinery
Amoco Oil Co.
P.O. Box 710 -
Whiting 46394
Energy Cooperative, Inc.
3500 Indianapolis Blvd.
E. Chicago 46312
Gladieux Refinery, Inc.
4133 New Haven Ave.
Ft. Wayne 46803
Indiana Farm Bureau Cooperative
Assn., Inc.
' P.O. Box 271
Mt. Vernon 47620
Industrial Fuel Asphalt of
Indiana
Hammond 46320
Laketon Asphalt Refinery Co.
P.O. Box 231
Laketon 46943
Princeton Refinery, Inc.
Princeton 47670
County
Lake
Lake
Allen
Posey
Lake
Wabash
Gibson
AQCR No.
067
067
081
077
067
084
077
Capacity
bbl/day
380,000
126,000
12,200
21,200
9,800
8,500
4,600
Attainment area
for 'photochemical
oxidant standards
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
TJ
(D
H-
X
(continued)
-------
U) MJ
X. (D
00 ft
o h
o
H
(D
(D
Hi
H-
3
CD
H
H
p
i-h
O
H
O
CD
3
ft
TABLE A-32. (continued)
REGION: V
•STATE: Indiana (continued)
Name and address of refinery
Rock Island Refining Corp.
P.O. Sox 68007
Indianapolis 46263
Totals 8
County
Marion
AQCR No.
080
Capacity
bbl/day
43,600
605,900
Attainment area
for photochemical
oxidant standards
3
Nonattainment area
for photochemical
oxidant standards
•K
5
13
(D
3
-------
00 ft
O H
O
H
CD
TABLE A-33. BREAKDOWN OF OPERATING REFINERIES IN MICHIGAN
(D
Hi
H-
3
(D
M
0
Hi
O
H
o
(D
13
ft
> ~
I 3
"I
P>
REGION:
STATE: Michigan
Name and address of refinery
Consumers Power Co.
Marysville 48040
Crystal Refining Co. of Carson
City, Inc.
Carson City 48811
Dow Chemical , USA
4868 Wilder Road
Bay City 48706
Lakeside Refining Co.
P.O. Dox 909
Kalamazoo 49005
Marathon Oil Co.
1300 S. Fort Street
Detroit 48217
Osceola Refining Co. (subsidiary
of Texas American Petrochemical)
2790 Refinery Rd.
West Branch 48661
Total Petroleum, Inc. (subsidiary
of Total Petroleum (North
American), Ltd.)
East Superior St.-, Alma 48801
Totals 7
County
St. Clair
Montcalm
Bay
Kalamazoo
Wayne
Ogemaw
Gratiot
AQCR No.
123
122
122
125
123
122
122
Capacity
bbl/day
37,655
6,200
17,000
5,600
65,000
12,500
42,000
185.955
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
7
H-
X
-------
U) ^0
\ (D
CO rt-
O H
o
. M
(D
(D
Hi
H-
(D
w
3
HI
o
n
o
g
(D
> J5
OJ 13
00 d
TABLE A-34. BREAKDOWN OF OPERATING REFINERIES IN MINNESOTA
REGION:
STATE: Minnesota
Name and address of refinery
Continental Oil Co.
P.O. Box 8
Wrenshall 55797
Koch Refining Co. (subsidiary of
Koch Industries, Inc.)
P.O. Box 43596
St. Paul 55154
Northwestern Refining Co.
(subsidiary of Ashland Oil,
Inc.)
P.O. Drawer 9
St. Paul Park 55071
Totals 3
County
Carl ton
Dakota
Washington
AQCR No.
129
131
131
Capacity
bbl/day
23,500
127,300
57,143
217,943
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
3
(D
-------
\ (D
00 ft
O H
O
H
(D
TABLE A-35. BREAKDOWN OF OPERATING REFINERIES IN OHIO
Mi
H-
3
(D
w
3
HI
O
n
O
(D
(D
> S
I p)
REGION: V
STATE: Ohio
Name and address of refinery
Ashland Oil , Inc.
P.O. Box 8170
Canton 44701
Ashland Oil Inc.
Findlay 45348
Gulf Oil Corp.
P.O. Box 7
Cleves 45202
Gulf Oil Corp.
P.O. Box 1023
Toledo 43601
Standard Oil Co. of Ohio
1150 S. Metcalf St.
Lima 45804
Standard Oil Co. of Ohio
P.O. Box 696
Toledo 43601
Sun Co. , Inc.
P.O. Box 920
Toledo 43601
Totals 7
County
Stark
Hancock
Hamilton
Lucas
Allen
Lucas
Lucas
AQCR No.
174
177
079
124
177
124
124
Capacity
bbl/day
64,000
20,400
42,700
50,300
168,000
120,000
125,000
590,400
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
7
13
H-
X
-------
OJ >tl
\ (D
oo rt
o M
O
H
(D
(D
Mi
P-
3
(D
H
3
Ml
O
H
O
0>
cr
P)
TABLE A-36. BREAKDOWN OF OPERATING REFINERIES IN WISCONSIN
REGION: V
STATE: Wisconsin
Name and address of refinery
Murphy Oil Corp.
Superior 54880
Totals 1
County
Douglas
AQCR No.
129
Capacity
bbl/day
40,000
40,000
Attainment area
for photochemical
o-xidant standards
.
0
Nonattainment area
for photochemical
oxidant standards
X
•
1
(D
3
X
>
-------
u> na
\ n>
00 ft
o n
o.
TABLE A-37. BREAKDOWN OF OPERATING REFINERIES IN REGION VI.
0)
Hi
H-
W
3
Hi
O
l-i
O
fD
(D
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Totals
Total
refineries
4
28
8
12
56
108
Total capacity,
bbl/day
64,100
2,172,280
119,630
550,400
4,635,150
7,541,560
Refineries in
attainment
areas
4
10
8
10
22
54
Refineries in
nonattainment
areas
0
18
o
• 2
34 .
54
0)
3
-------
OJ nj
oo rt
O H
o .
(D
TABLE A-38. BREAKDOWN OF OPERATING REFINERIES IN ARKANSAS
REGION: VI
HI STATE: Arkansas
H
*< Name and address of refinery
Ul
s
HI Berry Petroleum Co. (subsidiary of
° Crystal Oil Co.)
0 Stephens 71764
3 Cross Oil & Refinery Co. of Ark.
2 P.O. Box 105
ct Smackover 71762
S Lion Oil (Div. of Tosco Corp.)
. 2 El Dorado 71730
>C!
&) MacMillan Ring-Free Oil Co., Inc.
1-1 Norphlet 71759
0)
^Totals 4
County
Ouachita
Un i on
Union
Union
AQCR No.
019
019
019
019
Capacity
bbl/day
3,500
9,200
47,000
4,400
64,100
Attainment area
for photochemical
oxidant standards
X
X
X
X
4
Nonattainment area
for .photochemical
oxidant standards
'
0
X
>\
-------
\ ro
00 ft
O M
O
I-1
TABLE A-39. BREAKDOWN OF OPERATING REFINERIES IN LOUISIANA
REGION: VI
STATE: Louisiana
(D
^<
Name and address of refinery
W
H, Atlas Processing Co. (subsidiary
O of Pennzoil Co. )
£ P.O. Box 9389
$ Shreveport 71109
£3
(D Bayou State Oil Corp.
i P.O. Box 158
Hosston 71043
g
& Bruin Refining, Inc.
5 P.O. Box 156
fa St. James 70086
1 — '
Calcasieu Refining, Ltd.
Lake Charles 70601
Calumet Refinery Co. (Oiv. of
Calumet Industries, Inc.)
Princeton 71067
Canal Refinery Co.
Church Point 70525
Cities Service Oil Co.
P.O. Box 1562
J> Lake Charles 70601
**t
County
Caddo
Caddo
St. James
Calcasieu
Bossier
Acadia
Calcasieu
AQCR No.
022
022
106
106
022
106
106
Capacity
bbl/day
45,000
5,000
Attainment area
for photochemical
oxidant standards
'
;
i
19,300
5,000
2,400
6,400
268,000
i
Nonattainment area
for photochemical
oxidant standards
X
x
X
X
X
1
i
X
i X
i
1
1
1
H-( continued)
X
-------
\ (D
00 ft
O M
O
TABLE A-39. (continued)
REGION: VI
hh STATE: Louisiana (continued)
(D
"< Name and address of refinery
3 Claiborne Gasoline Co.
Hi P.O. Box 75
^ Lisbon 71048
O
fl> Continental Oil Co.
| Egan 70531
ct Continental Oil Co.
.. P.O. Box 37
>gf Westlake 70669
*.£ Cotton Valley Solvents Co. (owned
& by Triangle Refineries, Inc.,
wholly owned subsidiary of
Kerr-McGee Refining Corp.)
P.O. Box 97
Cotton-Valley 71018
Evangel ine Refinery Co., Inc.
P.O. Box 726
Jennings 70546
Exxon Co. , USA
P.O. Box 551
Baton Rouge 70821
•** Good Hope Refineries, Inc.
2 P.O. Drawer 537
(D Good Hope 70079
County
Claiborne
Acadia
Calcasieu
Webster
AQCR No.
022
106
106
022
i
i
Jefferson i 106
Capacity
bbl/day
6,500
15,000
83,000
7,000
5,000
Davis
i
E. Baton ; 106
Rouge !
i
i
St. Charles
106 .
i
510,000
80,000
'
Attainment area
for photochemical
oxidant standards
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
1
X
X
(continued)
-------
oo rt
o H
O
TABLE A-39. (continued)
(D
Hi
H-
3
(D
Hi
o
n
o
CD
3
ft
I pj
REGION: VI
STATE: Louisiana (continued)
Name and address of refinery
Gulf Oil Co. -US
P.O. Box 395
Belle Chasse 70037
Gulf Oil Co. -US
P.O. Box G
Venice 70091
Hill Petroleum (subsidiary of
Goldking Petroleum Co.)
P.O. Box 453
Krotz Springs 70750
LaJet, Inc. (branch of
No. American Petroleum)
P.O. Box 47
St. James 70086
Marathon Oil Co.
P.O. Box A-C
Garyville 70051
Mt. Airy Refining Co.
P.O. Box T
Garyville 70051
Murphy Oil Corp.
Meraux 70075
County
Plaquemines
Plaquemines
St. Landry
St. James
St. John
the Baptist
St. John
the Baptist
St. Bernard
AqCR No.
T06
106
106
106
106
106
106
Capacity
bbl/day
195,900
28,700
10,000
20,000
200,000
11,580
92,500
Attainment area
for photochemical
oxidant standards
X
X
- x
Nonattainment area
.for photochemical
oxidant standards
X
X
X
X
(D
3
(^
H-
X
(continued)
-------
U)
00 ft
O H
O
H
CD
JO
TABLE A-39. (continued)
REGION: VI
STATE: Louisiana (continued)
p
CD
H
Name and address of refinery
trl
H, Placid Refining Co.
O P.O. Box 350 B
H Port Allen 70767
O
| Shell Oil Co.
(D P.O. Box 10
2. Norco 70079
ft
g Shepherd Oil, Inc.
^ P.O. Box 609
5 Jennings 70546
M South Louisiana Production Co.
Mermentau 70556
T & S Refining, Inc.
Mermentau 70556
Tenneco Oil Co.
P.O. Box 1007
Chalmette 70043
Texaco, Inc.
P.O. Box 37
Convent 70723
CD
3
H. Totals 28
County
W. Baton
Rouge
St. Charles
Jefferson
Davis
Acadia
AQCR No.
106
106
106
106
j
Acadia
St. Bernard
St. James
106
106
106
Capacity
bbl/day
36,000
230,000
10,000
10,000
10,000
120,000*
140,000
2,172,280
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
10
X
X
X
18
*Barrels per stream day ' . .
-------
U) >T3
\ (D
CO ft
O H.
o
I-1
(D
C
JO
H-
3
(D
l-i
W
3
Hi
O
H
O
(D
3
ft
TABLE A-40. BREAKDOWN OF OPERATING REFINERIES IN NEW MEXICO
REGION: VI
STATE: New Mexico
Name and address of refinery
Caribou-Four Corners Oil Co.
P.O. Box 175
Kirtland 87417
Giant Refining Co.
Bloomfield 87413
Navajo Refinery Co. (owned by
Holly Corp.)
P.O. Box 159
Artesia 88210
Plateau, Inc.
Bloomfield 87413
Shell Oil Co., Ciniza Refinery
Wingate Star Route
Gallup 87301
Southern Union Refining Co.
Lovington 88260
Southern Union Refining Co.
Monument 88265
Thriftway Oil Co.
Bloomfield 87413
Totals 8
County
San Juan
San Juan
Eddy
San Juan
Me Kin ley
Lea
Lea
San Juan
AQCR No.
014
014
155
014
014
155
155
014
Capacity
bbl/day
2,500
6,000
29,900
14,000
18,000
36,430
5,300
7,500
119,630
Attainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
X
8
Nonattainment area
for photochemical
oxidant standards
0
(D
H-
X
-------
OJ ^
\ tt>
00 ft
O H
O
H
(D
§
TABLE A-41. BREAKDOWN OF OPERATING REFINERIES IN OKLAHOMA
Hi
H-
3
(D
K
td
3
HI
O
H.
O
(D
3
ft
REGION: VI
STATE: Oklahoma
Name and address of refinery
Allied Materials Corp.
P.O. Box 516
Stroud 74079
Bell Oil & Gas Co. (Div. of
Vicker Petroleum Co.)
P.O. Box 188
Ardmore 73401
Champ! in Petroleum Co. (subsidiary
of Union Pacific)
P.O. Box 552
Enid 73701
Continental Oil Co.
P.O. Box 1267
Ponca City 74601
Hudson Oil Co.
P.O. Box 1111
Cushing 74023
Kerr-McGee Corp.
P.O. Box 305
Wynnewood 73098
OKC Refining Co.
P.O. Box 918
Okmulgee 74447
County
Lincoln
Carter
Ellis
Kay
Payne
Garv in
Okmulgee
AQCR No.
184
188
187
185
185
188
186
Capacity
bbl/day
5,500
64,100
53,800
126,000
Attainment area
for photochemical
oxidant standards
x
x
x
Nonattainment area
for photochemical
oxidant standards
x
19,000 ! x
50,000 • x
',
25,000
x
'
•O
(D
3
Pb
H-
Icontinued)
-------
oo rt
o H
O
M
(D
(D
Hi
H-
3
(D
w
3
Hi
o
I-!
O
(D
3
rt
fl)
TABLE A-41. (continued)
REGION: VI
STATE: Oklahoma (continued)
Name and address of refinery
Oklahoma Refining Co.
Cyril 73029
Sun Petroleum Products Co. (Oiv.
of Sun Oil Co. of Pa.)
P.O. Box 820
Duncan 73533
Sun Petroleum Products Co. (Div.
of Sun Oil Co. of Pa.)
P.O. Box 2039
Tulsa 74102
Texaco, Inc.
P.O. Box 2389
Tulsa 74101
Tonkawa Refining Co.
Route 1, Box 30
Arnett 73832
.
Totals 12
County
Caddo
Stephens
Tulsa
Tulsa
Ellis
AQCRNo.
189
189
186
186
187
.
•
•
j
;
Capacity
bbl/day
14,000
48,500
88,500
50,000
6,000
550,400
Attainment area
for photochemical
oxidant standards
X
X
X '
-
10
Nonattainment area
for photochemical
oxidant standards-
X
X
2
(D
H-
X
-------
\ (D
00 ft
o H
O
I-1
tt>
TABLE A-42. BREAKDOWN OF OPERATING REFINERIES IN TEXAS
REGION: VI
STATE: Texas
Name and address of refinery
Adobe Refining Co. (subsidiary of
Crystal Oil Co., La Blanca
Refining Div. )
P.O. Box 3
La Blanca 78558
American Petrofina Co.
P.O. Box 849
Port Arthur 77640
Amoco Oil Co.
P.O. Box 401
Texas City 77590
Atlantic Richfield Co.
P.O. Box 2451
Houston 77001
Champlin Petroleum Co. (subsidiary
of Union Pacific)
1801 Nueces Bay Blvd.
Corpus Christi 78408
Charter Int'l Oil Co.
P.O. Box 5008
Houston 77012
Chevron USA, Inc.
P.O. Box 20002
El Paso 79998
( r*f\nti{ mioH 1
County
Hidalgo
Jefferson
Galveston
Harris
Nueces
Harris
El Paso
AOCR No.
213
106
216
216
214
216
153
Capacity
bbl/day
5,000
110,000
360,000
322,000
155,000
65,500
76,000
Attainment area
for photochemical
oxidant standards
X
. Nonattainment area
'for photochemical
oxidant standards
X
X
X
X
X
X
i-ti
H-
13
(D
h
W
3
HI
O
H
O
(D
I
Ul
13
T3
n>
-------
\ n>
00 ft
o H
O
\->
(D
TABLE A-42. (continued)
REGION: VI
STATE: Texas fcnntiniiedl
Name and address of refinery
Coastal States Petrochemical Co.
(subsidiary of Coastal States
Gas Producing Co.)
1300 Cantwell Lane
Corpus Christi 78407
Cosden Oil & Chemical Co.
.Big Spring 79720
Crown Central Petroleum Co.
Pasadena 77501
Diamond Shamrock Oil & Gas Co.
P.O. Box 36, Star Route 1
Sunray 79086
Dorchester Refining Co. (subsidi-
ary of Dorchester Gas Corp.)
P.O. Box 1011
Mt. Pleasant 75455
Eddy Refining Co.
P.O. Box 185
Houston 77001
Erickson Refining Corp.
Port Neches 77651
County
Nueces
Howard
Harris
Moore
Titus
Harris
Jefferson
AQCR No.
214
218
216
211
022
216
106
Capacity
bbl/day
185,000
65,000
100,000
51,500
26,000
3,250
30,000
Attainment area •
for photochemical
oxidant standards
>
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
3
(D
H
H
3
l-h
O
H
O
(D
3
rt
H-
X
(continued;
-------
00 ft
O H
O
M
(D
n>
Mi
H-
H
3
Hi
O
H
O
TABLE A-42. (continued)
• REGION: VI
STAT.E: Texas (continued)
Name and address of refinery
Exxon Co. USA
P.O. Box 3950
Baytown 77520
Flint Chemical Co.
403 Somerset
San Antonio 78211'
Gulf Oil Corp.
P.O. Box 701
Port Arthur 77640
Gulf States Oil & Refining Co.
• 7501 Up River Rd.
Corpus Christi 78410
Gulf States Oil & Refining Co.
P.O. Box 896
Quitman 75783
Howell Hydrocarbons, Inc.
P.O. Box 2776
San Antonio 78299
Independent Refining Corp.
Winnie 77665
J.W. Refining Co.
Tucker 75801
County
Harris
Bexar
Jefferson
Nueces
Wood
Bexar
Chambers
Anderson
AQCR No.
216
217
106
214
022
217
216
022
Capacity
bbl/day
640,000.
1,200
334,500
12,500
6,000
5,000
16,000
4,000
Attainment area
for photochemical
oxidant standards
X
X
' X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
(1)
13
0)
3
a
H-
X
(continued)
-------
00
o
CD
50
(D
Hi
H-
3
fD
w
t>
HI
o
H
O
§
(D
•g
fll
TABLE A-42. (continued)
REGION: VI
STATE: Texas (continued)
Name and address of refinery
LaGloria Oil & Gas Co. (subsidiary
of Texas Eastern Transmission
Corp.)
P.O. Box 840
Tyler 75702
Longview Refining Co. (Oiv. of
Crystal Oil Co.)
P.O. Box 1512
Longview 75601
Marathon Oil Co.
P.O. Box 1191
Texas City 77590
Mid-Tex Refinery (owned by
Electro-Form, Inc.)
Hearne 77859
Mobil Oil Corp.
P.O. Box 3311
Beaumont 77704
Petrol ite Corp.
Kilgore 75662
Phillips Petroleum Corp.
P.O. Box 271
Borger 79007
County
Smith
Gregg
Galveston
Robertson
Jefferson
Gregg
Hutchinson
AQCR No.
022
022
216
212
106
022
211
Capacity
bbl/day
29,300
9,000
66,700
3,000
335,000
1,000
100,000
Attainment area
for photochemical
oxidant standards
X
.
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
(D
H-
X
(continued)
-------
OJ "XI
\(D
00 ft
O l-f
o .
TABLE A-42. (continued)
(D
Hi REGION:
H- STATE:
(D
VI
Texas (continued)
Name and address of refinery
Phillips Petroleum Corp.
P.O. Box 866
Sweeny 77480
Pioneer Refining Co.
Nixon 78140
Pride Refining Co.
P.O. Box 3237
Abilene 79604
Quintana-Howell , Joint Venture
(owned by Howell Corp.)
P.O. Box 4656
Corpus Christi 78408
Rancho Refining Co., Inc. (Div. of
Southwest Petrochemical , Inc.)
Donna 78537
Raymal Refining, Ltd.
Ingleside 78362
Saber Petroleum Co.
6560 Up River Rd.
Corpus Christi 78410
Sentry Refining, Inc.
Corpus Christi 28407
County
Brazoria
AQCR No.
216
Deaf Smith
Taylor
Nueces
Hidalgo
San Patricio
Nueces
211
210
214
Capacity
bbl/day
104,000
5,000
36,500
35,000
i
213
214
214
Nueces i .214
1
1,000
2,000
20,000
10,000
Attainment area
for photochemical
oxidant standards
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
W
3
Hi
O
H
O
(D
3
ft
>S
I JD
U1J3
*e
P)
(D
(continued)
-------
\ tt>
oo rt
o H
O
H
(D
-. i r\oi_u n-*tc . v^u" «• ' nucu )
Hi REGION: VI
£' STATE: Texas (continued)
fl>
H
"^
w Name and address of refinery
H> Shell Oil Co.
° P.O. Box 100
0 Deer Park 77536
3 Shell Oil Co.
2 P.O. Box 2352
ft Odessa 79760
^ Sigmore Refining Co. (subsidiary of
a Sigmore Corp.)
d P.O. Box 490
0* Three Rivers 78071
South Hampton Co.
P.O. Box 605
Silsbee 77656
Southwestern Refining Co., Inc.
(subsidiary of Kerr-McGee Corp.)
P.O. Box 9217
Corpus Christi 78408
Sun Petroleum Products Co. (Div. of
Sun Oil Co. of Pa.)
P.O. Box 2608
> Corpus Christi 78403
*S Tesoro Petroleum Corp.
2 P.O. Box 156
& Carrizo Springs 788~34
H. . . . ,
. County
Harris
EC tor
Live Oak
Hard in
Nueces
Nueces
Dimmit
AQCR No.
216
218
214
106
214
214
217
Capacity
bbl/day
285,000
32,000
10,000
18,100
124,000
Attainment area j Nonattainment area
for photochemical
oxidant standards
x
X
j
57,000
26,100
X
for photochemical
oxidant standards
X
X
X
X
1
-------
00 ft
o n
O
H
CD
s?
l-h
0)
H
Hi
O
K1
O
(D
13
>«
U1 p
CTv [3
£
p)
TABLE A-42. (continued)
REGION: VI .
STATE: Texas (continued)
Name and address of refinery
Texaco, Inc.
P.O. Box 30110
Amarillo 79120
Texaco, Inc.
P.O. Box 20005
El Paso 79998
Texaco, Inc.
P.O. Box 712 '
Port Arthur 77640
Texaco, Inc.
P.O. Box 787
Port Neches 77651
Texas Asphalt & Refining Co.
P.O. Box 416
Euless 76039
Texas City Refining Co.
P.O. Box 1271
Texas City 77590
Thriftway, Inc.
P.O. Box 195
Graham 76046
County
Potter
El Paso
Jefferson
Jefferson
Tarrant
Galveston
Young
AQCR No.
211
153
106
106
215
216
210
Capacity
bbl/day
20,000
17,000
367,000
47,000
6,000
130,000
1,000
Attainment area
for photochemical
oxidant standards
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
*
X
n>
(continued)
-------
OO ft
o H
o
H1
(D
Hi
H-
3
(1)
n
w
3
Hi
O
hi
O
g
I 3
01 £
-B
P
TABLE A-42. (continued)
REGION: VI
STATE: Texas fcontinued)
Name and address of refinery
Tipperary Corp.
P.O. Box 659
Ingleside 78362
Uni Oil, Inc.
Ingleside 78362
Union Oil Co. of California
P.O. Box 237
Nederland 77627
Wickett Refining Co.
Wickett 79788
Winston Refining Co.
28th St. & Sylvania Ave.
Ft. Worth 76111
Totals 56
County
San Patricio
San Patricio
Jefferson
Ward
Tar rant
AQCR No.
214
214
106
218
215
Capacity
bbl/day
6,000
10,000
120,000
8,000
20,000
4,635,150
Attainment area
for photochemical
oxidant standards
X
X
X
.
22
Nonattainment area
for photochemical
'oxidant standards
X
x
34
(D
H-
X
-------
\ CD
00 ft
o i-i
O
H
CD
CD
Hi
H-
3
CD
h
W
13
Hi
O
CD
P
ft
TABLE A-43. BREAKDOWN OF OPERATING REFINERIES IN REGION VII.
Iowa
Kansas
Missouri
Nebraska
Totals
Total
refineries
0
11
1
13
| Refineries in
Total capacity, j attainment
bbl/day I areas
0
459,339
107,000
5,000
571,339
0
10
0
1
11
Refineries in
nonattainment
areas
0
1
1
0
2
oo
13
T3
CD
H-
X
-------
OJ
co rt
O l"{
o
fD
3 TABLE A-44. BREAKDOWN OF OPERATING REFINERIES IN IOWA
fl? REGION: VII
Hi STATE: Iowa
3
fD
H
^ Name and address of refinery
3 None
i-h
O
h
O
fD
ft
^ s
ui CD
u> 3
d
M
fD
3
g; Totals o
County
AQCR No.
i
j
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
X
>
-------
u> ^
\ fl>
oo rt
O hj
O
TABLE A-45. BREAKDOWN OF OPERATING REFINERIES IN KANSAS
>-h REGION: VII
STATE: Kansas
Name and address of refinery
CRA, Inc. (subsidiary of Farmland
Industries, Inc.)
P.O. Box 570
North Linden St.
Coffeyville 67337
CRA, Inc. (subsidiary of Farmland
Industries, Inc.)
P.O. Box 608
Phillipsburg 67661
Derby Refining Co.
P.O. Box 1030
Wichita 67201
E-Z Serve, Inc.
Route 2
Scott City 67871
Getty Refining & Marketing Co.
P.O. Box 1121
El Dorado 67042
Mid-American Refining Co., Inc.
P.O. Box 31
Chanute 66720
Mobil Oil Corp.
P.O. Box 546
Augusta 67010
County
Montgomery
Phillips
Sedgwick
Scott
Butler
Neosho
Butler
AQCRNo.
098
097
099
100
099
098
099
Capacity
bbl/day
48,000
26,400
27,982
10,000
80,577
3,500
50,000
Attainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
0)
h
O
O
rt
I PJ
PJ
TJ
(D
H-
X
(continued)
-------
°fT
O
3 TABLE A-45. (continued)
it? REGION: VII
STATE: Kansas (continued)
(D
l-i
^ Name and address of refinery
Ijj .
3 National Co-Op Refining Assoc.
HI P.O. Box 1167
° McPherson 67460
O
§ Pester Refining Co.
P.O. Box 751
g El Dorado 67042
Phillips Petroleum Co.
^ §• 2029 Fairfax Rd.
3 Kansas City 66115
P" Total Petroleum, Inc.
1-1 Arkansas City 67005
TJ
n>
H- Totals 11
County
McPherson
Butler
.
Wyandotte
Cow ley
AQCR No.
096
Capacity
bbl/day
54,150
099
094
099
22,500
90,000
46,230
459,339
Attainment area
for photochemical
oxidant standards
X
X
X
10
Nonattainment area
for photochemical
oxidant standards
X
1
I
cr\
-------
CO ft
o n
O •
TABLE A-46. BREAKDOWN OF OPERATING REFINERIES IN MISSOURI
-------
oo
o
O
M
(D
REGION: VII
ESTATE: Nebraska
TABLE A-47. BREAKDOWN OF OPERATING REFINERIES IN NEBRASKA
(D
H
*< Name and address of refinery
W
HCRA, Inc. (subsidiary of Farmland
O Industries, Inc.)
H P.O. Box 311
0 Scottsbluff 69361
rt
*
O)
ft)
tJ
(D
DJ Totals i
County
Scotts
Bluff
AQCR No.
146
Capacity
bbl/day
5,000
5,000
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
0
X - -
-------
\ CD
CO ft
o h
o
M
(D
(D
Hi
H-
3
0)
M
3
Hi
O
H
O
(D
3
ft
en
TABLE A-48. BREAKDOWN OF OPERATING REFINERIES IN REGION VIII.
(D
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Totals
Total
refineries
3
6
3
0
. 8
14
34
Total capacity,
bbl/day
64,000
144,950
58,658
0
159,500
215,790
642,898
Refineries in
attainment
areas
1
6
3
0
1
14
25
Refineries in
nonattainment
areas
2
0
0
0
7
0
9
H-
X
-------
\ (D
00 ft
O H
O
M
(D
TABLE A-49. BREAKDOWN OF OPERATING REFINERIES IN COLORADO
pa REGION: VIII
£. STATE: Colorado
H-
3
(D
i^ name and address of refinery
w •
3 Asamera Oil (U.S.), Inc.
O 5800 Brighton Blvd.
hi Commerce City 80022
0
§ Continental Oil Co.
^ 5801 Brighten Blvd.
3 Commerce City 80022
rt
g Gary Western Co.
pi Gary Community Rural Station
3 Fruita 81521
£»
TJ
(D
a Totals 3
County
Adams
Adams
Mesa
AQCR No.
003
003
on
Capacity
Attainment area
for photochemical
bbl/day oxidant standards
21,500
32,500
10,000
64,000
x
1
Nonattainment area
for photochemical
oxidant standards
X
X
2
cr»
01
-------
OJ
-------
U) 13
CO rr
O H
O
H
(D
C
CD
Hi
H-
3
(D
H
"<:
H
3
Hi
O
O
CD
rt
f»
i|
TABLE A-51. BREAKDOWN OF OPERATING REFINERIES IN NORTH DAKOTA
REGION: VIII
STATE: North Dakota
Name and address of refinery
Amoco Oil Co.
P.O. Box 549
Mandan 58554
Northland Oil & Refining Co.
P.O. Box 1246
Dickinson 58601
Westland Oil Refinery
(Oiv. of Thunderbird Resources,
Inc.)
P.O. Box 849
Mil listen 58801
Totals 3
County
Morton
Stark
Williams •
AOCR No.
.
.172
172
172
Capacity
. bbl/day
49,000
5,000
4,658
.
58,658
Attainment area
for photochemical
oxidant standards
*
*
.
3
Nonattainment area
for photochemical
oxidant standards
0
CD
3
H-
>
-------
OJ I'd
\ CD
oo ft
o n
O
M
(D
C
3
TABLE A-52. BREAKDOWN OF OPERATING REFINERIES IN SOUTH DAKOTA
CD
HiREGION:
t'STATE:
VIII
South Dakota
en
CO
(D
h
.^Name and address of refinery
3 •— •
HI
O None
0
CD
ft
g
C
&
V
(D
3
a
^Totals 0
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
-------
U) 13
\(D
00 ft
O K
O
M
(D
TABLE A-53. BREAKDOWN OF OPERATING REFINERIES IN UTAH
(D
Ml
H-
M
3
Hi
O
n
O
REGION: VIII
STATE: Utah
Name and address of refinery
Amoco Oil Co.
474 W. 900 N.
Salt Lake City 84103
Caribou-Four Corners, Inc.
P.O. Box 54
Woods Cross 84087
Chevron USA, Inc.
2351 N. llth W.
P.O. Box 25117
Salt Lake City 84125
Husky Oil Co.
P.O. Box 175
North Salt Lake 84054
Morrison Petroleum Co.
P.O. Box 227
Woods Cross 84087
Phillips Petroleum Co.
Wood Cross 84087
Plateau, Inc.
Roosevelt 84066
Western Refining Co.
Woods Cross 84087"
Totals 8
County
Salt Lake
Davis
Salt Lake
Davis
Davis
Davis
Duchesne
Davis
AQCR No.
220
220
220
220
220
220
219
220
Capacity
bbl/day
39,000
7,500
45,000
25,000
2,500
23,000
7,500
10,000
159,500
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
7
(D
>
I
(D
-------
00 ft
O H
O
M
(D
(D
Hi
P-
g
TABLE A-54. BREAKDOWN OF OPERATING REFINERIES IN WYOMING
H, REGION: VIII
P STATE: Wyoming
n
(D flame and address of refinery
ft •
& Amoco Oil Co.
£ P.O. Box 160
g Casper 82602
P
H C & H Refinery, Inc.
. P.O. Box 278
•f Lusk 82225
o Glacier Park Co.
P.O. Box 3155
Osage 82723
Glenrock Refininq Co.
P.O. Box 992
Glenrock 82637
jp Husky Oil Co.
r£j P.O. Box 1583
t3 Cheyenne 82001
(D
^ Husky Oil Co.
H- P.O. Box 380
X Cody 82414
Johnson Oil Co.
La Barqe 83123
County
Natrona
Nicbrara
Weston
Converse
Laramie
Park
Lincoln
AQCR No.
241
243
243
241
242
243
243
Capacity
bbl/day
43,000
190
3,900
1,000
23,600
10,800
2,000
Attainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
(continued)
-------
OJ 13
\ (D
CO ft
O I-!
O
t-1
tt>
TABLE A-54. (continued)
Hi
H-
3
0>
H
3
O
REGION: VIII
STATE: Wyoming (continued)
Name and address of refinery
Little American Refining Co.
P.O. Box 510
Evansville 82636
Mountaineer Refining Co., Inc.
P.O. Box 127
La Barge 83123
Sage Creek Refining Co.
P.O. Box 37
Cowley 82420
Sinclair Oil Corp.
P.O. Box 227
Sinclair 82334
Southwestern Refining Co.
La Barge 83123
Texaco, Inc.
P.O. Box 320
Casper 82601
Wyoming Refining Co. (subsidiary of
Hermes Products)
' P.O. Box 820
Newcastle 82701
J. Totals 14
County
Natrona
Lincoln
Big Horn
Carbon
Lincoln
Nartona
Weston
AQCR Mo.
241
243
243
243
243
2/11
243
Capacity
bbl/day
24,500
600
1,200
72,000
1,500
21,000
10,500
215,790
Attainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
14 0
>
3
C
>
tt>
3
X
>
-------
00 ft
O H
O
TABLE A-55. BREAKDOWN OF OPERATING REFINERIES IN REGION IX.
(D
Mi
H-
3
(D
H
W
3
Hi
O
l-i
O
CD
3
0)
Arizona
California
Hawaii
Nevada
American Samoa
Guam
Totals
Total
refineries
1
41
2
1
0
1
46
Total capacity,
bbl/day
6,000
2,395,120
105,000
1,800
0
29,500
2,537,420
Refineries in
attainment
areas
1
0
2
1
0
1
5
Refineries in
nonattainment
areas
0
41
0
0
0
0
41
(D
H-
X
-------
CD rt
o i-t
O
M
(D
TABLE A-56. BREAKDOWN OF OPERATING REFINERIES IN ARIZONA
0)
Hi
H-
g
H
W
P
Hi
O
K
O
ffi
1
REGION: IX
STATE: Arizona
Name and address of refinery
Arizona Fuels, Inc.
Fredonia 86022
Totals 1
County
Coconino
AQCR No.
014
Capacity
bbl/day
6,000
6,000
Attainment area
for photochemical
oxidant standards
X
Nonattainment area
for photochemical
oxidant standards
0
OJ fl)
CD
-------
\ n>
00 ft
o n
O
TABLE A-57. BREAKDOWN OF OPERATING REFINERIES IN CALIFORNIA
REGION:
h" STATE:
IX
California
Name and address of refinery
W
H, Atlantic Richfield Co.
O 1801 E. Sepulveda Blvd.
£ Carson 90745
3 Basin Petroleum, Inc.
(D 1825 E. Spring
3 Long Beach 90806
> g Beacon Oil Co.
' f» 525 W. Third St.
^| g Hanford 93230
P)
M Champlin Petroleum
2402 E. Anaheim
Wilmington 90748
Chevron USA, Inc.
P.O. Box 5097
Bakersfield 93308
Chevron USA, Inc.
P.O. Box 97
El Segundo 90245
Chevron USA, Inc.
^ P.O. Box 1272
t3 Richmond 94802
(D
3
County
Los Angeles
Los Angeles
Kings
Los Angeles
Kern
Los Angeles
Contra Costa
AQCR No.
024
024
031
024
031
024
030
Capacity
bbl/day
180,000
10,700
12,100
31,000
26,000
405,000
365,000
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
H- (continued)
X
-------
U) h3
\ (D
00 ft
o h
O
TABLE A-57. (continued)
H-
3
(D
5 Name and address of refinery
W DeMenno Resources
P 2000 N. Alameda
O Compton 90222
£ Douglas Oil Co. of California
g P.O. Box 198
(D Paramount 90723
^ Douglas Oil Co. of California
g P.O. Box 1260
0) Santa Maria 93454
3
E ECO Petroleum, Inc.
P 1840 E. 29th St.
Signal Hill 90806
Edgington Oil Co.
2400 E. Artesia Blvd.
Long Beach 90805
Exxon Co. , USA
3400 E. 2nd St.
Benicia 94510
Fletcher Oil & Refining Co.
P.O. Box 548
»P Wilmington 90748
tf
O
/t\
County
Los Angeles
Los Angeles
Santa Barbara
Los Angeles
Los Angeles
Solano
Los Angeles
AQCR No.
024
024
032
024
024
030
024
Capacity
bbl/day
5,000
46,500
9,500
5,000
29,500
93,000
20,100
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
Ul
H-
>
(continued)
-------
\ n>
co rt
o h
O
M
(D
JO TABLE A-57. (continued)
[I!! REGION: IX
STATE: California (continued)
H Name and address of refinery
!? Golden Eagle Refining Co.
h 21,000 S. Flgueroa St.
O Torrance 90502
jjj Gulf Oil Co.
•3 13539 E. Foster Rd.
rt Santa Fe Springs 90670
pj Kern County Refining, Inc.
i!3 Route 6
g Bakersfield 93307
I— i
Lion Oil Co.
Bakersfield 93308
Lion Oil Co.
Martinez 94553
Lunday-Thagard Oil Co.
9301 Garfield Ave.
South Gate 90280
MacMillan Ring Free Oil Co., Inc.
2020 Walnut Ave.
Signal Hill 90806
rrj Mobil Oil Corp.
(D 3700 W. 190th St.
3 Torrance 90509
County
Los Angeles
Los Angeles
Kern
Kern
Contra Costa
Los Angeles
Los Angeles
Los Angeles
AQCR No.
024
024
031
031
030
024
024
024
Capacity
bbl/day
16,500
51,500
15,900
40,000
126,000
10,000
12,200
123,500
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
X
(continued)
-------
to *a
\ 0>
oo rt
o H
O
M
CD
TABLE A-57. (continued)
(D REGION: IX
•"h STATE: California (continued)
CD
^ Name and address of refinery
3 Mohawk Petroleum Corp. (subsidiary
M» of Reserve Oil and Gas Co.)
2 P.O. Box 1476
0 Bakersfield 93302
3 Newhall Refining Co., Inc. (owned
2 by Pauley Petroleum, Inc.)
£ P.O. Box 938
Newhall 91322
3
M Oxnard Oil Co.
H P.O. Box 258
f Oxnard 93032
Pacific Refining Co. (subsidiary
of Coastal States Gas Corp.)
P.O. Box 68
Hercules 94547
Power ine Oil Co.
12354 E. Lakeland Rd.
Santa Fe Springs 90670
Road Oil Sales, Inc.
P.O. Box 5356
Bakersfield 93308
£3 Sabre Oil S Refining, Inc.
(D 3121 Standard St.
3 Bakersfield 93308
County
Kern
Los Angeles
Ventura
Contra Costa
Los Angeles
Kern
Kern
AQCR No.
031
024
024
030
024
031
031
!
Capacity
bbl/day
-- , - i
Attainment area
for photochemical
oxidant standards
22,100
11,500
2,500
53,500
44,120
1,500
3,500
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
P; (continued)
X
>
I
^1
-------
OJ
oo rt
o i-f
O
M
(0
TABLE A-57. (continued)
JX) REGION:
(D STATE:
Hi
H-
(D
IX
California (continued)
Name and address of refinery
Union Oil Co. of California
P.O. Box 758
Wilmington 90744
USA Petrochemical Corp.
4777 Crooked Palm Rd.
Ventura 93001
West Coast Oil Co.
P.O. Box 5475
Oildale 93308
Witco Chemical Corp.
P.O. Box 5446
Oildale 93308
Totals 41
County
Los Angeles
Ventura
Kern
Kern
AQCR NO.
024
024
031
031
Capacity
bbl/day
108,000
20,000
19,000
11,000
2, 395, .120
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
41
HI
o
M
O
i
CD
fl>
H-
>
-------
\ CD
00 ft
o h
O
M
CD
TABLE A-57. (continued)
JO REGION: IX
fD STATE: California (continued)
H-
(D
*2 Name and address of refinery
H San Joaquin Oil Co.
3 P.O. Box 5576
g> Bakersfield 93308
O Shell Oil Co.
ffi P.O. Box 711
g Martinez 94553
ft Shell Oil Co.
^ ,., P.O. Box 6249
7 ft Wilmington 90749
vc C sierra Anchor Oil Refinery
P McKittrick 93251
Sunland Refining Corp.
P.O. Box 1345
Bakersfield 93302
Texaco, Inc.
P.O. Box 817
Wilmington 90748
Union Oil Co. of California
Route 1, P.O. Box 7600
Arroyo Grande 93420
£* Union Oil Co. of California
£ Rodeo 94572
(D
3 (continued)
County
Kern
Contra Costa
Los Angeles
Kern
Kern
Los Angeles
San Luis Obispo
Contra Costa
AQCR No.
031
030
024
031
031
024
032
030
Capacity
bbl/day
27,000
92,400
93,000
10,000
15,000
75,000
41,000
111,000
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
X
X
X
X
X
X
X
X
-------
\ CD
00 ft
o h
O
H
(D
TABLE A-58. BREAKDOWN OF OPERATING REFINERIES IN HAWAII
% REGION: IX
H, STATE: Hawaii
Name and address of refinery
Chevron USA, Inc.
P.O. Box 29789, Barber's Point
Honolulu 96820
Hawaii Independent Refinery
1060 Bishop St., Box 3379
Honolulu 96842
Totals 2
County
Honolulu
Honolulu
AQCR No.
060
060
Capacity
bbl/day
40,000
65,000
105,000
Attainment area
for photochemical
oxidant standards
X
X
2
Nonattainment area
for photochemical
oxidant standards
0
CD
t-f
W
P
l-h
O
n
o
(D
>
I
00
o
(D
H-
>
-------
OJ "T3
\(D
00 ft
o h
o
H
0>
TABLE A-59. BREAKDOWN OF OPERATING REFINERIES IN NEVADA
REGION: IX
STATE: Nevada
Name and address of refinery
Nevada Refining Co.
Tonopah 89049
Totals i
County
Nye
AQCR No.
147
i
Capacity
bbl/day
1,800
1,800
Attainment area
for photochemical
oxidant standards
-
X
1
Nonattainment area
for photochemical
oxidant standards
0
n
K
w
Hi
o
h
o
(D
ft
> £
I 3
CO £
13
CD
0
-------
U) >X)
\ CD
00 ft
0 H
O
(D
i
TABLE A-60. BREAKDOWN OF OPERATING REFINERIES IN AMERICAN SAMOA
H, REGION: IX
H- STATE: American Samoa
0>
H
._. Name and address of refinery
W
'"h None
O
O
(D
ft
> &
1 2
oo £
NJ P
13
fl>
P-
H- Totals 0
County
AQCR No.
Capacity
bbl/day
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
axidant standards
i
I i
i
0
i
0
0
-------
u> *a
\ n>
00 ft
O H
o
TABLE A-61. BREAKDOWN OF OPERATING REFINERIES IN GUAM
(D
Hi
H-
3
(D
H
REGION: IX
Guam
Name and address of refinery
Guam Oil & Refining Co.
P.O. Box 3190
Agana 96910
Totals i
County
AQCR No.
246
Capacity
bbl/day
29,500
29,500
Attainment area
for photochemical
oxidant standards
X
1
Nonattainment area
for photochemical
oxidant standards
0
O
(D
3
ft
CO,
<•*> i
(D
-------
\ CD
CO fl"
O I-!
O
H
CD
Hi
H-
3
(D
M
Hi
O
O
(D
00
TABLE A-62. BREAKDOWN OF OPERATING REFINERIES IN REGION X.
Alaska
Idaho
Oregon
Washington
Totals
Total
refineries
3
0
1
8
12
Total capacity,
bbl/day
82,600
0
14,000
380,900
477,500 _
Refineries in
attainment
areas
3
0
0
4
7
Refineries in
nonattainment
areas
0
0
1
4
5
(D
-------
\ (D
00 ft
O H
O
M
CD
TABLE A-63. BREAKDOWN OF OPERATING REFINERIES IN ALASKA
1K, REGION: X
H- STATE: Alaska
(D
Name and address of refinery
M
^ Chevron USA, Inc.
O Drawer F
H Kenai 99611
O
j=j North Pole Refining (Div. of
(D Earth Resources Co. of Alaska,
3 Energy Co. of Alaska)
>rt P.O. Box 5028
JgjS North Pole 99705
5 Tesoro-Alaskan Petroleum Corp.
5 P.O. Box 3691
M Kenai 99611
tJ
(D
H-Totals 3
County
Kenai -Cook
Inlet
Fairbanks
Kenai -Cook
Inlet
AQCR No.
008
009
008
Capacity
bbl/day
22,000
22,600
38,000
82,600
Attainment area
for photochemical
oxidant standards
X
X
X
3
Nonattainment area
for photochemical
oxidant standards
0
-------
\ CD
00 ft
o n
o
TABLE A-64. BREAKDOWN OF OPERATING REFINERIES IN IDAHO
Hi
H-
P
(D
M
Hi
O
h
O
(D
> ^
ig
C^ i-i
(D
(i
H-
REGION: X
STATE: Idaho
Name and address of refinery
None
Totals 0
County
AQCR No.
Capacity
bbl/day
0
Attainment area
for photochemical
oxidant standards
0
Nonattainment area
for photochemical
oxidant standards
0
-------
oo rt
o M
O
H
(D
Hi
fl>
TABLE A-65. BREAKDOWN OF OPERATING REFINERIES IN OREGON
REGION: X
STATE: Oregon
Name and address of refinery
County
AQCR No.
Capacity
bbl/day
Attainment area
for photochemical
oxidant standards
Nonattainment area
for photochemical
oxidant standards
5 Chevron USA, Inc.
5501 N.W. Front Ave.
M Portland 97210
rti
O
K
O
Multnomah
193
I
CO
C
H
TJ
V
Totals
14,000
14,000
P-
H-
X
-------
\ CD
00 ft
O H
o
H
(D
TABLE A-66. BREAKDOWN OF OPERATING REFINERIES IN WASHINGTON
(D REGION: X
HI STATE'- Washington
H-
3
CD
Name and address of refinery
Atlantic Richfield Co.
P.O. Box 1127
Ferndale 98248
Chevron USA, Inc.
Foot of Richmond Drive
Richmond Beach 98160
Mobil Oil Corp.
P.O. Box 8
Ferndale 98248
Shell Oil Co.
P.O. Box 700
Anacortes 98221
Sound Refining, Inc. (subsidiary of
Kalama Chemical, Inc.)
P.O. Box 1372
Tacoma 98401
Texaco, Inc.
P.O. Box 622
Anacortes 98221
United Independent Oil Co.
709 Alexander Ave.
Tacoma 98401
County
Whatcom
King
Whatcom
Skagit
Pierce
Skagit
Pierce
AQCR No.
228
229
228
228
229
228
229
Capacity
bbl/day
106,000
4,500
71,500
.
91 ,000
7,500
78,000
1,000
Attainment area
for photochemical
oxidant standards
X
X
X
X
Nonattainment area
for photochemical
oxidant standards
X
X
X
W
3
hh
O
h
O
(D
3
rf
> P?
I 3
CO £
00 {U
CD
3
(continued)
-------
\ CD
CO ft
O H
O
M
(D
0)
I
oo
vo
TABLE A-66. (continued)
REGION: X
STATE: Washington (continued)
H-
13
(D
^ Name and address of refinery
H U.S. Oil & Refining Co.
pj, 3001 Marshall Ave.
0 Tacoma 98401
0
(D
(D
ft
S
H
•r!
(D
^ Totals 8
County
Pierce
AG.CR No.
229
Capacity
bbl/day
21,400
380,900
Attainment area
for photochemical
oxidant standards
4
Nonattainment area
for photochemical
oxidant standards
X
4
-------
SUPPLEMENTAL INFORMATION
In the petroleum refining industry continual changes take
place in ownership, operation, and size of refineries. This
section is intended to clarify inventory omissions and to indi-
cate additions or changes that may be necessary in the near
future.
REFINERIES RECENTLY SHUT DOWN
Although the following U.S. refineries may have appeared on
earlier reference lists, they are omitted from the Appendix A
inventory because they have been recently shut down:
Region I:
Region II:
Region III:
Region IV:
Region V:
Region VI:
Region VIII:
Mobil Oil Corp., East Providence, Rhode
Island
Amerada Hess Corp., Port Reading, New Jersey
Wolf's Head Oil Refinery, Inc., Reno,
Pennsylvania
Young Refining Corp., Moundville, Alabama
Cities Service Oil Co., East Chicago, Indiana
Mobil Oil Corp., East Chicago, Indiana
Mobil Oil Corp., Woodhaven, Michigan
Petroleum Specialists, Inc., Flat Rock,
Michigan
Somerset Refinery, Inc., Troy, Indiana
Bayou Refining Co., Pasadena, Texas
Monarch Oil & Gas, San Antonio, Texas
Big West Oil Co. of Montana, Kevin, Montana
Jet Fuel Refining, Mosby, Montana
John Wight, Inc., Shelby, Montana,
temporarily shut down
Morrison Refining Co., Grand Junction,
Colorado
Oriental Refining Co., Greybull, Wyoming
Petroleum Refinery Enforcement Manual
3/80 A-90
Appendix A
-------
NEW REFINERIES*
The following companies either plan to build or are now
building new refineries in the locations indicated. When these
refineries are in operation, the inventory will be updated
accordingly.
Region I:
Region II:
Region III;
Region IV:
Region V:
Pittstone Oil Refinery, Eastport, Maine
Capacity: 250,000 bbl/day; Status: C
Virgin Islands Refinery Corp., St. Croix,
Virgin Islands
Capacity: 200,000 bbl/day; Status: E
Crown Central Petroleum Corp., Baltimore,
Maryland
Capacity: 200,000 bbl/day; Status: E
Hampton Roads Energy Co., Portsmouth, Virginia
Capacity: 184,100 bbl/day; Status: E,
1980
Steuart Petroleum Co., Piney Point, Maryland
Capacity: 100,000 bbl/day; Status: P
Wallace & Wallace Chem. & Oil Corp., Tuskegee,
Alabama
Capacity: 150,000 bbl/day; Status: C
Akron Hydrocarbons, Akron, Michigan
Capacity: 1,000 bbl/day; Status: E
(continued)
The following abbreviations are used in pages A-81 through A-84:
P In planning
E In engineering
C Under construction
1978, 1979, etc.
Projected year of
completion
N.A. Not available
To Total capacity after con-
struction
Re Being revamped, modernized,
or debottlenecked; not
reported whether increment
increase or final capacity
Ex Expansion; not classified
Petroleum Refinery Enforcement Manual
3/80 A-91
Appendix A
-------
Region VI: Dow Chemical Co., Freeport, Texas
Capacity: 210,000 bbl/day; Status: C,
1979
Harbor Refining Co., Derby, Texas
Capacity: 5,000 bbl/day; Status: E, 1979
Lake Charles Refining Co., Lake Charles,
Louisiana
Capacity: 30,000 bbl/day; Status: E, 1979
Refinery Services, Inc., Westwego, Louisiana
Capacity: N.A.; Status: P
Resource Refining Co., Lake Charles, Louisiana
Capacity: 30,000 bbl/day; Status: C
Tetrak Oil, Inc., Hahnville, Louisiana
Capacity: 30,000 bbl/day; Status: P
Region IX: Hawaiian Oil & Refining Co., Hawaii
Capacity: N.A.; Status: N.A.
Region X: Alpetco, Valdez, Alaska
Capacity: 150,000 bbl/day; Status: P,
1981
Cascade Energy, St. Helens, Oregon
Capacity: 30,000 bbl/day; Status: E, 1982
EXPANSIONS OF EXISTING REFINERIES
The following companies are expanding or modernizing their
existing refineries. Upon completion of each project, it will be
necessary to change the capacity entry in this inventory.
Region III: Elk Refining Co., Falling Rock, West Virginia
Capacity: N.A., Ex; Status: N.A.
Region IV: Ashland Oil, Inc., Catlettsburg, Kentucky
Capacity: 25,000 bbl/day, Re; Status: C
Marion Corp., Mobile, Alabama
Capacity: 5,000 bbl/day; Status: P, 1980
Mobile Bay Refining Co., Chickasaw, Alabama
Capacity: 10,000 bbl/day; Status: C
Seminole Asphalt & Refining, Inc., St. Marks,
Florida
Capacity: 6,000 bbl/day; Ex; Status: C
Warrior Asphalt of Alabama, Tuscaloosa,
Alabama
Capacity: N.A.; Status: C
Region V: Bi-Petro, Inc., Pana, Illinois
Capacity: 4,500 bbl/day; Status: C
Total Petroleum, Alma, Michigan
Capacity: 15,000 bbl/day, Ex; Status:
N.A.
Region VI: Amoco Oil Co., Texas City, Texas
Capacity: 47,000 bbl/day, Ex; Status: C,
1979
Capacity: N.A., Re; Status: U, 1979
Petroleum Refinery Enforcement Manual Appendix A
3/80 A-92
-------
Region VI:
(Continued) Atlas Processing Co., Shreveport, Louisiana
Capacity: 60,000 bbl/day, To; Status:
C
Cities Service Co., Lake Charles, Louisiana
Capacity: N.A., Re; Status: E, 1978
Continental Oil Co., Westlake, Louisiana
Capacity: 100,000 bbl/day, Ex; Status:
E, 1980
Good Hope Refineries, Inc., Good Hope,
Louisiana
Capacity: 60,000 bbl/day; Status: C,
1978
Gulf States Oil & Refining Co., Corpus Christi,
Texas
Capacity: 30,000 bbl/day, To; Status: P,
1979
Kerr-McGee Corp., Wynnewood, Oklahoma
Capacity: 50,000 bbl/day, To; Status: E,
1979
LaGloria Oil & Gas Co., Tyler, Texas
Capacity: 17,000 bbl/day, Ex; Status: E,
1979
Lion Oil Co., El Dorado, Arkansas
Capacity: 36,500 bbl/day, Re; Status: C
Marathon Oil Co., Garyville, Louisiana
Capacity: N.A., Ex; Status: E, 1979
Mid Tex Refining Co., Hearne, Texas
Capacity: 7,500 bbl/day; Status: C, 1978
Phillips Petroleum Corp., Sweeny, Texas
Capacity: 190,000 bbl/day, To; Status:
E, 1979
Placid Refining Co., Port Allen, Louisiana
Capacity: 42,000 bbl/day; Status: E
Sigmore Refining Co., Three Rivers, Texas
Capacity: 20,000 bbl/day, To; Status: E,
1978
Thriftway Oil Co., Graham, Texas
Capacity: 3,000 bbl/day; Status: C
Uni Oil, Ingleside, Texas
Capacity: 20,000 bbl/day, Ex; Status: C,
1979
Region VIII: Asamera Oil, Inc., Commerce City, Colorado
Capacity: 30,000 bbl/day; Status: E,
1979
C & H Refinery, Inc., Lusk, Wyoming
Capacity: 3,310 bbl/day; Status: C
Exxon Co. USA, Billings, Montana
Capacity: N.A.; Status: C, 1978
Husky Oil Co., Cheyenne, Wyoming
Capacity: 30,000 bbl/day; Status: C,
1978
Petroleum Refinery Enforcement Manual Appendix A
3/80 A-93
-------
Region IX: Atlantic Richfield Co., Carson, California
Capacity: 20,000 bbl/day, Ex; Status: P
DeMenno Resources, Compton, California
Capacity: 8,000 bbl/day, To; Status: C,
1978
Lion Oil Co., Bakersfield, California
Capacity: N.A., Re; Status: P, 1979
Mohawk Petroleum Corp., Bakersfield, California
Capacity: 33,000 bbl/day, Ex; Status: E,
1979
Pacific Refining Co., Hercules, California
Capacity: 20,000 bbl/day; Status: C
Sabre Oil & Refining, Inc., Bakersfield,
California
Capacity: 10,000 bbl/day, To; Status: C,
1978
Union Oil Co. of California, Rodeo, California
Capacity: N.A., Re; Status: E, 1979
U.S.A. Petrochemical Corp., Ventura, California
Capacity: 15,000 bbl/day, Ex; Status: E,
1979
REFINERIES NOT MEETING SIC CODE 2911
The following companies may be listed as petroleum refineries
in other references, but they have been omitted from this inventory
because they do not meet the criteria for SIC Code 2911 (Petroleum
Refining):
Region III: Chevron U.S.A., Inc., Baltimore, Maryland
No longer refines crude oil.
Region VI: Dorchester Gas Producing Co., White Deer, Texas
Does not sell any SIC 2911 refinery
products.
Monsanto Chemical Co., Texas City, Texas
Buys gas well distillates to use as
feedstocks to olefin units. Residuals are
sold to refineries in the Texas City area
for refining; therefore, Monsanto does not
sell any SIC 2911 refinery products.
Region X: Alyeska Pump Stations, Alaska
Topping plants 6, 8, and 10 distill diesel
fuel off of crude oil from the Alaskan
Pipeline and use this fuel to run pipe-
line pumps. No products are sold. There-
fore, these plants do not meet the SIC
criteria for refineries.
Petroleum Refinery Enforcement Manual Appendix A
3/80 A-94
-------
APPENDIX B
SIMPLIFIED THEORY OF REACTORS
Under appropriate conditions, feed materials may be trans-
formed in a reactor into new and different materials that consti-
tute different chemical species. If this transformation occurs
by rearrangement or redistribution of structures, a chemical
reaction has occurred.
Reactor design theory incorporates knowledge of thermo-
dynamics, chemical kinetics, fluid mechanics, heat transfer, mass
transfer, and economics. Principles of thermodynamics provide
the designer with two important pieces of information: the
amount of heat to be liberated or absorbed during reaction and
the maximum possible extent of reaction (that is, the maximum
potential yield of the products of a reaction). Principles of
chemical kinetics deal with the mode and mechanisms of a reac-
tion, the physical and energy changes involved, and the rate of
formation of products.
A reaction is classified as homogeneous if it occurs in one
phase (such as entirely in the vapor phase) or as heterogeneous
if the reaction requires at least two phases (such as liquid and
vapor phases). Cutting across this classification is the cataly-
tic reaction, whose rate is altered by a material that is neither
a reactant nor a product. Such a material, called a catalyst,
may either impede or accelerate the reaction process while its
own physical and chemical characteristics are modified relatively
slowly, if at all. A catalyst that impedes a reaction is called
a negative catalyst, and one that accelerates a reaction is
called a positive catalyst. Although catalysts may be solids or
fluids, in petroleum refining they are most often solids.
Petroleum Refinery Enforcement Manual Appendix B
3/80 B-l
-------
A solid-catalyst reaction usually involves high-energy
rupture or high-energy synthesis of materials. In processes
where a variety of reactions occur the catalyst may be selective,
changing the rates of only certain reactions (often a single
reaction) without affecting the rates of others. Thus, in the
presence of a specific catalyst, a given feed may yield a reac-
tion product containing relatively uniform types and concentra-
tions of materials.
Catalyst activity decreases as the catalyst is used. The
term "fouling" is often used if catalyst deactivation is rapid
and is caused by deposition of a solid that physically blocks the
catalytic surface. Removal of this solid is referred to as
regeneration. Deposition of carbon during catalytic cracking is
an example of fouling, after which the deactivated catalyst is
regenerated or replaced.
Poisoning of the catalyst can occur if its active surface is
modified by chemisorption (chemical adsorption) of materials that
are not easily removed. When catalyst activity can be restored
after poisoning, the restoration process is called reactivation.
When the adsorption is reversible, a change in operating condi-
tions may be sufficient to regenerate the catalyst. When the
adsorption is not reversible, the poisoning is permanent. The
surface of the catalyst may be treated chemically, or the spent
catalyst may be replaced.
Many variables other than the catalysts affect the rate of a
chemical reaction. In both homogeneous and heterogeneous systems
the temperature, pressure, and composition are variables. In
heterogeneous systems, the rate of mass and heat transfer may
also be variables.
Petroleum Refinery Enforcement Manual Appendix B
3/80 B-2
-------
APPENDIX C
BASIC PRINCIPLES OF FRACTIONATION
Fractionation may be broadly defined as any method in which
a liquid or vapor mixture is separated into individual components
by vaporization or condensation. The components may be pure
compounds, or, if the original material is a complex mixture,
they may be products that are still mixtures but whose distilla-
tion range is limited by the fractionation process. The various
means of separation are given special names: distillation,
fractionation, stabilization, absorption, and stripping. The
glossary gives simple definitions of these terms.
Fractionation is based on the difference in equilibrium
composition of the liquid and vapor phases. The main function of
industrial equipment for vapor-liquid transfer operations is to
provide for the intimate contact of vapor and liquid phases and
for subsequent separation and handling of the products of frac-
tionation. In typical equipment, vapors may bubble through a
continuous liquid phase, droplets of liquid may fall through a
continuous vapor phase, an extended interface may provide contact
between the two phases, or these methods may be used in combina-
tion.
Fractionating towers and related equipment are mechanical
devices that repeatedly establish equilibrium between ascending
vapor and descending liquid, and repeatedly separate the two
phases. Duration and violence of the contact are of little
significance; any sucessful design, however, must incorporate a
means of .attaining a large interface for contact and of com-
pletely separating the two phases.
Petroleum Refinery Enforcement Manual Appendix C
3/80 C-l
-------
A plate tower is a fractionating tower in which the vapor
and liquid phases flow countercurrently. A typical arrangement
consists of a vertical shell in which are mounted a large number
of equally spaced circular plates. At one side of each plate, a
conduit known as a downcomer allows passage of liquid to the
plate below. At the opposite side of the plate, a similar con-
duit feeds liquid from the plate above.
A bubble-cap plate is pierced with holes into which are
fitted risers or "chimneys," through which vapors from the plate
below may pass. The vapors rise through the chimneys, are di-
rected downwards by the cap, and are discharged as small bubbles
from slots or notches at the bottom of the cap beneath the liquid.
A weir maintains the liquid level on the plate. Liquid fed to
the plate passes across it and through the downcomers to the
plate below; the vapors pass upward through the plate, mixing
intimately with the liquid on the plate because of dispersion
produced by the slots in the bubble caps. The vapors separate at
the liquid surface and pass to the plate above. A plate tower
with bubble caps is sometimes called a "bubble tower."
A perforated plate, or sieve plate, is pierced with small
holes that replace the bubble-cap assembly. The passage of
vapors through the perforations prevents liquid from draining
through them. The tower has weirs and downcomers identical to
those used in a bubble-cap tower.
A valve tray is perforated with openings of variable areas
for gas flow. The perforations are covered with movable caps,
which rise as the flow rate of gas increases. Action of the gas
prevents liquid from flowing through the perforations. At low
flow rates, the liquid does not drain through the perforations
because the valves close.
The packed tower consists of a vertical shell filled with
packing material. The liquid flows over the surface of the
packing in thin films and thereby presents a large surface for
contact with ascending gases. The packing is supported on a
grid. The liquid is introduced at the top of the packing by
Petroleum Refinery Enforcement Manual Appendix C
3/80 C-2
-------
means of a distribution plate (a perforated plate), and the vapor
is introduced beneath the grid that supports the packing. A
packed tower offers the advantages of multiple contact and coun-
tercurrent flow, but the efficiency of contact is usually lower
than that obtained in a plate-type tower.
In computing the degree of fractionation to be accomplished
in a fractionating system, the designer must know the relation-
ship between the compositions of the liquid and the vapor at
equilibrium. The designer either uses experimental data or
computes the needed data from known laws.
In determining the number of trays or plates in a tower, the
designer first calculates the number of theoretical plates re-
quired. That is, he assumes ideal contacting and other condi-
tions to determine the number of plates required to perform the
desired separation. The overall efficiency of the tower is the
ratio of the theoretical number of plates to the actual number
required for a particular separation.
A fractionating tower must operate between two impractical
extremes. At one extreme, the reflux rate is the minimum that
can be used, and an infinite number of plates is required; at the
other, the reflux rate is infinite and a minimum number of plates
is required. In practice, the engineer must decide whether it is
more economical to purchase a large number of plates or to oper-
ate at a higher daily operating cost.
Petroleum Refinery Enforcement Manual Appendix C
3/80 C-3
-------
APPENDIX D
SELECTED PHYSICAL PROPERTIES OF COMMON PETROCHEMICAL COMPOUNDS
The table found in this appendix lists various petrochemical
compounds and their true vapor pressure at various temperatures.
These data are useful in determining the type of storage vessel
and vapor control equipment required to store a given material.
Petroleum Refinery Enforcement Manual Appendix D
3/80 D-l
-------
Petroleui
3/80
cf
(D
H,
H-
(D
H
^
M
O
H
o
3
(D
OS
»-5
£
(U
>
•o
(D
s
H-
t)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
IABLL D-T SELECTED PHYSICAL -PROPERTIES OF COMMON PETROCH
Chemical names and abbreviations
Acetic acid (AcOH or IUPAC), ethanoic acid
Acetone (DMK)
Acetonitrile
Acrylonitrile
Allyl alcohol
Allyl chloride
Ammonium hydroxide (28.8% solution)
Benzene
Butyl "Cellosolve"b (see No. 49}
Butyl "OxitoT'c (BUOX), 2-butoxyethanol
Butyl formated
Butyl methacrylate, butyl acrylate
Butyl phenol
Isobutyl acetate (IBAc)
Isobutyl alcohol (IBA or IBUOH)d
Isobutyl isobutyrate (IB IB)
n-Butyl acetate (NBAc)
n-Butyl alcohol (NBA)
Secondary butyl alcohol (SBA)
Tertiary butyl alcohol (TBA)
n-Butyl chloride
Diisobutylene, dii?obutene
EMICAL
True vapor pressure,
60°F 70°F
0.2 0.3
2.9 3.7
1.1 1.4
1.4 1.8
0.3 0.4
4.8 6.0
8.5 10.8
1.2 1.5
0.3 0.4
0.1 0.1
Negligible
0.2 0.3
0.1 0.2
0.2 0.3
0.1 0.2
0.1 0.1
0.2 0.3
0.5 0.6
1.3 1.7
80 °F
0.3
4.7
1.9
2.4
0.5
7.4
13.5
2.0
0.6
0.1
0.4
0.3
0.4
0.2
0.2
0.4
0.9
2.2
COMPOUNDS
psiaa
90°F
0.5
6.0
2.5
3.1
0.7
9.1
16.8
2.6
0.8
0.2
0.5
0.4
0.5
0.3
0.2
0.6
1.2
2.7
(continued)
-------
TABLE D-l (continued)
to ha
\(t»
00 rt
O
(D
(D
H,
H-
(D
•3
g
O
O
(D
3
rt
02
I ft)
U) 0
c
-0
•o
(D
a
H-
t-l
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Chemical names and abbreviations
. Carbon disulfide
. Carbon tetrachloride
. "Cellosolve"b solvent (see
following)
. Chloroform
. Chloroprene
. Cumene (isopropyl benzene)
. Cresylic acid (Cresol)6
. Cyclohexane
. Cyclopentane
. n-Decyl alcohol (1-decanol
. Diacetone alcohol (see No.
. 1, 1-Dichloroethane
. 1, 2-Dichloroethane
. cis -1, 2-Dichloroethylene
No. 51
)
57)
. trans-1 , 2-Dichloroethylene
. Di ethyl ether
. Di ethyl ami ne
. Diisobutyl ketone
. Di isopropyl ether
. 1-4 Dioxane
. Dipropyl ether
True vapor pressure,
60° F
4.8
1.4
2.5
2.9
0.1
0.2
1.2
4.2
70° F
6.0
1.8
3.2
3.7
0.1
0.3
1.6
5.2
80° F
7.4
2.3
4.1
4.6
0.1
0.5
2.1
6.5
psiaa
90° F
9.2
3.0
5.2
5.7
0.2
0.8
2.6
8.1
Negligible
2.9
1.0
2.7
4.4
7.0
2.9
2.1
0.4
0.8
3.8
1.4
3.5
5.5
8.7
3.9
2.7
0.6
1.1
4.7
1.7
4.4
6.8
10.4
4.9
3.5
0.3
1.4
5.8
2.2
5.6
8.3
13.3
6.1
4.3
1.1
1.9
(continued)
-------
TABLE D-1 (continued)
to no
\n>
oo rt
0 H
o
H-1
0>
3
PC
(D
Hi
H-
0>
*<
M
HI
O
o
0>
0)
ft
D«^
»!5
1 0J
it* 0
M
e
•o
p.
X
o
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
Chemical names and abbreviations
. Ethyl acetate (EAc)
. Ethyl acrylate
. Ethyl alcohol
. Ethyl amyl ketone (EAK)
5-methyl -3-hexanone
. Ethyl glycol
. Ethyl ene glycol di ethyl ether
Ethyl ene glycol monobutyl ether
. Ethyl ene glycol monoethyl ether
. Ethyl ene glycol monomethyl ether
(see Nos. 73 and 83)
. "Freon ll",e trichlorofluoromethane
. n-Heptane
. n-Hexane
. Hexylene glycol (HG),
2-methyl-2,4 pentane-diol
. Hydrogen cyanide (HCN)
. 4-Hydroxy-4 methyl -2 pentanone
(same as No. 32)
. Isobutyl acetate (IBAc)
(see No. 13)
. Iso-octane
. Isopentane
. Isoprene
True vapor pressure,
60 °F 70 °F
1.1 1.5
0.4 0.6
0.6 0.9
Negligible
Negligible
0.2 0.2
0.1 0.2
10.9 13.4
0.5 0.7
0.9 2.4
9.5 11.9
9.5 11.9
Negligible
0.5 0.8
10.0 12.5
7.7 9.7
80 °F
1.9
0.8
1.2
0.2
0.3
16.3
1.0
3.1
15.4
15.4
1.1
15.3
11.7
psiaa
90°F
2.5
1.1
1.7
0.2
0.4
19.7
1.2
3.9
18.6
18.6
1.4
18.4
14.5
(continued)
-------
TABLE D-1 (continued)
oo rt
O
CD
1
(D
H,
H-
n>
*s
w
&
«_j
n
O
0)
n>
rt
D 2
1 P^
^n bJ
Oj
|-1
§
CD
H-
O
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
Chemical names and abbreviations
. Isopropyl alcohol (IPA)
. Isopropyl ether (IPE)
. Mesityl oxide (MO, isopropylideneace-
tone)
. Methanol6 (methyl alcohol, carbinol,
MEOH)
. 4-Methoxy-4 methyl -pentanone-2,
pent-oxone (see No. 91)
. Methyl acetate
. Methyl aery late
. Methyl alcohol (see No. 65)
. Methyl amyl acetate (MAAc)
. Methyl amyl alcohol (MIBC), methyl -
isobutyl carbinol
. Methyl butyl keton (MBK)
. Methyl "Cellosolve"f (see Nos-. 51 and
83)
. Methacrylonitrile
. Methyl eye lohexane
. Methyl cyclopentane
. Methyl ene chloride
. Methyl ethyl ketone (MEK)
. Methyl isobutyl acetate (MIBAc)
isopropyl acetate
True vapor pressure,
60°F
0.5
2.1
0.1
1.4
2.7
1.0
Neg.
0.9
0.5
1.6
5.4
1.2
70°F
0.7
2.8
0.1
2.0
3.7
1.4
0.1
1.2
0.7
2.2
6.8
1.5
80° F
0.9
3.6
0.2
2.6
4.7
1.8
0.1
1.5
1.0
2.9
8.7
2.1
psiaa
90°F
1.3
4.6
0.3
3.5
5.8
2.4
0.1
1.9
1.3
3.6
10.3
2.7
(continued)
-------
TABLE D-1 (continued)
oo rt
o H
O
(D
(D
H»
H-
W
S>
H
O
0>
3
0)
OS
•o
(D
Chemical names and abbreviations
80.
81.
82.
83.
84.
85.
86.
87.
88.
89.
90.
91.
92.
93.
94.
95.
96.
97.
98.
99.
Methyl isobutyl carbinol (MIBC, see
No. 71)
Methyl isobutyl ketone (MIBK)
Methyl methacrylate
Methyl "Oxitol"c (see Nos. 51 and 73)
Methyl propyl ether
Naphthenic acid, hexahydrobenzoic acid
cyclohexanecarboxylic acid
"Neosol A"c>9
Nitromethane
"Oxitol"c (see. Nos. 51, 73, and 83)
n-Pentane
"Pentoxone"0 (see No. 66)
Perch loroethyl ene , tetrachl oroethyl ene
Propyl acetate
n-Propylamine
Sty rene , pheny 1 -ethyl ene
Super VM and P-66c'h'n
Tetrahydrofuran (THF)
Toluene
"Tolu-Sol 6"c'h
1,1, 1-Trichloroethane
True vapor
60 °F
0.1
0.3
6.1
0.6
0.3
6.8
0.2
0.4
4.2
0.1
0.2
2.1
0.3
0.6
1.6
pressure,
70°F
0.1
0.5
7.1
0.9
0.5
8.4
0.3
0.5
5.3
0.1
0.3
2.6
0.4
0.8
2.0
80°F
0.2
0.8
9.4
1.2
0.7
10.4
0.4
0.7
6.5
0.2
0.3
3.3
0.6
1.0
2.6
psiaa
90°F
0.2
1.1
11.6
1.7
1.0
13.0
0.5
0.9
8.0
0.2
0.4
4.1
0.7
1.4
3.3
(continued)
-------
TABLE D-l (continued)
oo
o
o
n>
so
Hj
H-
g
M
CJ
HI
O
H
O
0)
03
I 0)
SU
Chemical names and abbreviations
100
101
102
103
. Trichloroethylene
. Vinyl acetate
. Vinyl idene chloride
. Xylene >J (meta-, ortho- and para-)
True vapor pressure, psiaa
60PF 70° F 80»F 90° F
0.9 1.2 1.5 2.0
1.3 1.7 2.3 3.1
7.9 9.8 11.8 15.3
0.1 0.1 0.2 0.2
a All values are from API Bulletin entitled Petrochemical Evaporation Loss From
'Storage Tanks, Bulletin No. 2523, 1st ed., November 1969, unless otherwise
indicated. Metric conversion factors are as follows: "F = 9/5 (°C) + 32;
psia = 6.8947 kPa.
Union Carbide trademark.
c Shell Chemical Company trademark.
d Weast, R. C. Handbook of Chemistry and Physics. 55th ed. CRC Press
Cleveland, Ohio, 1974.
e Dean, J. A. Lang's Handbook of Chemistry, llth ed. McGraw-Hill Company,
New York, 1973. pp. 10-31/10-45.
du Pont trademark.
9 Bureau of Internal Revenue approved denatured alcohol
No. 1 (190 proof) 100 parts by volume
Methyl isobutyl ketone 1 part by volume
Ethyl acetate 1 part by volume
Aviation gasoline 1 part by volume
(For calculations, use ethyl alcohol, No. 45)
h Shell Oil Company data, Dominguez Research Laboratories, October 28, 1975.
1 Molecular weight is a calculated value based on boiling point range.
J Kirk-Othmer Encyclopedia of Chemical Technology. 2nd ed., Vol. 22. John Wiley
& Sons, New York, 1970. p. 486.
(D
3
H-
X
-------
APPENDIX E
STORAGE TANK INSPECTION BY STATISTICAL SAMPLING
During a Level II or Level III inspection, a number of
storage tanks are checked to determine compliance with state and
Federal regulation of hydrocarbon emissions. From both a time
and cost viewpoint, it is impractical to check every storage tank
in a refinery. A statistical sampling approach enables the
inspector to test only a small percentage of the total number of
tanks in a refinery and thereby to determine with confidence the
compliance status of the entire tank farm. The statistical
technique to be applied is acceptance control. The objective is
to ensure that the final product (in this case, storage tanks) is
consistent with a specified quality, i.e., is in compliance with
state and Federal regulations. Four general types of acceptance
control are practiced: spot checks, 100% inspection, certifica-
tion, and acceptance sampling.
Acceptance sampling by attributes (go/no-go) is widely
accepted as the preferred method of acceptance control. Tables,
charts, and graphs have been developed to facilitate implementa-
tion of acceptance sampling and selection of specific sampling
1 ?
plans. The guidelines MIL-STD-105D and MIL-STD-404 are sources
of widely used information on military acceptance control. These
standards define a range of acceptable quality levels (AQL),
which limit the percentage of allowable defects. The charts
developed for acceptance sampling define criteria for the size of
the sample to be tested based on the size of the production lot
(i.e., number of storage tanks in a refinery) and also define
criteria for the maximum number of defective units permitted in
the sample. When these criteria are met, the probability of
Petroleum Refinery Enforcement Manual Appendix E
3/80 E-l
-------
accepting lots with this defective rate is specified by the
applicable plan. The inherent risk in all acceptance sampling
plans is rejecting lots that should be accepted, and vice versa.
Acceptance sampling evaluates a group of units, drawn from a
production lot, in order to assess the acceptability of the whole
lot. Since only a portion of the whole lot is inspected, there
is always a risk that the quality of the sample will not reflect
the quality of the lot. As a result, lots may be rejected unde-
servedly and faulty lots accepted. The former situation is
mainly of interest to the producer (refinery owner), who wants to
minimize the risk of having good lots rejected, and is defined as
the producer's risk. The risk of accepting bad lots in a sam-
pling scheme is mainly the concern of the consumer (inspector),
and is called the consumer's risk. Both risks are quantified
statistically by constructing an operating characteristic curve
(OC curve).
The producer's risk, 'a', is the probability of having
production lots rejected as a result of a sampling plan, even
though they meet the specified acceptable quality requirements.
The most frequently used value for the producer's risk is 0.05.
This means the producer has a 95 percent chance of having produc-
tion lots accepted that meet the quality requirements.
The consumer's risk, 'b1, is the probability of accepting
production lots that do not meet the poorest tolerable quality
requirements. The risk assumed by the consumer is usually set at
0.1 or 10 percent. This quality level is designated as the lot
tolerance percent defective (LTPD). The consumer has a 90 per-
cent chance that the sampling plan will reject production lots of
LTPD quality.
The acceptable quality level (AQL) is the maximum percentage
of defective units that, for purposes of the sampling inspection,
can be considered satisfactory as a process average (the lot has
a high probability of acceptance, usually 95 percent).
Petroleum Refinery Enforcement Manual Appendix E
3/80 E-2
-------
The lot tolerance percent defective (LTPD) is that quality
level (in percent defective) that has a low probability of ac-
ceptance, usually 10 percent. The usual sampling plan therefore
accepts good lots (lot quality = AQL) 95 percent of the time and
rejects the not-quite-so-tolerable lots (lot quality = LTPD) 90
percent of the time. Lot quality levels between the AQL and LTPD
values have probabilities of acceptance as defined by the OC
curve, which is a graph depicting the relationship between pro-
cess defect percentage and the corresponding probability of
acceptance of such lots by the sampling plan. A typical OC curve
is shown in Figure E-l.
Points "a1 and fbf on the OC curve refer, respectively, to
the AQL and the LTPD. These probability percentages agree with
the common AQL and LTPD acceptance probabilities. The OC curve
permits the determination of the probability of acceptance for
lots of varying quality. For example, in Figure E-l the proba-
bility of acceptance can be determined for any lot defective rate
between zero and 12 percent. For a submitted lot that is 3
percent defective, the probability of acceptance is 70 percent
(see point "P1).
A sampling plan and its associated OC curve are fully de-
fined by the sample size, 'n1, and the acceptance number, 'c1. A
range of values of percentage defective 'p1, is assumed, and the
expected number of defects, 'np1, is calculated. Then the Pois-
son distribution is used to determine the probability of 'c' or
fewer defectives occurring for each value of 'np1. This is the
probability of acceptance and is plotted against the percent
defective as the OC curve. Values of the acceptance number
depend on the particular level of quality desired and the amount
of protection afforded by the plan. The MIL-STD-105D contains a
large number of inspection plans that define sample size and
accept/reject numbers as related to acceptable quality levels and
OC curves. The guideline is used to define the inspection plan
for each refinery tank farm inspected.
Petroleum Refinery Enforcement Manual Appendix E
3/80 E-3
-------
I I I I I I I I
on
o
M
0>
0>
Mi
H-
0
(D
n
w
d
Mi
o
h
o
I
MS
(U
I
(B
H-
X
w
3456789 10
QUALITY OF LOTS SUBMITTED (IN PERCENT DEFECTIVE)
11 12
Figure E-l. Typical operating characteristic curve for. sampling plan.
-------
For a given lot size (number of tanks in the refinery), a
sample size can be determined depending on the inspection level
desired. In MIL-STD-105D, a code letter designates the inspec-
tion sample size. There are three general inspection levels: I,
II, and III. Inspection Level I provides less discrimination (60
percent less than Level II) because it uses smaller sample sizes;
Level III increases the discrimination to 1.6 times that of a
Level I inspection because of larger sample sizes for the same
lot size.
Four special inspection levels are designated 's-, ' through
's4'. These special levels are used when the inspection involves
destructive testing or when the cost of inspection is high.
After selection of the inspection level and corresponding
sample size, the acceptance and rejection numbers are determined
for varying acceptable quality levels. For each sample inspect-
ed, the entire lot is considered acceptable (passes the inspec-
tion) if the number of defectives found (tanks not passing the
inspection) is equal to or less than the acceptance number. If
the number of defectives exceeds the acceptance number, the lot
is rejected (the tank farm does not pass the inspection). Appen-
dix F contains selected tables from MIL-STD-105D.
For the refinery tank farm inspections (Level II and III in-
spections), sample sizes have been determined and the acceptance
number chosen for two different acceptable quality levels. A
Level II inspection is based on a MIL-STD-105D inspection level
of I and an acceptable quality level of 10. A Level III inspec-
tion is based on a MIL-STD-105D inspection level of II and an
acceptable quality level of 4. Table E-l summarizes the sampling
plan for the two levels of refinery inspections.
Plans for double and multiple sampling are also available.
Inspection plans for double sampling give two sample sizes per
sample size code letter with the corresponding acceptance and
rejection number. Inspections start with the first sample size
and the applicable accept/reject criterion. As in the single
sampling plan, if the number of defectives found is equal to or
Petroleum Refinery Enforcement Manual Appendix E
3/80 E-5
-------
TABLE E-l. REFINERY TANK INSPECTION PLAN
No. of tanks
2 to 8
9 to 15
16 to 25
26 to 50
51 to 90
91 to 150
151 to 280
281 to 500
Inspection
level
2
3
2
3
2
3
2
3
2
3
2
3
2
3
2
3
Sampl e
size
2
3
2
3
3
5
5
8
5
13
8
20
13
32
20
50
Accept
No.
1
0
1
0
1
0
1
1
1
1
2
2
3
3
5
5
Reject
No.
2
1
2
1
2
1
2
2
2
2
3
3
4
4
6
6
Petroleum Refinery Enforcement Manual
3/80 E-6
Appendix E
-------
less than the accept number, the lot is accepted. If the number
of defectives exceeds the accept number and is equal to or great-
er than the reject number, the production lot is rejected.
If the number of defectives found in the first sample is
between the first acceptance and rejection numbers, a second
sample of the size given by the plan is inspected. If the sum of
the number of defectives found in the first and second inspection
samples equals or is less than the second acceptance number, the
lot is accepted. If the sum of the number of defectives in the
first and second inspection samples is equal to or exceeds the
second rejection number, the lot is rejected.
Multiple sampling plans are an extension of the double
sampling plans. The difference is that more than two successive
samples may be needed as a basis for decision regarding the
acceptance of the production lot.
Storage tanks can be categorized in two broad classes:
floating roof and fixed roof. Each group should be individually
inspected in the sampling plan so far submitted. Once the in-
spector has determined the number of tanks in each classifica-
tion, he can determine the sample size and accept/reject cri-
terion for each group. Each tank should have an individual tank
number and be listed on a master sheet (provided by the refin-
ery). A random number generator can be used to select the tanks
for the sample lot.
REFERENCES
1. U.S. Department of Defense. Sampling Procedures and Tables
for Inspection by Attributes. MIL-STD-105D. April 29, 1963.
2. U.S. Department of Defense. Sampling Procedures and Tables
for Inspection by Variables. MIL-STD-414. June 11, 1957.
Petroleum Refinery Enforcement Manual Appendix E
3/80 E-7
-------
APPENDIX F
MIL-STD TABLES FOR USE IN STATISTICAL SAMPLING OF STORAGE TANKS
Table F-l contains sample size code letters. An inspector
is to determine the lot or batch size (i.e., the number of tanks)
and select the type and level of inspection to be performed; the
sample size code letter can be determined from Table F-l based on
this information. The sample size and the accept and reject
numbers are presented in Tables F-2 and F-3. Appendix E contains
further information on the use of these tables.
REFERENCE
1. U.S. Department of Defense. Sampling Procedures and Tables
for Inspection by Attribute. MIL-STD 105D. April 29, 1963.
Petroleum Refinery Enforcement Manual Appendix F
3/80 F-l
-------
TABLE F-l. SAMPLE SIZE CODE LETTERS
Lot or batch size
2 to 8
9 to 15
16 to 25
26 to 50
51 to 90
91 to 150
151 to 280
281 to 500
501 to 1200
1201 to 3200
3201 to 10000
10001 to 35000
35001 to 150000
150001 to 500000
500001 and over
Special inspection levels
S-l
A
A
A
A
B
B
B
B
C
C
C
C
D
D
D
S-2
A
A
A
B
B
B
C
C
C
D
D
D
E
E
E
S-3
A
A
B
B
C
C
D
D
E
E
F
F
G
G
H
S-4
A
A
B
C
C
D
E
E
F
G
G
H
J
J
K
General inspection levels
I
A
A
B
C
C
D
E
F
G
H
J
K
L
M
N
II
A
B
C
D
E
F
G
H
J
K
L
M
N
P
0
III
B
C
D
E
F
G
H
J
K
L
M
N
P
Q
R
Petroleum Refinery Enforcement Manual
3/80 F_2
Appendix F
-------
co IT)
\(D
oo rt
o n
o
M
fD
TABLE F-2. SINGLE SAMPLING PLANS FOR NORMAL INSPECTION
(MASTER TABLE)
H,
H-
3
(D
13
Hi
O
H
O
(D
(D
to
0>
y
0)
Sample
size
code
letter
A
B
C
D
E
F
G
H
J
K
L
M
N
P
Q
R
Sample
size
2
3
5
8
13
20
32
50
80
125
200
315
600
800
1250
2000
Acceptable quality levels (normal Inspection)
IL010
Ac Re
0 1
f
0.015
Ac Re
0, 1
I
0.025
Ac Re
i
V
i
T
1 2
0.040
Ac Re
0
1
»
j
1 2
2 3
0.065
Ac Re
«
r
*
1 2
2 3
3 4
0.10
Ac Re
V
i
1
1 2
2 3
3 4
5 6
0.15
Ac Re
i
0 1
t
,*«
2 3
3 4
5 6
7 8
0.25
Ac Re.
0 '
'
1
\
1 ' 2
2 3
3 4
5 6
7 8
10 11
0.40
Ac
i
°1
1
1
2
3
5
7
10
14
Re
1
2
3
4
6
8
11
15
0.65
Ac
i
0 '
i
ll
2
3
5
7
10
14
21
Re
1
f
2
3
4
6
8
11
15
22
1.0
Ac Re
|
0
i
'
1
1 2
2 3
3 4
5 6
7 8
10 11
14 15
21 22
t
CD
3
a
H-
(continued)
-------
CO H0
\0>
00 ft
O h
o
M
(D
(D
Hi
M
K
O
(D
3
(D
(D
H-
X
TABLE F-2 (continued)
Acceptable quality levels (normal inspection)
1.5
AC
'
Ke
1
1
2
3
5
7
10
14
21
2
3
4
6
8
11
15
22
2.5
Ac
Ke
0 1
•
ll
2
3
5
7
10
14
21
•
2
3
4
6
8
11
15
22
4.
Ac
0
ke
'!'
i
i
2
3
5
7
10
14
21
i
,
3
4
6
8
11
15
22
6.
Ac
°1
1
1
2
3
5
7
10
14
21
5
ke
r
i
2
3
4
6
8
11
15
22
10
Ac
1
2
3
5
7
10
14
21
Re
,
2
3
4
6
8
11
15
22
15
Ac Re
,*,
2 3
3 4
5 6
7 8
10 11
14 15
21 22
25
Ac Re
1 2
2 3
3 4
5 6
7 8
10 11
14 15
21 22
'
40
Ac Re
2 3
3 4
5- 6
7 8
10 11
14 15
21 .22
1
65
Ac Re
3 4
5 6
7 8
10 11
14 15
21 22
100
Ac Re
5 6
7 8
10 11
14 15
21 22
150
Ac Re
7 8
10 11
14 15
21 22
30 31
250
Ac Re
10 11
14 15
21 22
30 31
44 45
400
Ac Re
14 15
21 22
30 31
44,
45
650
Ac Re
21 22
30 31
44 45
i
1000
Ac Re
30 31
44 45
f
I
4= Use first sampling plan below arrow. If sample size equals, or exceed, lot or batch size, do 100-percent inspection.
Use first sampling plan above arrow.
Ac * Acceptance number.
Re • Rejection number.
-------
TABLE F-3. DOUBLING SAMPLING PLANS FOR NORMAL INSPECTION
(MASTER TABLE)
Sample Cumu-
slze latlve
code Sample sample
letter Sample size size
First
A Second
First 2 2
B Second 2 4
First 3 3
C Second 3 6
First 5 5
D Second 5 10
First 8 8
E Second 8 16
First 13 13
F Second 13 26
First 20 20
G Second 20 40
First 32 32
H Second 32 64
First 50 50
J Second 50 100
First 80 80
K Second 80 160
First 125 125
L Second 125 250
First 200 200
M Second 200 400
First 315 315
N Second 315 630
First 500 500
P Second 500 1000
First 800 800
Q Second 800 1600
First 1250 1250
R Second 1250 2500
Acceptable quality levels (normal Inspection)
0.010
Ac Re
i
a
0.015
Ac Re
a
;
0.025
Ac Re
a
0 2
1 2
0.040
Ac Re
i
a
i
0 2
1 2
0 3
3 4
0.065
Ac Re
a
i
0 2
1 2
0 3
3 4
1 4
4 5
0.10
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
0.15
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
0.25
Ac Re
a
1
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
0.40
Ac Re
a
'
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
0.65
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
1.0
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
(continued)
Petroleum Refinery Enforcement Manual
3/80 F-5
Appendix F
-------
TABLE F-3 (continued)
Acctptable quality levels (normal Inspection)
1.5
Ac Re
a
'
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
2.5
Ac Re
a
•
1
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
4.0
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
6.5
Ac Re
a
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
10
Ac Re
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
1
15
Ac Re
0 2
1 2
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 ?7
25
Ac Re
a
0 3
3 4
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
40
Ac Re
a
1 4
4 5
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
65
Ac Re
a
2 5
6 7
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
i
100
Ac Re
a
3 7
8 9
5 9
12 13
7 11
18 19
11 16
26 27
150
Ac Re
a
5 9
12 13
7 11
18 19
11 16
26 27
17 22
37 38
250
Ac Re
a
7 11
18 19
11 16
26 27
17 22
37 38
25 31
56 57
400
Ac Re
a
11 16
26 27
17 22
37 38
25 31
56 57
650
Ac Re
a
17 22
37 38
25 31
56 57
1000
Ac Re
a
25 31
56 57
f« Use first sampling plan below arrow. If sample size equals or exceeds lot or batch size, do 100-percent Inspection.
f- Use first sampling plan above arrow.
Ac - Acceptance number.
Re • Rejection number.
a - Use corresponding single sanpllng plan (or alternatively, use double sampling plan below, where available).
Petroleum Refinery Enforcement Manual
3/80 F-6
Appendix F
-------
APPENDIX G
OPERATING INSTRUCTIONS FOR AN ORGANIC VAPOR ANALYZER (OVA)
1. GENERAL INSTRUCTIONS
1.1 INTRODUCTION
The Century Systems Corporation Model OVA-128 is a portable,
lightweight, sensitive instrument designed to measure trace
amounts of organic vapors in air. It utilizes a hydrogen flame
ionization detector and can be calibrated to measure almost all
organic vapors. It is a quantitative type instrument with sensi-
tivity to 0.1 ppm methane. Figure G-l illustrates the OVA-128.
Figure G-2 shows the instrument in use.
1.2 DESCRIPTION OF MAJOR PARTS
1.2.1 Probe/Readout Assembly
The output meter and high alarm level adjustments are lo-
cated in this assembly, along with the sample probe assembly.
This assembly can be handled with one hand. It is connected to
the side pack by a knurled nut on the sample line, and a five-pin
push type connector on the umbilical cord. When the instrument
is supplied with a sample dilutor to read vapor concentrations
greater than 1000 ppm, the dilutor is mounted on the sample
probe.
1.2.2 Side Pack Assembly
This unit contains the remaining operating controls and
indicators, the electronic circuitry, flame ionization detector
chamber, hydrogen fuel supply, and the battery pack power supply.
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-l
-------
co IT)
\(T>
oo r+
o M
o
M
(D
£
3
»
n
HI
H-
3
(D
H
•<;
M
3
HI
O
M
o
(D
oi
O S
I PJ
(D
H-
X
o
Figure G-l. Portable organic vapor analyzer (Model OVA-128).
Courtesy of Century Systems Corporation, Arkansas City, Kansas,
-------
-• -
Figure G-2. Illustration of the use of the organic vapor analyzer.
Petroleum Refinery Enforcement Manual
3/80 G-3
Appendix G
-------
1.2.3 Safety Considerations
Hydrogen gas is contained under pressure in the side pack.
All safety precautions for handling hydrogen gas must be observ-
ed. The instrument is safe when proper operating procedures are
followed. Section 5 of the Century System Manual provides de-
tailed safety precautions, which should be read and understood
before operating the OVA.
1.2.4 General Operating Principles
The instrument is used for detecting hydrocarbons in air.
The sample is pulled in at a constant rate, by the internal pump,
through the sample probe attached to the probe/readout assembly.
When hydrocarbons are present, they are burned in the hydrogen
flame. The ionization detector generates a signal that is sent
to the readout meter. This meter has a 0 to 10 scale. The
instrument has a range switch with XI, X10, and X100 settings,
which allows reading vapor concentrations from 1 to 1000 ppm. If
the vapor concentration is higher than 1000 ppm, the sample
dilutor may be used. The diluter makes it possible to measure
concentrations of 10,000 ppm, or higher.
The instrument is certified as safe by Factory Mutual Re-
search Corporation for use in Class I, Division 1, Groups A,
B, C, and D hazardous environments. Therefore, it is essential
to maintain the certification that the instrument not be modified
in any way.
2. OPERATING PROCEDURES
2.1 INITIAL STARTUP OF THE INSTRUMENT
Startup cannot be attempted until the internal hydrogen fuel
supply tank is filled (instructions in Section 2.6 of the Century
manual), and the battery pack is charged. The battery may be
checked with the INSTR/BATT test switch. Move the switch to the
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-4
-------
BATT position and note the reading to see if it is within the
"battery charged" section on the meter.
The GAS SELECT control should be preset to the desired dial
indication prior to turn on. The instrument as received from the
factory is set to measure methane' in air. Settings for other
vapors may be determined by the procedure in Section 4 of the
Century manual.
Following are the startup instructions for the Model
OVA-128:
1. Move the INSTR switch to ON and allow 5 minutes for warmup.
2. Select the sample probe suitable for the work to be perform-
ed. The adjustable length probe is used for normal survey
work, and the "close area" probe for special work where the
sample is easily within reach. Attach the probe to the
readout assembly with the captive locking nut. Insert a
pickup fixture in the probe. If there is a chance that dust
or liquids may be drawn into the probe, a particle filter
should be assembly to the side pack with the push-in plug,
making sure that the connector pins are properly aligned.
Connect the sample line to the pump connection with the
knurled nut.
3. Turn the pump switch to ON and observe the sample flow rate
indicator. The indication should be about 2 units. The
audible alarm may be set now if so desired. Adjust the
meter pointer to the desired alarm level using the CALIBRATE
ADJUST knob. Turn the alarm level adjust knob on the back
of the readout assembly until the audible alarm just comes
on. Adjust speaker volume with the VOLUME knob.
4. Move the CALIBRATE switch to X10 and adjust the meter read-
ing to zero with the CALIBRATE ADJUST knob.
5. Open the H2 TANK VALVE one turn and observe the reading on
the H2 TANK PRESSURE indicator. The tank pressure should be
sufficient to allow for 150 psi of pressure drop for each
hour of operation.
6. Open the H7 SUPPLY VALVE one turn and observe the reading on
the H2 SUPPLY PRESSURE indicator. CAUTION: Be sure the
pump Is running while the H- SUPPLY VALVE is open. Other-
wise, hydrogen will accumulate in the detector chamber which
could damage the instrument or cause an internal explosion.
7. Readjust the meter reading to zero if necessary.
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-5
-------
8. Depress the igniter button. There should be a slight "pop"
sound as the hydrogen ignites and the meter pointer will
move upscale. Release the igniter button immediately after
ignition. If the burner does not ignite, let the instrument
run for several minutes before depressing the igniter button
again. After ignition, the meter pointer will indicate the
hydrocarbon background concentration.
CAUTION: Do not depress the igniter button for more than
6 seconds at one time.
9. Move the instrument to an area that is representative of the
lowest ambient background concentration to be surveyed.
Move the CALIBRATE switch to XI and adjust the meter to read
1 ppm with the CALIBRATE ADJUST knob.
NOTE: Adjustment to 1 ppm, rather than 0, is necessary in
the XI range because of the sensitivity of the OVA. This
permits minor downward fluctuations in the normal background
level without dropping below 0, which would actuate the
flame-out alarm. Also, remember during subsequent surveys
that 1 ppm must be subtracted from all readings. Thus a
reading of 2.8 ppm would be only 1.8 ppm.
The instrument is now ready for use.
2.2 MONITORING TECHNIQUES
Start with the CALIBRATE switch in the XI range for maximum
sensitivity. Using one-hand operation, survey the areas of
interest while observing the meter. For ease of operation, use
the shoulder strap to carry the side pack assembly on the side
opposite the hand holding the probe/readout. For area surveys,
outdoors, the pickup fixture should be positioned several feet
above ground level. When making quantitative readings or pin-
pointing leaks, the probe should be positioned at the point of
interest. When testing for leaks, the probe pickup should be
held at the source, leaving the pickup in one spot for 5 seconds
or more to allow for the instrument response time. When the wind
is blowing, the probe pickup should be positioned on the downwind
side of the pipe connection or equipment for the initial leak
test.
When organic vapors are detected, the meter pointer will
move upscale and the audible alarm will sound when the preset
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-6
-------
point is exceeded. The frequency of the alarm will increase as
the detection level increases. Move the CALIBRATE switch to the
appropriate scale position to determine the extent of the leak.
If flame-out occurs, the flame-out alarm actuates; ensure
that the pump is running before pressing the igniter button.
Usually flame-out results from sampling a gas mixture that is
above the lower explosive level, which causes the H2 flame to
extinguish. When this happens, as soon as the explosive mixture
passes or is pumped out of the detector, reignition is all that
is required.
Another cause of flame-out is a restriction of the sample
flow line, which would not allow sufficient air for combustion to
enter the chamber. This condition could be caused by a clogged
particle filter or other restriction in the sample line, or by
blocking the exhaust port that is located on the bottom of the
case.
2.3 SHUTDOWN PROCEDURE
1. Close the H2 SUPPLY VALVE.
2. Close the H2 TANK VALVE.
3. Move the INSTR switch to OFF.
4. Wait 5 seconds and move the PUMP switch to OFF.
The instrument is now shut down.
3. REFUELING
3.1 REFILLING THE HYDROGEN FUEL SUPPLY
The instrument must be completely shut down as described in
the previous section. The refilling should be done in a well-
ventilated area to prevent a possible buildup of explosive mix-
tures of hydrogen and air. Also there should be no potential
igniters or flame in the area.
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-7
-------
1. If you are making the first filling of the instrument or if
the filling hose has been allowed to fill with air, the
filling hose must be purged with hydrogen prior to filling
the instrument tank. This can be accomplished by connecting
the filling hose to the cylinder and turning the valve on
the other end to the fill position for a few short blasts
and then to the bleed position for a short time with the
cylinder valve open slightly. Turn the bleed valve to the
OFF position.
2. Connect the hose to the refill connection on the side pack
assembly. Open the hydrogen supply bottle valve slightly.
Open the REFILL VALVE and the H- TANK VALVE on the instru-
ment panel and place the FILL/BLEED valve on the filling
hose assembly in the FILL position. The new pressure in the
instrument tank will now be indicated on the H~ TANK PRES-
SURE indicator.
3. After the instrument fuel tank is filled, shut off the
REFILL VALVE on the panel, the FILL/BLEED valve on the
filling hose assembly, and the hydrogen supply bottle valve.
The hydrogen in the filling hose must now be bled off by
turning the FILL/BLEED valve to the BLEED position. CAU-
TION: Hydrogen under high pressure is_ in this hose. After
the pressure in this line is down to atmospheric pressure,
turn the REFILL/BLEED valve to FILL for a short time to
allow the high-pressure hydrogen in the connectors to enter
the refilling hose. Again turn the FILL/BLEED valve to
BLEED to lower pressure to atmospheric in the hose. Turn
FILL/BLEED valve to the OFF position and disconnect it from
the REFILL VALVE. Leave connected to the cylinder and it
will not need purging again.
4. Close the H- TANK VALVE on the side pack and observe the
pressure on the pressure indicator that is reading the
pressure of the trapped hydrogen in the line. If this
pressure decreases more than 350 psig/h, it indicates a
significant hydrogen leak and it should be repaired.
3.2 BATTERY RECHARGING
1. Plug the charger BNC connector into mating connector on
battery cover and insert the AC plug into 115 VAC wall
outlet. Never charge in a hazardous area.
2. Move the battery charger switch to the ON position. The
light above the switch button should illuminate.
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-8
-------
3. Battery charge condition is indicated by the meter on the
front panel of the charger; the meter will deflect to the
right when charging. When fully charged, the pointer will
be in line with the "charged" marker above the scale.
4. Approximately 1 hour of charging time is required for each
hour of operation. However, overnight charging is recom-
mended, and the charger can be left on indefinitely without
damaging the batteries. If the battery has been allowed to
discharge completely and does not charge by the above pro-
cedure, the procedure in the Century manual, Section 2.7.1,
pages 6 and 7, must be followed.
4. CALIBRATION
4.1 GENERAL
The instrument is factory calibrated to a methane in air
standard at a GAS SELECT control setting of 300. The instrument
will respond to nearly all organic compounds and can be easily
and rapidly calibrated to other organic compounds of interest.
the GAS SELECT control on the panel is used to set the electronic
gain to a particular compound. The instrument is adjusted at the
factory to read linearly from one range to another.
4.2 CALIBRATION TO OTHER ORGANIC VAPORS
Primary calibration of the instrument is accomplished using
a known mixture of a specific organic vapor compound. Commer-
cially available standard samples offer the most convenient and
reliable calibration standards and are recommended for the most
precise analyses. Always obtain the cylinder with the desired
sample concentration and the "balance as air." The calibration
gas should be drawn from the cylinder into a collapsed sample
bag, then drawn from the bag by the instrument pump to prevent a
pressure or vacuum at the sample inlet.
Calibration of the instrument to other organic compounds by
the following procedure is recommended:
After the instrument is in operation and the normal back-
ground is "zeroed out," draw a sample of the calibration gas
into the instrument. The GAS SELECT knob on the panel is
used to shift the readout meter indication to correspond to
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-9
-------
the concentration of the calibration gas mixture. The
setting on the GAS SELECT dial is read and recorded for that
particular organic compound. This exercise can be performed
for a large variety of compounds; when the operator wants to
read a particular compound, the GAS SELECT control is turned
to the predetermined setting for that compound. Calibration
on any one range automatically calibrates the other two
ranges.
Calibration can be accomplished by means of pure gases or
liquids and preparing individual standards using collapsible bags
made of inert material such as polyethylene or mylar. Bags may
be purchased from laboratory supply houses or some instrument
manufacturers. Polyethylene trash can liners could be used.
Before using this method of making calibration standards, the
user should read and understand Section 4.3 on calibration, pages
8 and 9, in the Century manual.
For liquid samples, use of the following equation will allow
the calculation of the microliters of organic liquid needed to
make 100 ppm of vapor calibration gas.
V-L = V2 x Mw/244 D
where V, = volume of liquid in microliters (for
100 ppm mixture)
V~ = volume of bottle or bag in liters
Mw = molecular weight of organic liquid
D = density of organic liquid.
Therefore, to make up a 100 ppm hexane calibration gas,
V-, = 5 liters x 86/244 (0.659) =2.67 microliters
of hexane.
A microliter syringe is required to measure these small amounts
of liquid.
5. SAFETY CONSIDERATIONS
The Century Systems Models OVA-108, OVA-128, and OVA-138
have been tested and certified by Factory Mutual Research Corpo-
ration (FM) as intrinsically safe for use in Class I, Division
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-10
-------
1, Groups A, B, C, and D hazardous atmospheres. All flame ioni-
zation hydrocarbon detectors are potentially hazardous since they
burn hydrogen in the detector cell. Mixtures of hydrogen and air
are flammable over a wide range of concentrations. Safety was a
major factor in the design of the OVA. To protect against ex-
ternal ignition of flammable gas mixtures, the flame detection
chamber has porous metal flame arresters on the sample input and
exhaust ports, as well as on the hydrogen inlet connector. The
standard battery pack and other circuits are internally current
limited to an intrinsically safe level.
When monitoring organic vapors in a refinery, the following
safety practices are suggested:
1. Do not insert the probe too close to a moving part such
as a rotating pump shaft.
2. Do not place the probe too close to a liquid stream.
Blockage of the probe could result.
3. Do not place the umbilical cord on a heated surface
such as a pipe, valve, heat exchanger or furnace.
4. Turn the instrument off after a flame-out and ignite it
in a safe area.
5. Read the operating and service manual for the portable
OVA prior to operating it in the field.
6. Carefully read the hydrogen filling instructions prior
to refilling.
7. Read the operating and service manual prior to trouble-
shooting.
8. Make arrangements for hexane or methane and hydrogen
cylinders to arrive at the inspection site.
6. MONITORING PROBLEMS
One of the main problems in monitoring organic vapors is
pinpointing leaks. As discussed in the monitoring procedures, it
is important that the probe be moved slowly. The 5-second respon-
se time of the instrument requires a slow, methodical monitoring
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-ll
-------
procedure. Because the organic vapors are dispersed by the wind,
it is difficult to determine their source. When a slight in-
crease in organic vapors is detected, locate the source by moving
the probe slowly and noting differences in concentration. Move
the probe in the direction of highest concentration. To help in
pinpointing the leaks, note such usual indications of gas escape
as the frosting of points of leakage and the wavy appearance of
the air due to a change in the index of refraction.
Because the organic vapors are dispersed by the wind, plac-
ing a notebook on the upwind side or adjacent to the suspected
valve or flange aids in finding the leak.
The OVA will sometimes detect leaks at sources that do not
contain hydrocarbons. This usually happens when the OVA detects
hydrocarbons from one valve and the wind moves these vapors over
another valve. Be aware of the possibility of false readings and
make attempts to correct them.
Petroleum Refinery Enforcement Manual Appendix G
3/80 G-12
-------
APPENDIX H
EMISSIONS FROM VALVES, PUMP AND COMPRESSOR
SEALS, AND OTHER REFINERY EQUIPMENT COMPONENTS
Potential sources of volatile organic compound (VOC) emis-
sions at petroleum refineries include valves, flanges, threaded
fittings, pump seals, and compressor seals. Emissions occur when
the volatile material flowing through a refinery component leaks
through the component because the seal is inadequate. This
appendix describes these refinery components and discusses fac-
tors that contribute to the development of leaks.
Reasonably available control technology (as described in
EPA's control technique guidelines series) is an active inspec-
tion and maintenance (I&M) program. An I&M program requires that
refinery personnel monitor all valves, flanges, threaded fit-
tings, pump seals, and compressor seals for leaks. When a leak
is found, it is to be tagged and repaired within 15 days of its
detection. Air pollution control inspectors are to screen peri-
odically a random sample of refinery equipment associated with
various process units to determine the number of leaks. Records
of the refinery's I&M program are also to be reviewed by the
inspector.
An organic vapor analyzer (OVA) that meets the specifica-
tions listed in the control technique guideline is to be used in
detecting VOC leaks. The instrument is to be calibrated with
methane gas. A leak is defined as a concentration greater than
or equal to 10,000 ppm of hydrocarbons when sampling is conducted
at the source (i.e., 1 cm from the source).
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-l
-------
The locations on the various refinery components where
screening is to be done is indicated on the illustrations. These
are the points where VOC leaks generally occur.
VALVES
Large numbers of pipeline valves are associated with every
type of equipment used in petroleum processing. Although many
types exist, they perform one of three functions:
On/off flow control and throttling
Flow rate control (control valves)
Flow direction control (check valves)
The gate and plug valves are the most common types used for
on/off flow control in a refinery, while globe valves are the
most common type for flow control. Almost all check valves are
enclosed within the process piping, but their access connections
to the working parts may be sources of fugitive emissions. All
other valves consist of internal parts connected to an external
actuator by means of a valve stem. A packing around the valve
stem is used to prevent process fluid from escaping from the
valve. On/off flow control and throttling valves are actuated by
the operation of a handwheel or crank. Control valves are fre-
quently automatically operated, often by air pressure.
Because of heat, pressure, vibration, friction, and corro-
sion, leaks can develop in the packing surrounding the valve
stem. Figures H-l through H-8 show the potential leak areas for
common refinery valves. The California Air Resources Board
(CARB) found in its inspection of refineries that 9 percent of
the valves leaked hydrocarbons. Most of this valve leak rate was
from gas service valves, which constitute 25 percent of the
refinery valve population but produce 85 percent of the total
hydrocarbon emissions from valves.
Emissions originating from product leaks at valves can be
controlled only by regular inspection and prompt repair of the
leak. CARB requires gas service valves to be inspected by the
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-2
-------
HANDWHEEL
PACKING GLAND
PACKING BOX
BODY
SCREEN
HERE
RISING STEM TYPE
SPINDLE
PACKING GLAND
PACKING-BOX
NIPPLE
SCREW-IN
BONNET
DISK OR
WEDGE
NONRISING STEM TYPE
Figure H-l. Gate valves.
1
Petroleum Refinery Enforcement Manual
3/80 H-3
Appendix H
-------
HANDWHEEL
PACKING -If
GLAND [fa
PACKING
BOX
BODY
SCREEN
HERE
RENEWABLE DISK
MANUAL GLOBE VALVE
SPIRAL WOUND GASKET
CAGE GASKET
GROOVE
PIN
SEAT RING
GASKET
CAGE
PISTON RING
VALVE PLUG
SEAT RING
Figure H-2. Globe valves.
Petroleum Refinery Enforcement Manual
3/80 H-4
GLOBE-TYPE CONTROL VALVE
1
Appendix H
-------
SCREEN
HERE
LUBRICANT PLUG
PACKING GLAND
GROOVE FOR
LUBRICANT
Figure H-3. Lubricated plug valves.
1
Petroleum Refinery Enforcement Manual
3/80 H-5
Appendix H
-------
SCREEN
HERE
Figure H-4. Ball valve.
1
HANDWHEEL
CONTROL
SCREEN
HERE
BODY
DISK
Figure H-5. Butterfly valve.
1
Petroleum Refinery Enforcement Manual
3/80 H-6
Appendix H
-------
STEM
DIAPHRAGM
SCREEN
HERE
Figure H-6. Weir-type diaphragm valve.
1
SCREEN AT
FLANGES
Figure H-7. Check valves.
1
Petroleum Refinery Enforcement Manual
3/80 H-7
Appendix H
-------
SCREEN
HERE
SPRING
DISK
NOZZLE
ALTERNATE SCREENING
POINT (ONLY IF THE HORN
EXIT IS INACCESSIBLE)
PROCESS SIDE
Figure H-8. Spring-loaded relief valve.
1
Petroleum Refinery Enforcement Manual
3/80 H-8
Appendix H
-------
refinery once every 3 months and inspection records to be kept.
GARB concluded that a standard of no leaks for refinery gas
service valves is feasible when a mandated inspection and main-
tenance plan is applied to these valves. A no-leak standard can
be achieved from liquid-service valves with only marginally
improved maintenance by refineries.
CARB emphasis on valve maintenance by the refineries re-
quires that an inspector be able to recognize a lack of routine
maintenance. During field inspection, typical indicators of a
lack of routine maintenance are the following:
Leak is large enough to be seen, heard, or smelled.
Gland flange nuts are rusted on the bolts.
Valves are covered with undisturbed grime.
During the screening, the inspector should compare the leak fre-
quency of valves at similar process units in different refiner-
ies. Considerable variation in these leak frequencies indicates
a cause for leaks other than the nature of the valve service.
Inspection and maintenance of valve packing boxes are rou-
tinely performed by many refineries. Maintenance activities to
stop valve leakage include:
Simple tightening of the gland flange on gate or globe
valves, or
Lubrication of plug valves.
Sometimes, instead of improved maintenance, the valves need to be
modified or different designs selected. For example, valves
packed with alternate rings of braided graphite and containing
steam at a temperature of 315°C (600°F) and a pressure of 2860
kPa (400 psig) have undergone 50,000 cycles (turns) before leak-
ing. Such valves were completely leak-free for 15,000 cycles.
Additionally, hermetically sealed diaphragm or bellows valves are
advertised as zero-leak valves.
Because the leakage rate of a valve depends on the nature of
the products handled, the degree of maintenance, and the charac-
teristics of the equipment, the level of emission reduction
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-9
-------
achieved by I&M programs is difficult to estimate. The costs of
I&M programs are the cost of labor for inspection and the cost of
materials for repairs and maintenance. I&M program credits are
received for product recovery and improved process operations.
PUMP AND COMPRESSOR SEALS
Pumps and compressors most frequently leak at the seal be-
tween the moving shaft and the stationary casing. However, there
are some types of pumps that are nonleaking. Examples of non-
leaking pumps are the completely enclosed or "canned" pumps in
which there are no seals, diaphragm pumps in which a flexible
diaphragm prevents the product from contacting the working parts
of the pump, and pumps with magnetic drivers in which magnetics
are used to transmit mechanical energy across a sealed pump hous-
ing.
Pumps may be classified under two general headings, positive
displacement and centrifugal. Positive-displacement pumps have
as their principle of operation the displacement of the liquid
from the pump case by reciprocating action of a piston or dia-
phragm or by the rotating action of a gear, cam, vane, or screw.
The type of action may be used further to classify positive-
displacement pumps as reciprocating or rotary. Reciprocating
positive-displacement pumps are the most common type of positive-
displacement pump used in refineries. Centrifugal pumps operate
by the principle of converting velocity pressure generated by
centrifugal force to static pressure. Velocity is imparted to
the fluid by an impeller that is rotated at high speeds inside a
housing containing the fluid. The fluid enters the housing at
the center of the impeller and is discharged from the housing at
the impeller's periphery. These pumps, which are illustrated in
Figures H-9 and H-10, are commonly used by refineries.
Compressors are pumps that are used in gas service. They
operate on the principle of volume reduction through the recipro-
cating action of a piston and by pressure increase through the
centrifugal action of a vane just like a pump.
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-10
-------
SCREEN
HERE
Figure H-9. Vertical centrifugal pump.
1
SCREEN
HERE
Figure H-10.
Horizontal centrifugal
pump.1
Petroleum Refinery Enforcement Manual
3/80 H-ll
Appendix H
-------
The seals normally used on pumps are mechanical or packed.
A packed seal generally consists of a stationary stuffing box,
much like the packing gland on a valve. The stuffing box sur-
rounds the moving shaft and is filled with fiber, leather, or
other elastic material. The stuffing box is provided with takeup
rings that allow compression of the packing. Compression forces
the packing material against the shaft and effects the seal. A
mechanical seal consists of two plates situated perpendicular to
the shaft and forced tightly together. One plate is attached to
the shaft and one is attached to the casing. Packed seals can be
used on reciprocating or rotating shafts; mechanical seals are
for rotating shafts only. Figures H-ll through H-13 illustrate
the packed and mechanical seals and show areas where leakage may
occur.
In normal service both packed and mechanical seals can leak.
These losses may be vapor or liquid and occur when shafts become
scarred, move eccentrically, or through failure of the packing or
seal faces. The rate at which this destruction of seal effi-
ciency progresses depends upon the abrasive and corrosive proper-
ties of the product handled and the type of maintenance applied.
The CARB found that centrifugal pumps with packed seals lost
2.2 kg of hydrocarbons/day-seal (4.8 Ib/day-seal), centrifugal
pumps with mechanical seals lost 1.5 kg of hydrocarbons/day-seal
(3.2 Ib/day-seal), reciprocating pumps with packed seals lost 2.4
kg of hydrocarbons/day-seal (5.4 Ib/day-seal), and compressors
lost 3.9 kg of hydrocarbons/day-seal (8.5 Ib/day-seal). A total
of 20 percent of the pumps in liquid service leaked, while 18
percent of those processing gas leaked. Of the pumps and com-
pressors inspected by CARB, 11 percent of the compressors leaked
and 20 percent of the pumps leaked. Compressor seals are illus-
trated in Figures H-14 and H-15.
Both packed and mechanical seals inherently leak, but emis-
sions from centrifugal pumps can be reduced 33 percent by replac-
ing packed seals with mechanical seals. Emissions from dual
mechanical seals can be eliminated by using a circulating, inert
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-12
-------
POSSIBLE LEAK AREAS
ROTATING OR RECIPROCATING SHAFT
TAKEUP
PLATE
PRODUCT
BEING
PUMPED
PACKING
Figure H-ll. Simple packed seal.1
Petroleum Refinery Enforcement Manual
3/80 H-13
Appendix H
-------
POSSIBLE LEAK AREA
STATIONARY > »
SEALING RING
SHOULDER FIXED-
TO SHAFT
ROTATING RING
FIXED TO
SHOULDER
•PRODUCT BEING PUMPED
Figure H-12. Simple mechanical seal.
1
Petroleum Refinery Enforcement Manual
3/80 H-14
Appendix H
-------
STUFFING-BOX^
HOUSING
PUMPEt
INNER
MATING — "
RING
INNER PRIMAR
RING
•>*.
( C
) LIQUID
SEAL LIQUID,
OUT (TOP)
^ t
u
UIIL ^
'tr /
SEAL LIQUID,
IN (BOTTOM)
T V
u H
\---J
CINT
SHAFT
C
^•^c
*-
3
n
— GL
\ \
j
r
AND PLATE
OUTER
MATING
RING
OUTER
PRIMARY
RING
TYPICAL DOUBLE MECHANICAL SEAL
STUFFING-BOX
HOUSING\
PUMPED
LIQUID
BYPASS
,FLUSH
BUFFER LIQUID,
OUT IN
(TOP) (BOTTOM)
t i
/
GLAND PLATE
INNER MATING RING
OUTER PRIMARY RING
TANDEM MECHANICAL SEALS
Figure H-13. Double mechanical seals for pumps.
1
Petroleum Refinery Enforcement Manual
3/80 H-15
Appendix H
-------
PORT MAY BE ADDED
FOR SCAVENGING OR
INERT-GAS SEALING
INTERNAL
GAS PRESSURE
ATMOSPHERE
Figure H-14. Honeycomb labyrinth compressor seal.
1
Petroleum Refinery Enforcement Manual
3/80 H-16
Appendix H
-------
PORT MAY BE
ADDED FOR
SEALING
INTERNAL
GAS
PRESSURE
SCAVENGING PORT
MAY BE ADDED FOR
VACUUM APPLICATION
ATMOSPHERE
\
RESTRICTIVE CARBON RING SEALS
Figure H-15. Mechanical seals for compressors.
1
Petroleum Refinery Enforcement Manual
3/80 H-17
Appendix H
-------
fluid to pressurize the seals. According to several refiners,
the highest temperatures in which mechanical seals can be used
range from 210° to 360°C (410 to 680°F). Emissions from recipro-
cating pumps can be controlled by installation of dual packed
seals with provisions to vent the volatile vapors that leak past
the first seal into a vapor recovery system.
Emissions from any kind of pump or compressor seal can be
minimized by frequent inspection and corrective maintenance.
Major indications of leakage at or near the seal/shaft are a
visible mist, hissing sound, or strong odor.
FLANGES AND OTHER PIPE JOINING TECHNIQUES
Process piping can be joined to process vessels and equip-
ment or to other lengths of piping in as many as 17 different
ways. There are, however, three principal types of joining
techniques used in petroleum refining:
Threaded fittings
Flanges
Welds
Threaded fittings are a joining technique where threaded
lengths of pipe are screwed together using other threaded parts.
They are most commonly used for pipes of 0.05-m (2-inch) diameter
or smaller. The most common threaded fitting is the "bull plug."
Bull plugs are used to cap off valve outlets or other threaded
outlets that are normally used for sampling. A valve outlet is
the same type of equipment without a threaded fitting in place.
Some refineries have bull plugs in all exposed valve outlets.
Flanges provide pipe joints that can easily be disassembled.
They consist of circular discs (faces) welded or threaded to the
outer circumference of pipe ends. A gasket forms the seal be-
tween flanges. The gasket is held in place by bolts connecting
the two flange faces. Gasket material for flanges is typically
asbestos fiber sheet (similar to brake shoe material), metal/
asbestos for high temperature and pressure, and steel alloys for
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-18
-------
corrosive service. Flanges are the most common joining technique
used in refineries.
Welds are used to connect pieces of pipe when disassembly
will not be needed. Welding produces a seal almost as complete
as the pipe itself. Welding is a desirable pipe joining techni-
que whenever practical.
The influences of heat, pressure, vibration, friction, and
corrosion can cause leakage in joints. Of the three kinds of
joints described, threaded fittings that have been frequently
assembled and disassembled are the most likely to leak. The CARB
inspected 346 threaded fittings and found that 23 percent of them
leaked. Some refineries require bull plugs in exposed valve
outlets after a leak is detected from the valve outlet. Threaded
fittings, however, are not the predominant type of connecting
device. Therefore, many refineries do not have procedures for
them. Welds are virtually leak-proof because they are rigid
joints less susceptible to the effects of vibration, etc., that
disturb the original seal. Flanges can leak if the gasket mate-
rial is damaged, if the flange is not aligned properly, or be-
cause of seal deformation due to thermal stresses on the piping
system. CARB inspected 24,826 flanges and found that only 0.4
percent leaked. Therefore, flanges are a negligible source of
emissions.
Emissions from product leaks at flanges and threaded fit-
tings can be controlled by regular inspection and prompt mainte-
nance. CARB recommends an annual undocumented inspection program
for flanges. The board and other governmental agencies focused
their regulations on the control of emissions from flanges,
because they are the most common type of connecting device in a
refinery.
REFERENCE
1. Harris, G. E., and G. J. Langley. Detailed Screening Plan
For Fugitive Emissions From SOCMI Process Units. Prepared
by Radian Corporation for the U.S. Environmental Protection
Agency. DCN 79-203-001-01-05, December 1979.
Petroleum Refinery Enforcement Manual Appendix H
3/80 H-19
-------
APPENDIX I
INFORMATION CHECKLISTS FOR PSD REVIEW
The data sheets in this appendix list the source information
that is required for a TIER I and TIER II PSD review (Prevention
of .Significant Deterioration of Air Quality).
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-1
-------
SOURCE INFORMATION
1. General Information
Facility name
Proposed location
Parent company
Principal products
New or modified source
2. An Enforceable State Permit
If an enforceable state permit has been
obtained, submit that; if not, submit the
data required in Items 1, 3 and 4.
3. Major Activity Throughputs
Description of major activity
Major activity products
Maximum capacity
Operating schedule
4. Potential Emissions
Annual potential emissions
The calcultion by which the above emissions
were estimated
If the applicant would like EPA to calculate
the annual potential emissions, they should
submit the data required in Items 1, 5, 6,
and 7 as applicable.
5. Process/Operating Data
Descriptions of process/operating units
Process/operating units
Feed materials
Maximum annual rates
Process/operating units outputs
Products
Maximum annual rates
Fuel usage
Type of combustion unit
Size
Fuel
Type
Heat content
Percent sulfur
Percent lead
Percent ash
Annual fuel consumption
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-2
-------
6. Storage Tank Data
Tank capacity
Throughputs
Roof type
Product stored
Reid vapor pressure
7. Solvent Usage
Feed material
Common name of solvent
Chemical composition
Solvent as a percent of feed material
By volume
By weight
Solvent recovered
Amount by volume
Amount by weight
Method for recovery
Disposal of solvent
Amount
Method
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-3
-------
INFORMATION REQUIREMENTS FOR A TIER I REVIEW
1. General Information
Facility name
Proposed location
Parent company
Company contact
Principal products
New or modified source
Distance to Class I areas
2. Detailed Construction Schedule
3. An Enforceable State Permit
If an enforceable state permit has been
obtained, submit it along with Items 9
and 10, if they are not included as part of
the state permit. If a state permit has not
been obtained, submit Items 1, 4, 5, 9, 10,
as applicable.
4. Major Activity Throughputs
Description of major activity
Major activity products
Maximum capacity
Operating schedule
5. Allowable Emissions
Annual, daily, and hourly allowable emissions
The calculation by which the above emissions
were estimated
If the applicant would like EPA to calculate
the allowable emissions, they should submit
the data required in Items 1, 6, 7, 8, 9,
and 10 as applicable.
6. Process/Operating Data
Process flow diagram describing the entire
facility
Process flow diagram describing each major
activity affected by the modification
Descriptions of process/operating units
Operating schedule (h/yr)
Process/operating units
Feed materials
Maximum annual, daily, and hourly rates
Process/operating unit outputs
Products
Maximum annual, daily, and hourly rates
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-4
-------
Fuel usage
Type of combustion unit
Size
Fuel
Type
Heat content
Percent sulfur
Percent lead
Percent ash
Annual, daily, and hourly fuel consumption
7. Storage Tank Data
Tank capacity
Throughputs
Roof type
Product stored
Reid vapor pressure
8. Solvent Usage
Feed material
Common name of solvent
Chemical composition
Solvent as a percent of feed material
By volume
By weight
Solvent recovered
Amount of volume
Amount of weight
Method for recovery
Disposal of solvent
Amount
Method
9. Stack and Vent Data
Location of emission points
Stack, vent, fugitive, immediately after
process unit (prior to combination with
other units)
Stack height
Cross-sectional area
Exit gas flow rate
Maximum
Normal
Exit gas velocity
10. Air Cleaning Equipment
Type
Specifications (design criteria)
Pollutant removed
Percent collection efficiency (design
criteria)
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-5
-------
INFORMATION REQUIREMENTS FOR A TIER II REVIEW
1. General Information
Facility name
Proposed location
Parent company
Company contact
Principal products
New or modified source
Distance to Class I area
2. Detailed Construction Schedule
3. Process/Operating Data
Process flow diagram describing the entire
facility
Process flow diagram describing each major
activity affected by the modification
If it is not apparent from the process
flow diagrams, describe how process/
operating units, air cleaning equipment,
and stacks and vents are interconnected.
Descriptions of process/operating units
Operating schedule (h/yr)
Process/operating units
Feed materials
Maximum annual, daily, and hourly rates
Process/operating unit outputs
Products
Maximum annual, daily, and hourly rates
Fuel usage
Type of combustion unit
Size
Fuel
Type
Heat content
Percent sulfur
Percent lead
Percent ash
Maximum annual, daily, and hourly fuel
consumption
4. Storage Tank Data (as applicable)
Tank measurements
Capacity
Throughputs
Diameter
Height
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-6
-------
Tank characteristics
Location (above or below ground)
Fill mouth (submerged, splash, bottom
loading)
Roof type
Roof seal
Product stored
Density
Vapor mole weight
Reid vapor pressure
Storage temperature
Maximum
Normal
5. Solvent Usage (as applicable)
Feed material
Common name of solvent
Chemical composition
Solvent as a percent of feed material
By volume
By weight
Solvent recovered
Amount by volume
Amount by weight
Method for recovery
Disposal of solvent
Amount
Method
6. Stack and Vent Data
Location of emission points
Stack, vent, fugitive, immediately after
process unit (prior to combination with
other units)
Stack height
Cross sectional area
Exit gas temperature
Exit gas flow rate
Maximum
Normal
Exit gas velocity
7. Control Technology
a. Flue Gas Treatment
(1) ESP
(2) Fabric Filter
(3) Scrubber
(4) Other
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-7
-------
b. Process Modification (if applicable)
(1) Description of how the process modifi-
cations (including fuel cleaning, or
treatment or innovative fuel combus-
tion techniques) reduce emissions
(2) Emission reductions gained by using
the modified process
(3) Direct costs as indicated in Part A,
"Guidelines for Determining BACT".
c. Design, Equipment, Work Practice or
Operational Standard
(1) Description
(2) Emissions reductions
(3) Direct costs
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-8
-------
PRECIPITATOR DATA
Part I - Preliminary design or design criteria
1. Estimated total gas flow at full load and ESP operating
temperature (ac fm)
2. ESP operating temperature (°F) range
3. Number of separate ESP modules under consideration
4. Estimated total collecting surface area of each module
5. Estimated total collecting surface for all modules
6. Number of separate electrical sections for each module under
consideration
7. Type of power control
Manual power
or Manual spark rate
or Automatic power
or Automatic spark rate
8. Instrumentation for each electrically isolated section
Primary voltage
Primary current
Secondary voltage
Secondary current
Spark rate
9. Estimated linear velocity of gas through each module at full
load (actual ft/s) or range of acceptable velocities
10. Briefly describe techniques used to ensure uniform linear
velocity within ESP
11. Briefly describe system used to remove and convey collected
ash to final disposal.
]2. Vendor guarantee and terms of guarantee if available
Part II - Reference plant example
1. General flow diagram for the precipitator
2. Provide design criteria or preliminary engineering data for
the major elements of the ESP for the particular plant under
consideration or a similar plant where the major elements
have been designed and exact detailed specifications are
available.
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-9
-------
FABRIC FILTER
Part I - Preliminary design or design criteria
1. Estimated total gas flow at the full load and fabric filter
operation temperature (acfm)
2. Fabric filter operation temperature (°F) range
3. Estimated number of separate fabric filters
4. Estimated number of isolated compartments per fabric filter
5. Estimated number of filters per compartment
6. Estimated filter length (ft) and filter diameter (inches) or
range of acceptable alternative lengths or diameters
2
7. Estimated total cloth area of all filters (ft )
8. Design criteria for air to cloth ratio or range of acceptable
ratio (cloth area divided by total acfm)
9. Briefly describe cloth
Material
Weave 7
Weight (oz/yd^)
Permeability
10. Type of filter cleaning under consideration
Reverse air
Pulse jet
Shake
Other
11. Type filter cleaning controls
Pressure drop actuated
Time actuated
12. Briefly describe how faulty filters will be detected and re-
placed
13. Briefly describe ash handling system from fabric filter to
final disposal
14. Vendor guarantee and terms of guarantee if available
Part II - Reference plant example
1. General flow diagram for the fabric filter
2. Provide design criteria or preliminary engineering data for
the major elements of the fabric filter for the particular
plant under consideration or a similar plant where the above
elements have been designed and exact detailed specifications
are available.
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-10
-------
SCRUBBER DATA
Part I - Preliminary design or design criteria
1. Design data or criteria for the scrubber modules to include:
- Scrubber type (TCS, spray tower, etc.)
- Absorbent type
- Possible scrubber liquor additives (e.g., Mg)
- Prescrubber design criteria, or acceptable ranges for 1/g,
inlet and outlet chloride, etc.
- Design criteria for acceptable ranges for inlet and outlet
gas flow and temperature and volume percent H?0, 0_, and
SO z J
- Specific design criteria or acceptable ranges for liquid/
gas ratio
- Estimated scrubber gas velocity
- Design criteria or acceptable range for scrubber inlet and
outlet pH
- Design criteria or acceptable range of pressure drop
across the scrubber (inches H2
-------
taken to eliminate stack corrosion or provide data to verify
that stack corrosion will not be a problem area.
9. Outline routine maintenance and inspection procedures for
the scrubber system hardware to ensure continuous and reli-
able scrubber performance.
10. Describe the general design standard for the material to be
used and type of mist eliminator system, and describe the
techniques under consideration to guarantee uniform gas
distribution across the mist eliminator and to the scrubber
modules.
11. Vendor guarantees and terms of guarantee if available
Part II - Reference plant example
1. General flow diagram of the scrubber system including mix
tanks, prequench section, scrubber modules, mist eliminator
and reheat. General design standards for materials to be
used to construct above elements.
2. Provide design criteria or design criteria data for the
major scrubber and system components (e.g., sizing of pumps,
clarifier, recirculation tanks, alkali handling systems,
etc.) for the particular plant under consideration or a
similar plant where the above items have been already de-
signed and exact detailed specifications are available.
OTHER CONTROL DEVICES
Type
Specifications (design criteria)
Pollutant removed
Percent collection efficiency (design criteria)
Inlet gas temperature
Inlet gas flow rate
Inlet gas pressure
Pressure drop
Petroleum Refinery Enforcement Manual Appendix I
3/80 1-12
-------
APPENDIX J
LEVEL I INSPECTION: BLANK CHECKLIST FORMS
This appendix provides the cover sheet and checklist form to
be used in conducting a Level I inspection.
Petroleum Refinery Enforcement Manual Appendix J
3/80 J-l
-------
AQCR
LEVEL _ INSPECTION
Date(s) of Inspection
Company Name
Mailing Address
Time In
Out
Location of Facility
(Include County or Parish)
Type of Industry
Form of Ownership
Corporate Address
Company Personnel
Responsible for
Facility
Responsible for
Environmental
Matters
Company Personnel
Contacted
Confidentiality
Statement given to
EPA Personnel
Name
Title
Phone
State or Local
Agency Personnel
Petroleum Refinery Enforcement Manual
3/80 J-2
Appendix J
-------
SOURCE NAME.
ADDRESS
VISIBLE EMISSION OBSERVATION FORM
OBSERVER
DATE
Point of Emission
OBSERVATION
POINT
STACK: DISTANCE FROM
WIND-SPEED
HEIGHT
DIRECTION
SKY CONDITION:
COLOR OF EMISSION:
RELATIVE HUMIDITY:
BACKGROUND:
AMBIENT AIR TEMPERATURE:
CERTIFICATION DATE:
SUMMARY OF AVERAGE OPACITY
Set
Number
Time
Start—End
Opacity
Sum
Average
Observer x
Sun-. Wind — ^ Plume & Stack
CL"
" —
Sou
(
Obse
xe
>
rver
X
Remarks:
0
1
2
3
4
5
6
7
8
9
10
II
12
n
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
0
15
30
45
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
I have received a copy of these opacity
readings
Evaluator's Signature:
title:_
Petroleum Refinery Enforcement Manual
3/80 J-3
Date:
Appendix J
-------
LEVEL I INSPECTION CHECKLIST
I. Heater and Boiler Information
Identification Heater description
Number including unit location Opacity Comments
II. Catalytic Cracker
Identification Type of Pollution Control FCC Sump
Number or Name Process Equipment Stack
CO ESP Cyclones Opacity Comments
Boiler Comments
III. Sulfur Plant
Identification Pollution Control Incinerator Incinerator
Number or Name Equipment Temperature Stack
(°F) Opacity Comments
IV. General Comments
(Note the general housekeeping practices of the refinery.)
Petroleum Refinery Enforcement Mapual Appendix J
3/80 J-4
-------
APPENDIX K
LEVEL II INSPECTION: BLANK CHECKLIST FORMS
This appendix provides the cover sheet and checklist form to
be used in conducting a Level II inspection.
Petroleum Refinery Enforcement Manual Appendix K
3/80 K-l
-------
AQCR
LEVEL _ INSPECTION
Date(s) of Inspection
Company Name
Mailing Address
Time In
Out
Location of Facility
(Include County or Parish)
Type of Industry
Form of Ownership
Corporate Address
Company Personnel
Responsible for
Facility
Responsible for
Environmental
Matters
Company Personnel
Contacted
Confidentiality
Statement given to
EPA Personnel
Name
Title
Phone
State or Local
Agency Personnel
Petroleum Refinery Enforcement Manual
3/80 Kr2
Appepcjix K
-------
SOURCE NAME_
ADDRESS
VISIBLE EMISSION OBSERVATION FORM
OBSERVER
DATE
Point of Emission
OBSERVATION
POINT
STACK: DISTANCE FROM
WIND-SPEED
HEIGHT
DIRECTION
SKY CONDITION:
COLOR OF EMISSION:
RELATIVE HUMIDITY:
BACKGROUND:
AMBIENT AIR TEMPERATURE:
CERTIFICATION DATE:
SUMMARY OF AVERAGE OPACITY
Set
Number
Observe
Sunxjv
Time
Start—End
Opacity
Sum Average
r x
Wind — ^ Plume & Stack
Sou
(
Obse
*ce
i
-ver
X
Remarks:
0
1
2
3
4
5
6
7
8
9
10
II
12
n
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
0
15
30
45
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
0
15
30
45
I have received a copy of these opacity
readings
Evaluator's Signature:
Title:
Petroleum Refinery Enforcement Manual
3/80 K-3
Date;
Appendix K
-------
(Insert refinery flow diagram here.)
Simple process flow diagram.
Petroleum Refinery Enforcement Manual Appendix K
3/80 K-4
-------
PROCESS INFORMATION
u> ^
\ o>
oo rt-
O hf
O
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
g Crude distilla-
3 tion
HI
H-
(D
M
Hi
O
H
O
(D
(D
Vacuum distillation
« S
I ft)
ui 3
Catalytic
reforming
> Isomerization
13
T3
(D
3
Number of atmospheric towers -
Description of towers - preflash,
primary, secondary, tertiary
fractionating towers
Number of atmospheric towers -
Description of towers - preflash,
primary, secondary, tertiary
fractionating towers
Pressure of tower -
Type of vacuum producing system
Pressure of tower
Type of vacuum producing system
Type -
Catalyst
-------
PROCESS INFORMATION
U) *a
\fD
oo rt
O H
O
M
(D
C
3
Hi
H-
3
0)
i-h
O
i-!
O
fD
3
(D
I
en
Process unit
Crude distilla-
tion
Vacuum distilla-
tion
Catalytic
reforming
Isomerization
Feed
Products
Maximum
rate,
barrels/day
Current
rate,
barrels/day
Evaluated for
RACT parti culates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
(D
H-
X
-------
PROCESS INFORMATION
U) ffl
\ro
CO ft
O h!
O
h-1
(D
CD
l-h
H-
3
fD
W
3
Hi
O
H
O
0)
Process unit
RACT requirements
Comments
fu
M
13
'C
0)
Crude distillation
Vacuum distillation
All hot wells must be covered
Catalytic
reforming
Isomerization
Recommended venting to atmosphere after 5 psig
during turnaround
Last shutdown date
Next shutdown date
Last shutdown date
Next shutdown date
P-
X
-------
PROCESS INFORMATION
\ a
JO -r
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
2 Polymerization
JO
D
Alkylation
PI
3
n
Hydrocracking
V § Catalytic
00 § cracking
a>
Coking
Visbreaking
Deasphalting
'o
*3
01
3
O
Type -
Catalyst -
Type of process -
Type of process -
Type of process -
Solvent employed
-------
PROCESS INFORMATION
OO ff
O
(D" Process unit
Polymerization
CD
' HI
H-
CD
n
w
3 Alkylation
HI
o
o
CD
CD
3
rf Hydrocracking
1 QJ
g Catalytic
M cracking
Coking
Visbreaking
.Deasphalting
tr(
Feed
Products
Maximum
rate,
barrels/day
Current
rate,
barrels/day
Evaluated for
RACT particulates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
CD
H-
X
-------
PROCESS INFORMATION
to W
\(D
00 ft
OH
o
I—1
CD
(D
hh
H-
Process unit
RACT requirements
Comments
Polymerization
n> Alkylation
w
3
Hi
O
(D
fD
3
a
H,
X
Hydrocracking
Catalytic
cracking
Coking
Visbreaking
Deasphalting
Last shutdown date
Next shutdown date
-------
PROCESS INFORMATION
CD
S£ Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
(D Hydrotreating
(D
H! Wax production
CD
E;1 Grease production
o
M
o
M 2
Lube production
Asphalt
Gas processing
Sulfur plant
Furfural extrac
> tion
v
T3
(D
X
-------
PROCESS INFORMATION
U) V
\(D
00 ft
O hf
o
M
ID
Hi
H-
3
(D
w
Hi
O
M
O
(D
I
ft
hd *^
XN t^4
I 0)
Process unit
Hydrotreating
Wax production
Grease production
Lube production
Asphalt
Gas processing
Sulfur plant
Furfural extrac-
tion
Feed
—
Products
Maximum
rate,
barrels/day
Current
rate,
barrels/day
Evaluated for
RACT parti culates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
H-
X
-------
PROCESS INFORMATION
OJ V
\o>
00 ft
O H
0>
i
Process unit
RACT requirements
Comments
M
3
Hi
o
n
o
(D
« S
I 0)
M3
co 0
•s
13
(D
3
&
Hi
X
Hydrotreating
2, Wax production
p-
3
(D
Grease production
Lube production
Asphalt
Gas processing
Sulfur plant
Furfural extraction
-------
PROCESS INFORMATION
CO ft
O H
O
H
CD
hh
H-
w
O
CD
3
(D
3
rt
S
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
Amine treating
Other
Type of solvent -
(D
H-
X
-------
PROCESS INFORMATION
U> 'Tj
\ (D
oo rt
0 h(
H- Process unit
3 Amine treating
£
HI
H-
(D
hi
M Other
H)
0
o
(D
Feed
Products
Maximum
rate,
barrels/day
Current
rate,
barrels/day
Evaluated for
RACT parti culates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
rt
*rrf ^
x*« *s*
M P
en
(D
H-
X
-------
PROCESS INFORMATION
u> nd
\tt>
oo rf
o H
Process umt
RACT requirements
Comments
°, Amine treating
(D
I
(0
HI
g Other
w
HI
o
n
o
(D
§
H 3
CD
H-
X
-------
HEATER AND BOILER INFORMATION
\2. Identi-
00 ft , .
on fication
£, Numoer
CD
H)
H-
(D
H
M
hh
0
0
CD
CD
ft
1 PJ
M 3
-J C
Appendix
Heater description
including unit location
Fuel
caoabi 1 i ty
Current
fuel
Du
m i 1 1 i o
Maximum
ty
n Btu/h
Current
Number
of
Stacks
Stack Data
Height (ft)| Diameter (ft)
Exit
Temp.
03ac:-.
-------
HEATER AND BOILER INFORMATION (continued)
Identi-
fication
No.
Heater description
including unit location
Opacity
Petroleum Refinery Enforcement Manual
3/80 K-18
Appendix K
-------
For Particulate, sulfur dioxide, and nitrogen oxide emission
information.
Type of
Fuel used
in Boilers and
Heaters
Heat
Content
Btu/lb or
Btu/scf
Sulfur
Content
Pec.ro J
3/80
Refinery Enforcement Manual
K.19
Appendix K
-------
TANK INFORMATION
Tank
\ 0) Number
00 ft
o n
O
c
••+1
t—
3
cn
?
o
3
<-(•
>N ^S
J D>
i\o a
o c
(U
M
Capacity
(Units)
Type
(D
Product
Stored
True Vapor
Pressure
(Units)
Tank
Color
Construction:
Welded or
Riveted
Vapor
Controls
(2)
Remarks*
D
•D
0)
Q,
M-
X
•7:
Footnotes:
(1) C = fixed roof: F = floating roof; P = pressure; 0 = open top; S = spheroid; H = horizontal;
U = underground
(2) N = None, CV = conservation vents; F = floating roof (SS = single seal; OS = double seal);
VR = Vapor recovery (describe); VD = vapor disposal (describe); VB = vapor balance; SF =
submerged fill
* Date installed, etc.
-------
VOLATILE HYDROCARBON LOADING/UNLOADING FACILITIES
\n> LOADING
SfT FACILITY
° DESIGNATION
HI
H-
3
(D
M
Hi
0
0
fD
(D
rt
1 PJ
to 3
M
(D
3
o.
SOURCE
TYPE TRANSFER/SIZE
(RR CARS, TRUCKS)
MONTHLY
THRU-PUT
(1000 GAL)
VAPOR
CONTROL
SYSTEM
SUBMERGED
LOADING
PRODUCTS
TYPE
VAPOR PRESSURE
(PSIA)
X
-------
WASTEWASTER TREATMENT
Treatment
Facility
In-Plant
Treatment:
Sour Water
Stripper
Primary treat-
ment: -
Separators
1) Interme-
ment: Dis-
solved Air
Flotation
Unit and
holding
basin
Secondary
treatment:
Biological
Oxidation
Tertiary
treatment
!l) Solids
Disposal
Surge
storage
capability
Observation
Noticable emissions (l)
Yes No
Type(s) of separator
Type(s)
Type(s)
Type(s)
Type(s)
Type(s)
Disposition of sulfides (1)
incinerated recovered 1n
sulfur recovery
unit
gaps (or) leaks in cover - inspect
with hydrocarbon detector
Capacity of each
Capacity of each
Capacity of each
Disposal (1)
onsite offsite
Capacity of each
(1)
coverec-
uncovprs*
Type of
cover
Noticable
emissions (1)
Yes No
U> H3
\fl>
00 ft
on
o
M
(D
hh
H-
(D
n
w
3
Hi
o
n
o
(D
I
I
NJ
X Footnotes:
^ (1) Circle one
-------
LEAK DETECTION SURVEY LOG
CD
o
o
M
fD
CD
l-h
H-
3
(D
w
o
51
h
o
§
(D
3
rt
XS
I 0>
KJ 3
U) c
0)
•o
(D
3
Inspection
level II
Sample size 2°
Unit
Isomerization
Accept No. L
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
(A)
00 ft
o n
o
M
(D
50
(D
(D
3
M
HI
O
h
O
(D
3
rt
I
to
•o
(D
B
H-
Inspection
level II
Unit
Alkylation
Sample size 20_
Accept No. L
Component Valves
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO ^
Xrt>
oo rt
o H
O
M
0>
CD
0)
M
I
NJ
on
H-
Inspection
level II
Unjt Alkylation
r.nmpnnpnt Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 5
pt No. 1
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO
\
oo
o
o
M
fD
(D
Hi
H-
3
(D
M
O
K
O
0)
3
(D
ts>
(D
3
Pa
H-
Inspection
level IT
Unit
Storage
Sample size 20
Accept No. 5
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo
o
O
M
CD
50
CD
Hi
H-
s
M
o
fD
I
•o
0)
0
Inspection
level
Unit
Storage
Sample size
2
Accept No.
seals
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CJ *TJ
\CD
OD ft
O H.
O
fD
Hi
H-
3
fD
W
0
H,
O
H
O
fD
CD
0)
00
(U
fD
13
Q<
H-
X
Inspection
level II
Unit Storage
rnmpnnpnt Compressor seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP size 2
pt No. l
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\0>
00
O
00 ft
H
o
I-J
(D
(D
H-
tt>
M
H,
O
I-!
O
I
CD
Inspection
level II
Sample size 20
Unit Loading
rnmpnnpnt Valves
Description of source
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
pt No. 5
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO
\
oo
o
I
co
o
o
M
(D
50
CD
H,
tD
H
l-h
O
H
O
(D
3
(D
0
ft
3
0)
H-
X
Inspection
level II
Unit Loading
r.nmpnnpnt Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP si?p b
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO hj
\
-------
LEAK DETECTION SURVEY LOG
CO *1)
\CD
CD ft
oi-i
o
M
fD
fD
3
fD
B
o
i
fD
I
w
to
•o
(D
3
O.
H-
Inspection
level II
Unit Gas Processing
rnmpnnpnt PumP seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 8
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO h0
\n>
oo rt
o n
o
M
(D
C
CD
Hj
H-
3
(D
W
O
H,
o
l-j
o
fD
3
fD
CO 3
C0£
0)
•s
'O
0)
3
Inspection
level _H_
Gas processing
Sample size
Accept No.
Component
Compressor seals
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\rt>
oo rt
O H
o
M
(D
JO
fD
Hi
H-
3
(D
M
O
fD
3
(D
5 S
I (U
fD
3
&
H-
Inspection
level II
Unit FCC
rnmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 8
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
GJ
\
oo
o
M
(D
(D
Hi
H-
3
CD
M
0
H,
O
H
O
0»
0)
V
Inspection
level II
Unit FCC
rnmpnnpnt PumP seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 5
pt No. 1
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo ft
o H
o
M
0)
pa
0)
Hi
H-
3
(D
M
O
0)
I
(D
H-
X
Inspection
level I3:
Unit FCC
rnmpnnpnt Compressor seals
Description of source
•
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size ^
pt No. l
Maximum VOC
reading
-------
APPENDIX L
LEVEL II INSPECTION: EXAMPLE COMPLETED CHECKLIST FORMS
This appendix provides an example of a completed Level II
checklist.
Petroleum Refinery Enforcement Manual Appendix L
3/80 L-l
-------
LEVEL II, INSPECTION
AQCR QQ3 Date(s) of Inspection
March 17-18, 1980
Time In8:00/9;00 Out 4;00/2;00
Company Name Refinery A
Mailing Address 201 Oil Blvd. Oil City, U.S.A.
Location of Facility County
(Include County or Parish)
Type of Industry Petroleum Refinery
Form of Ownership
Corporate Address
Company Personnel Name Title Phone
Responsible for
Facility Refinery Manager
Responsible for
Environmental
Matters Assistant Manager
Company Personnel Refinery Manager
Contacted
Confidentiality
Statement given to
EPA Personnel
State or Local
Agency Personnel
Petroleum Refinery Enforcement Manual Appendix L
3/80 L-2
-------
OJ TJ
\ fD
CD rt
o i-!
O
M
(D
(D
Hi
H-
0
(D
h
W
3
Hi
O
H
O
(D
3
ft
S
PURCHASED NATURAL GAS
(D
H-
X
FCC: FLUID CATALYTIC CRACKING
LCD: LIGHT CYCLE OIL
REFINERY FLOW DIAGRAM
-------
OJ ^
\ fD
OD rt
^^ I"S
(D
(D
Hi
H-
3
CD
M
Hi
O
h
O
(D
rt
S
i
PROCESS INFORMATION
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
H-
X
Crude distilla-
tion
1
212
Vacuum distillation
Catalytic
reforming
300
Isomerization
Number of atmospheric towers - 2
Description of towers - preflash,
primary, secondary, tertiary
fractionating towers
Number of atmospheric towers -
Description of towers - preflash,
primary, secondary, tertiary
fractionating towers
Pressure of tower - 10 mm Hg absoulte
Type of vacuum producing system - 3 stage
1 contact condenser job
1 surface condenser
Pressure of tower
Type of vacuum producing system
3 Fixed bed reactors
Power former
Type -
Catalyst
-------
PROCESS INFORMATION
\ CD
00 ft
0 H
o
£ Process unit
d
Crude distilla-
£ tion
HI
H-
(D
H
Hi
O
O
(D
3
ro Vacuum disti Ha-
rt tion
1 5"
M
Catalytic
reforming
Qlsomerization
Feed
Sweet crude
Atmospheric
bottoms
Naphtha
Products
Gas
Naphtha
Kerosene
Diesel
Gas oil
Gas oil
Resid
Hydrogen
Gas
Reformate
Maximum
rate,
barrels/day
Current
rate,
barrels/day
20,000
5,000
3,100
Evaluated for
RACT parti culates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
H-
X
-------
PROCESS INFORMATION
(0
n-
n
p
M
(C
(D
l-h
p-
CD
n
w
3
hh
O
H
O
(D
rt
S
V 3
o- d
00
o
Process unit
RACT requirements
Comments
Crude distillation
Vacuum distillation
Catalytic
reforming
Isomerization
ATI hot wells must
1 covered hot well
be covered
Hydrocarbon vapors from surface
condensers are flared.
Recommended venting to atmosphere after 5 psig
during turnaround
Last shutdown date February, 1980
Next shutdown date
Last shutdown date
Next shutdown date
(D
H-
X
-------
(jj T3
oo rt
^^ 1"^
PROCESS INFORMATION
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
c Polymerization
Alkylation
(D
HI
p-
3
(D
K
3
Hi
O
H
O
CD Hydrocracking
P Catalytic
cracking
(a
Coking
Visbreaki.ng
> Deasphalting
(D
3
Cb
H-
400
500
Type - Solid phosphonic acid
Catalyst -
Type of process -
Type of process
UOP design
- Fluid -
Type of process - .
Solvent employed
-------
PROCESS INFORMATION
U> TD
\ CD
CO ft
o n
o
(D
Hi
H-
3
(D
t-f
O
H
O
CD
a
ft
s
Process unit
Polymerization
Alkylation
Hydroc rack ing
Catalytic
cracking
Coking
Visbreaking
Deasphalting
Feed
Gas
Raw gasoline
Gas oil and wax
crude oil
Products
Gas
Propane
Butane
Polymer
Gas
Raw gasoline
Slurry
Maximum
rate,
barrels/day
Current
rate,
barrels/day
2,000
7,000
Evaluated for
RACT particulates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
Primary and
secondary
cyclones
99.9 percent
efficiency
13
-------
PROCESS INFORMATION
\ CD
OO ft
o i-i
o
Process unit
RACT requirements
Comments
<2 Polymerization
50
CD
Hi
P-
CD
^<
W
Hi
O
I-i
O
CD
ft
s
Alkylation
Hydrocracking
^pi Catalytic
1-1 cracking
Coking
Visbreaking
13
CD
l Deasphalting
x
tr1
Last shutdown date
Next shutdown date
February, 1980
Installed 1958
-------
PROCESS INFORMATION
00 ft
Process unit
Number
of units
Identification
number or name
Process description
Refinery terminology
Hydrotreating
Hi
' Wax production
(D
h
^<
w
^
o
H
o
Grease production
(D Lube production
rt
F f»
H£ Asphalt
o PJ
Gas processing
Sulfur plant
Furfural extrac-
tion
H-
X
600
700
Amine treating and claus sulfur plant
-------
PROCESS INFORMATION
00ft
O
M
g Process unit
j*> Hydrotreating
HI
H-
tt>
K: Wax production
w
Hi
o
o Grease production
CD
rt
^Lube production
I 3
Asphalt
Gas processing
Sulfur plant
^Furfural extrac-
H-tion
X
Feed
Sour waste gas
Products
Sulfur
Maximum
rate,
barrels/day
Current
rate,
barrels/day
10 tons/day
Evaluated for
RACT particulates,
carbon monoxfde
sulfur oxide
Pollution
abatement
equipment
-------
PROCESS INFORMATION
oort
on
O
Process unit
RACT requirements
Comments
g Hydrotreating
HI
H- Wax product!on
n
3 Grease production
HI
o
o
(D
jjj Lube production
rt
H£
i» Asphalt
op
M
Gas processing
Sulfur plant
^Furfural extraction
H-
X
-------
ui ^
\ (D —
oo rt
o K
o Process unit
PROCESS INFORMATION
Number
of units
Identification
number or name
Process description
Refinery terminology
(D
Amine treating
1
Sulfur plant
Type of solvent - Monoethgnolamine (MEA)
n>
HI
H-
8 Other
w
H)
O
h
o
(D
PJ
13
t3
(D
H-
f
-------
PROCESS INFORMATION
U) "Xl
00 ft
^D l"i
o
(D
g Process unit
ro Amine treating
HI
H-
0)
M
H\ Other
o
o
(D
3
(D
rt
Feed
Products
Maximum
rate,
barrels/day
Current
rate,
barrels/day
Evaluated for
RACT particulates,
carbon monoxide
sulfur oxide
Pollution
abatement
equipment
I 3
4^ A)
13
(D
H-
F
-------
PROCESS INFORMATION
XfD
con-
Ohf
o
H
(D
Process unit
RACT requirements
Comments
Anrine treating
(0
H)
H-
3
Bother
W
Hi
O
H =
O
(D
3
rt
I
H
01
(D
H-
X
-------
oo
o
(D
O
(D
(D
i-h
H-
3
0>
M
3
Hi
O
h
n
(D
3
o>
HEATER AND BOILER INFORMATION
Identi-
fication
No.
H-l
H-2
H-3
H-4
H-5
Heater description,
including unit location
Crude distillation unit
Crude distillation unit
Reformer
Reformer
FCC
Fuel
capabil ity
Current
fuel
1, 2
1, 2
3
3
3
Duty,
million Btu/h
Maximum
40
20
15
15
8
Current
Number
of
stacks
2
2
1
2
2
Stack data
Height,
ft
55
95
40
40
50
Diameter,
ft
3.0
6.0
4.0
3.5
3.0
Exit temp. ,
°F
350
350
800
800
1200
13
(D
H-
X
1 = Refinery gas. 2 = Natural gas. 3 = No. 6 Fuel oil
-------
HEATER AND BOILER INFORMATION (continued)
Identi-
fication
No.
Heater description
including unit location
Opacity
H-l
H-2
H-3
H-4
H-5
Crude distillation unit
Crude distillation unit
Reformer
Reformer
FCC
0
0
0
10
0
Petroleum Refinery Enforcement Manual
3/80 L-17
Appendix L
-------
For Particulate, sulfur dioxide, and nitrogen oxide emission
information.
Type of
Fuel used
in Boilers and
Heaters
Heat
Content
Btu/lb or
Btu/scf
Sulfur
Content
Refinery gas
No. 6 Fuel oil
800 Btu/scf
6 Btu/bbl
TOO grains H2$/scf
0.9%
Petroleum Refinery Enforcement Manual
3/80 L~18
Appendix L
-------
TANK INFORMATION
OJ
oo
o
O
M
(D
(D
Hi
H-
3
(D
h
HI
o
M
o
rt
S
tr1 PJ
I 3
H e
vo pj
•o
'O
(D
H-
x
Tank
Number
1
2
3
4
5
6
7
8
9
10
Capacity
(Units)
600
600
100
100
100
25
75
75
560
560
Type
(D
C
C
C
C
C
C
C
C
C
C
Product
Stored
Crude oil
Crude oil
Gas oil
Gas oil
Gas oil
Diesel
Unleaded
gasoline
Unleaded
gasoline
Regular
gasoline
Regular
gasoline
True Vapor
Pressure
(Units) psia
2.2
2.2
<1.0
<1.0
<1.0
0.2
5-12
5-12
5-12
5-12
Tank
Color
Gray
Gray
Gray
Gray
Gray
Gray
Gray
Gray
Gray
Gray
Construction:
Welded or
Riveted
Welded
Welded
Welded
Weeded
Welded
Welded
Welded
Welded
Welded
Welded
Vapor
Controls
(2)
F
F
N
N
N
N
VR
VR
VR
VR
Remarks*
Vapor recovery com
pressor system
Vapor recovery com
pressor system
Vapor recovery com
pressor system
Vapor recovery com
pressor system
Footnotes:
(D
(2)
C = fixed roof: F = floating roof; P = pressure; 0 = open top; S = spheroid; H = horizontal;
U - underground
N = None, CV = conservation vents; F = floating roof (SS = single seal; DS = double seal);
VR = Vapor recovery (describe); VD - vapor disposal (describe); VB = vapor balance; SF =
submerged fill
Date installed, etc.
-------
VOLATILE HYDROCARBON LOADING/UNLOADING FACILITIES
CO ft
CD ^
o
M
(D
g
(D
Hi
H-
3
(D
M
3
l-h
O
H
O
CD
3
ft
g
LOADING
FACILITY
DESIGNATION
Loading
Loading
SOURCE
TYPE TRANSFER/SIZE
(RR CARS, TRUCKS)
Truck
Truck
MONTHLY
THRU-PUT
(1000 GAL)
1,500
1,560
VAPOR
CONTROL
SYSTEM
i
SUBMERGED
LOADING
yes (100%)
no
PRODUCTS
TYPE
Gasoline
Propane
Butane
VAPOR PRESSURE
(PSIA)
TO
200
60
0)
H-
F
-------
co il-
OH
0
WASTEWATER TREATMENT
(D Treatment
g facility
^ In-plant
(D treatment:
i-h Sour water
£' stripper
(D
hj Primary treat-
K ment: Gravity
^ separators
c^
0
Hi
0
O
•3 Intermediate
g treatment:
^. Dissolved
air flotation
IS unit and holding
Y£} basin
HP) Secondary
1-1 treatment:
Biological
oxidation
Tertiary
treatment
Solids
disposal
> Surge
'O storage
*5 capability
Observations
Noticeable emissions3
Yes No
Type(s) of separator
3 API
Type(s)
Type(s)
Type(s)
Type(s)
Type(s)
Disposition of sulfides3
Incinerated Recovered in
sulfur recovery
unit
Gaps (or) leaks in cover: Inspect
with hydrocarbon detector
2
1
Capacity of each
Capacity of each
Capacity of each
Disposal3
Onsite Off site
Capacity of each
a
Covered
Uncovered
Type of
cover
fabric
Noticeable
emissions3
Yes (N(T)
H-
X
Circle one.
-------
LEAK DETECTION SURVEY LOG
Petroleum Refinery Enforcement Manua
3/80 L-22
Inspection
level II
Unit Gas Processing
r.nmpnnpnt Valves
Description of source
Gate valve
Gate valve
Control globe valve
Samp
Acce
Stream composition
Gas
X
X
X
Liquid
Stream volatility
High
X
X
X
Low
le size
pt No.
20
5
Maximum VOC
reading
100
40
100
ppm
ppm
ppm
H-
X
-------
APPENDIX M
LEVEL III INSPECTION: BLANK CHECKLIST FORMS
This appendix provides the cover sheet and additional forms
to be used in conducting a Level III inspection. When combined
with the Level II checklist forms (Appendix K), this material
constitutes a Level III inspection report.
Petroleum Refinery Enforcement Manual Appendix M
3/80 M-l
-------
LEVEL _ INSPECTION
AQCR Date(s) of Inspection
Time In Out
Company Name
Mailing Address
Location of Facility
(Include County or Parish)
Type of Industry
Form of Ownership
Corporate Address
Company Personnel Name Title Phone
Responsible for
Facility
Responsible for
Environmental
Matters
Company Personnel
Contacted
Confidentiality
Statement given to
EPA Personnel
State or Local
Agency Personnel
Petroleum Refinery Enforcement Manual Appendix M
3/80 M-2
-------
\
i-h
H-
3
^
.n
O
CD
3
3
Vacuum distillation
Catalytic cracking
Isomerization
X
2
Number of ejectors
Type of ejectors
Type of condensers
Is hot well covered?
Reactor temperature, °F
CO boiler temperature, °F
Oxygen analyzer, % 02
ESP status:
Primary voltage, kW
Primary current, amp
Secondary current, amp
Hopper heaters (on, off)
Hopper level indicators
(full, empty)
Reactor temperature, °F
-------
00
O
'O
'D
ADDITIONAL PROCESS INFORMATION FOR LEVEL III INSPECTIONS
°, Process unit
D
c
-O
t)
Polymerization
Alkylation
n
n
(C
3
0)
Hydrocracking
Catalytic reforming
ft)
Coking
-3
a.
H-
x
3,
Reactor temperature, °F
Reactor temperature, °F
Reactor temperature, °F
Reactor pressure, psig
Hydrogen pressure, psig
-------
ADDITIONAL PROCESS INFORMATION FOR LEVEL III INSPECTION
£, Process unit
i Visbreaking
0)
Deasphalting
• i
$ Hydrotreating
0>
r-f
3 3
d
Reactor temperature, °F
Reactor pressure, psig
Hydrogen pressure, psig
Wax production
Grease production
0)
3
a
H-
X
-------
00 ft
o >-i :
o
ADDITIONAL PROCESS INFORMATION FOR LEVEL III INSPECTION
Process unit
3 Lube production
JO
3
-------
U, Tl
\ ft)
\o r*
o-n
O
r—'
C
3
JO
T>
ADDITIONAL PROCESS INFORMATION FOR LEVEL III INSPECTION
Process unit
n
3
^n
O
h
o
CD
3
(D
33
i »
QJ
0)
-3
Q.
H-
X
3
Amine treating
Hydrocarbon in acid gas feed
-------
LEAK DETECTION SURVEY LOG
oo ft
O H
o
H-1
CD
fD
Ml
H-
0
0)
M
O
l-i
O
fD
3
CD
13
ft
3 S
I 0)
000
e:
OJ
fD
H-
3
Inspection
level Hi
Unit Isomerization
rnmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP Si7C 20
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
co hd
\n>
03 rt
o n
o
i-"
(D
C
50
fl>
HI
H-
W
O
0)
3
0)
0
rt
S S
i &>
VO J3
C
OJ
•o
CD
Inspection
level
Unit
Sample size 50
Alkylation
Accept No.
Component Valves
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\(D
00 ft
OH
o
M
(D
CD
H,
M-
3
(D
l-i
Hi
O
h
O
n>
3
rt
32
I (U
H »
O C
P)
0>
H-
X
2
Inspection
level
Unit
Alkylation
Sample size _JL
1
Accept No.
PuraP seals
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
00 ft
O H
o
M
0)
JO
(D
Hi
H-
0
(D
M
0
HI
O
H.
O
n>
(D
23
I 0>
(U
•o
(D
H-
X
Inspection
level II]C
Unit Storage
rnmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le si7c 50
pt No. 5
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
co t-d
\0>
oo rt
o i-i
o
M
(D
(D
l-h
H-
M
3
H,
O
H
O
n>
n>
ss
I (1)
M 3
Ni tf
I
n>
H-
X
Inspection
level TI1
Sample size
20
Unit Storage
r.ninpnnpnt PumP seals
Description of source
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
to IT)
\tt>
oo rt
O H
50
(D
HI
H,
O
M
O
n>
S g
I (U
fD
H-
X
3
Inspection
level HI
Unit Storage
P.nmpnnpnt Compressor seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 3
pt No. °
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
00 ft
o h
o
(D
(D
H,
H-
9
(D
W
o
(D
1
•o
0>
a
H-
X
2
Inspection
level II1
Um't Loading
T.nmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 50
pt. No. 5
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\0>
05 rh
O H
O
M
(D
CD
HI
(D
M
d
H,
O
H
O
(D
(D
3S
I 0>
M0
tn c
I
(D
H-
2
Inspection
level
Unit
Loading
Sample size
Accept No.
20
seals
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo rt
o n
o
M
01
i-h
H-
0
tt>
M
3
Hi
O
H
O
0)
(P
cy>
•s
•o
n>
X
s
Inspection
level II:E
Unit Gas processing
r.nmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP S1,p 5°
pt No. 5
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
Co hcJ
\0>
oo rt
O H
O
(D
Hi
H-
3
n>
l-h
O
H
O
(D
3
ft
S
(D
H-
3
Inspection
level Hi
Unit Gas processing
fnmpnnpnt P^P seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size ^
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO
\
c»
o
Hi
H-
w
a
H,
O
H
O
0>
00
(D
H-
X
Inspection
level II1
II .:.£ Gas processing
r.nmpnnpnt Compressor seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 3
pt. No. 0
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\n>
oo rt
o n
o
tt>
HI
H-
S3
o
n
o
S3
ft
•o
CD
S3
X
3
Inspection
level II]C
Unit FCC
rnmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size ^
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
00 ftf
\(D
00 ft
O H
o
CD
H,
H-
P
fD
H
M
0
S1
H
O
(D
3
(D
I
Ki
o
CD
3
CL
Inspection
level II][
Sample size
Unit FCC
r.nmpnnpnt Pump seals
Description of source
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
pt No. 1
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\tt>
co rt
O H
O
M
CD
C
0)
Hi
H-
3
CD
W
O
H)
O
H
O
n>
(D
S3
i cu
•O
0)
H-
X
Inspection
level in
Unit FCC
rnmpnnpnt Compressor seals
Description of source
-
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 3
pt No. 0
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo rt
on
o
\->
(D
50
(D
(D
H
S1
I-!
O
(D
3
(D
D
rt
3S
I cu
to o
we
&)
0>
t)
D,
H-
X
Inspection
level in
Unit Visbreaking
r.nmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP 5i7P 20
pt. No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
n>
ff
o
ft)
Hi
H-
3
n>
w
3
H)
o
K
O
33
I (u
N>3
we:
e
•d
(D
H-
X
Inspection
level II:E
Unit Visbreaking
rnmpnnpnt Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 8
pt No. l
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO
\
oo
o
o
M
(D
i-h
H-
W
o
(D
(D
33
0J
(D
H-
3
Inspection
level I3CI
Sample size -L
Unit Visbreaking
rnmpnnpnt Compressor seals
Description of source
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
pt. No. °
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
CO >tl
\n>
oo rt
o n
o
M
tt>
50
0>
HI
H-
w
3
HI
o
H
O
I
I
tt>
X
3
Inspection
level II]C
Unit Hydrotreating
r.nmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 20
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo ft
o n
o
M
(D
CD
Hi
H-
0
(D
W
3
H,
O
h
o
(D
3
rt
S3
I (U
ft
H-
3
Inspection
level I11
Unit Hydrotreating
r.nmpnnpnt Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP size 8
pt No. 1
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
\0>
00 ft
OH
o
M
n>
(D
H,
H-
3
w
HI
o
o
i
(D
S3
I OJ
•o
fD
H-
3!
Inspection
level I:EI
Sample size _
Hydrotreating
Accept No.
Compressor seals
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
c» rt
o H
O
M
(D
50
(D
fD
l-t
O
fD
(D
top
00 £
OJ
0)
13
D.
H-
X
Inspection
level HI
Unit Hydrocracking
r.nmpnnpnt Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 20
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo rt
O h{
O
M
fD
C
tt>
l-h
H-
o
CD
M
O
fD
(D
to
tt>
H-
2
Inspection
level HI
Unit Hydrocrackina
rnmpnnpnt Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size °
pt No. 1
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo rt
o h
O
M
0)
HI
(D
3
M
o
(D
n>
•a
H-
3
Inspection
level I:EI
Unit Hydrocracking
rnmpnnpnt Compressor seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP size 3
pt No. 0
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
GJ hj
\(D
oo r+
O hj
o
I-1
CD
fD
MI
H-
M
3
HI
O
h
o
(D
(D
3! S
I PJ
0)
n>
H-
x
Inspection
level HI
Unit Reformer
Component Valves
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
IP size 20
pt No. 2
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
co hd
\(D
00 rt
O H
O
M
ft)
50
CD
HI
H-
3
(D
H
M
3
M,
O
H
O
CD
33
I (u
co 3
ro c
(D
0
0-
H-
Inspection
level "I
Unit Reformer
rnmpnnpnt. Pump seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 8
pt No. !
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
oo rt
o f-j
o
t->
n>
c
(D
Hi
(D
M
3
M,
O
h
o
n>
(D
ss
I (II
co >3
co c
•s
V
CD
3
CL
H-
Inspection
level III
Unit Reformer
nnmpnnpnt Compressor seals
Description of source
Samp
Acce
Stream composition
Gas
Liquid
Stream volatility
High
Low
le size 3
pt No. 0
Maximum VOC
reading
-------
LEAK DETECTION SURVEY LOG
00 ft
O l-(
o
H-1
(D
£
50
(D
l-h
H-
3
(D
H
l-h
O
n
o
U3
OJ
0)
B
H-
Inspection
level
Unit Distillation - atmospheric
Sample size 20
Accept No. 2
Description of source
Stream composition
Gas
Liquid
Stream volatility
High
Low
Maximum VOC
reading
-------
GLOSSARY
The definitions herein are those in current use in the
United States refining industry. Conversions of units of measure
to the metric system have not been included in most cases, be-
cause the English system continues to dominate the industry.
An ASTM number is a reference to a testing method defined by
the American Society for Testing and Materials.
ABSORPTION: An operation in which the significant or desired
transfer of materials is from the vapor phase to the liquid
phase. Absorption usually designates an operation in which
liquid is supplied as a separate stream independent of the
vapor being treated.
ACID HEAT TEST: A test indicative of unsaturated components in
petroleum distillates. The test measures the amount of re-
action of unsaturated hydrocarbons with sulfuric acid
(H2S04).
ADSORPTION: A separation process in which gas molecules condense
or liquid molecules crystallize onto a solid that has a
porous surface. The pore size dictates the selectivity of
the solid for a particular solute.
ALKYLATE: The product of an alkylation process.
ALKYLATE BOTTOMS: A thick, dark-brown oil containing high-molec-
ular-weight polymerization products of alkylation reactions.
ALKYLATION: A polymerization process uniting olefins and isopar-
affins: particularly, the reacting of butylene and iso-
butane, with sulfuric acid or hydrofluoric acid as a cat-
alyst, to produce a high-octane, low-sensitivity blending
agent for gasoline.
ALUMINUM CHLORIDE TREATING: A process that improves the quality
of steam-cracked naphthas by use of aluminum chloride
(AlCla) as a catalyst. The process improves the color and
odor of the naphtha by polymerization of undesirable olefins
into resins. Aluminum chloride treating is also used when
production of resins is desirable.
Petroleum Refinery Enforcement Manual Glossary
3/80 1
-------
ANILINE POINT: The minimum temperature for complete miscibility
of equal volumes of aniline and the test sample. The point
test is considered an indication of the paraffinicity of the
sample. The aniline point is also used in classifying the
ignition quality of diesel fuels.
API GRAVITY: An arbitrary gravity indicator defined as:
141.5
3 API =
Specific gravity 60/60°F - 131.5
This formula allows representation of the specific gravity
of oils, which on the 60/60° scale (density of substance at
60°F divided by the density of pure water at 60°F) varies
over a range of only 0.776 by a scale that ranges from less
than 0 (heavy residual oil) to 340 (methane). API gravities
are not usually accompanied by temperature; they correspond
to a temperature of 60°F unless otherwise indicated.
AROMATICS: Cyclic hydrocarbons in which five, six, or seven
carbon atoms are linked in a ring structure with alternating
double and single bonds. Common aromatics in refinery
streams are benzene, toluene, xylene, and naphthalene.
ASTM: American Society for Testing and Materials.
ASTM DISTILLATION: A standardized laboratory batch process for
distillation of naphthas and middle distillates carried out
at atmospheric pressure without fractionation.
BARREL: 42 gallons.
BARRELS PER CALENDAR DAY (BPCD): Average flow rates based on
operating 365 days per year.
BARRELS PER STREAM DAY (BPSD): Flow rates based on actual on-
stream time of a unit or group of units. This notation
equals barrels per calendar day divided by the service
factor.
BATTERY LIMITS (BL): The periphery of the area surrounding any
process unit, including the equipment used in the process.
B-B: Butane-butylene fraction.
BFOE: Barrels fuel oil equivalent based on net heating value
(LHV) of 6,050,000 Btu per BFOE.
Petroleum Refinery Enforcement Manual Glossary
3/80 2
-------
BITUMEN: That component of petroleum, asphalt, and tar products
that will dissolve completely in carbon disulfide (CS2).
This dissolving ability permits a complete separation from
foreign products not soluble in carbon disulfide.
BLENDING: One of the final operations in refining, in which two
or more components are mixed to obtain a specified range of
properties in the finished product.
BLOCKED OPERATION: Operation of a unit, e.g., a pipe still,
under periodic change of feed or internal conditions that
will yield a required range of raw products. Blocked oper-
ation is needed to meet critical specifications of various
finished products. No mixed stocks are charged; therefore,
the efficiency of operation is often increased because each
charge stock is processed at its optimum operating condi-
tions.
BOTTOMS: In general, the higher boiling residue that is removed
from the bottom of a fractionating column.
BRIGHT STOCK: Heavy lube oils from which waxy paraffins and
asphaltic compounds have been removed. Bright stock is the
feed to a lube oil blending plant.
BROMINE INDEX: Measure of amount of bromine-reactive material in
a sample; ASTM D-2710.
BROMINE NUMBER: Indicator of the degree of unsaturation in a
test sample; ASTM D-1159.
CABP: Cubic average boiling point.
h 1/3 3
CABP =
1^ XviTbi
where
vi = volume fraction of component i.
T
bi = normal boiling point of component i.
CAFFEINE NUMBER: A value indicating the amount of carcinogenic
compounds (high-molecular-weight aromatics, or "tars") in an
oil.
CATALYST: A substance that assists or deters a chemical reaction
but is not itself chemically changed as a result.
Petroleum Refinery Enforcement Manual Glossary
3/80 3
-------
CATALYST/OIL RATIO (C/0): The weight of circulating catalyst fed
to the reactor of a fluid-bed catalytic cracking unit,
divided by the weight of the hydrocarbons charged during the
same interval.
CATALYTIC CYCLE STOCK: The portion of a catalytic cracker efflu-
ent that is not converted to naphtha and lighter products.
This material, generally at temperatures of 340°F or more,
may either be completely recycled or it may be partly recy-
cled, in which case the remainder is blended to products or
further processed.
CETANE NUMBER: A number designating the percentage of pure
cetane in a blend of cetane and alphamethyl-naphthalene that
matches the ignition quality of a diesel fuel sample. This
number, specified for middle distillate fuels, is synonymous
with the octane number of gasolines.
CFR: Code of Federal Regulations.
CFR: Combined feed ratio. Ratio of total feed (including recy-
cle) to fresh feed.
CHARACTERIZATION FACTOR: An index of feedstock quality, also
useful for correlating data based on physical properties
such as average boiling point and specific gravity.
CLAY TREATING: A process conducted at high temperatures and
pressures, usually applied to thermally cracked naphthas to
improve stability and color. Stability is increased by the
adsorption and polymerization of reactive diolefins in the
cracked naphtha. Clay treating is now used extensively for
treating jet fuel to remove surface-active agents that
adversely affect the wastewater separator.
CLOUD POINT: The temperature at which solidifiable compounds in
a sample begin to crystallize or separate from the solution
under prescribed conditions of chilling. Cloud point is a
typical specification of middle distillate fuels; ASTM
D-2500.
CONRADSON CARBON TEST: A test used to determine the amount of
carbon residue left after evaporation and pyrolysis of an
oil under specified conditions. Expressed as percent by
weight; ASTM D-189.
CRACKING: The breaking down of higher-molecular-weight hydrocar-
bons to lighter components by application of heat. Cracking
in the presence of a catalyst improves product yield and
quality over those obtained in simple thermal cracking.
Petroleum Refinery Enforcement Manual Glossary
3/80 4
-------
CRUDE ASSAY DISTILLATION: See fifteen/five distillation.
CUT: The portion of a crude that boils within certain tempera-
ture limits. Usually the limits are specified on a crude
assay true boiling point basis.
CUT POINT: The temperature limit of a cut, usually on a true
boiling point basis. ASTM distillation cut points are not
uncommon .
DEBUTANIZER: A tower in which butane is removed by distillation
from a hydrocarbon stream.
DEISOBUTANIZER: A distillation column in which isobutane is re-
moved from a petroleum fraction.
DEWAXING: The removal of wax from lubricating oils, either by
chilling and filtering or by solvent extraction.
DIESEL INDEX (DI): A measure of the ignition quality of a diesel
fuel. The diesel index is defined as
DI = gravity <°API> X anine Point <°F)
The higher the diesel index, the higher the ignition quality
of the fuel. By means of correlations unique to each crude
and manufacturing process, this index can be used to predict
cetane number if no standardized test for the latter is
available.
DISTILLATE: A product of distillation, or the fluid condensed
from the vapor driven off during distillation. Gasoline,
naphtha, kerosene, and light lubricating oils are examples
of distillates.
DISTILLATION: A physical separation process in which different
hydrocarbon fractions are separated by means of heating,
vaporization, fractionation, condensation, and cooling.
DOCTOR TEST: A method of determining the presence of mercaptan
sulfur in petroleum products. This test is used for pro-
ducts in which a "sweet" odor is desirable for commercial
reasons, especially naphthas; ASTM D-484.
DRY GAS: All methane (Ci) to propane (Cs) material, whether
associated with a crude or produced as a byproduct of refin-
ery processing. By convention, hydrogen is often included
in dry-gas yields .
Petroleum Refinery Enforcement Manual Glossary
3/80 5
-------
END POINT (EP): Upper temperature limit of a distillation.
ENDOTHERMIC REACTION: A reaction in which heat must be added to
maintain reactants and products at a constant temperature.
EXOTHERMIC REACTION: A reaction in which heat is evolved.
Alkylation, polymerization, and hydrogenation reactions are
exothermic.
FBP: The final boiling point of a cut, in degrees Fahrenheit,
usually on an ASTM distillation basis.
FIFTEEN/FIVE (15/5) DISTILLATION: A laboratory batch distilla-
tion performed in a theoretical plate fractionating column
with a three-to-one reflux ratio. A good fractionation re-
sults in accurate boiling temperatures. For this reason,
the distillation is referred to as the true-boiling-point
(TBP) distillation.
FIXED CARBON: The organic portion of the residual coke obtained
when hydrocarbon products are evaporated to dryness in the
absence of air..
FLASH POINT: The temperature to which a product must be heated
under prescribed conditions to release sufficient vapor to
form a mixture with air that can be readily ignited. Flash
point is generally used as an indication of the fire and
explosion potential of a product; ASTM D-56, D-92, D-93,
E-134, D-1310.
FLUX: A material blended in small amounts with a product to meet
some specification of the final product.
FOE: Fuel oil equivalent.
FRACTIONATION: A countercurrent operation in which a vapor mix-
ture is repeatedly brought in contact with liquids having
nearly the same composition as the respective vapors.
Liquids are at their boiling points; hence part of the vapor
is condensed and part of the liquid is vaporized during each
contact. In a series of contact treatments, the vapor
finally becomes rich in low-boiling components, and the
liquid becomes rich in high-boiling components.
FRACTIONATOR: A closed cylindrical tower arranged with trays
through which distilled gas/liquid is caused to bubble. The
trays retain a portion of the condensed liquid and thus
separate the heavier fractions of the gas/liquid from the
lighter fractions of gas/liquid. Also called stabilizer
column, fractionating tower, or bubble tower.
Petroleum Refinery Enforcement Manual Glossary
3/80 6
-------
FREE CARBON: The organic matter in tars that is insoluble in
carbon disulfide
FUEL OIL EQUIVALENT (FOE): The heating value of a standard
barrel of fuel oil, equal to 6.05 x 106 Btu. On a yield
chart, dry gas and refinery fuel gas are usually expressed
in FOE barrels.
FVT: The final vapor temperature of a cut, in degrees Fahren-
heit. Boiling ranges expressed in this manner are usually
on a crude assay, true-boiling-point basis.
GAS OIL: That material boiling within the general range of 300°
to 750 °F. This range usually includes kerosene, diesel
fuel, heating oils, and light fuel oils. Actual initial and
final cut points are determined by specifications of the
desired products.
GHV: Gross heating value of fuels.
GILSONITE: A trade name for uintaite, a black, lustrous asphalt.
HEART CUT RECYCLE: The unconverted portion of catalytically
cracked material that is recycled to the catalytic cracker.
This recycle is usually in the boiling range of the feed
and, by definition, contains no bottoms. Recycle allows
less severe operation and suppresses the cracking of desir-
able products.
HEMPEL DISTILLATION: Routine distillation method of the U.S.
Bureau of Mines. Results are frequently used interchange-
ably with those of true boiling point (TBP) or 15/5 distil-
lation.
IBP: Initial boiling point of a cut, usually on an ASTM distil-
lation basis.
ISOBUTANE: A branched-chain butane compound (C^xo).
ISOMERIZATE: The product of an isomerization process.
ISOMERIZATION: The rearrangement of straight-chain hydrocarbon
molecules to form branched-chain products. Pentanes and
hexanes, which are difficult to reform, are isomerized by
use of aluminum chloride or precious-metal catalysts to form
gasoline-blending components of high octane value. Normal
butane may be isomerized to provide a portion of the isobu-
tane feed needed for alkylation processes.
IVT: Initial vapor temperature of a cut, in degrees Fahrenheit,
usually based on a crude assay distillation.
Petroleum Refinery Enforcement Manual Glossary
3/80 7
-------
KEROSENE: A middle-distillate product composed of material of
300° to 550° FVT. The exact cut is determined by various
specifications of the finished kerosene.
LAMP SULFUR: The total amount of sulfur present per unit of
liquid product. The analysis is made by burning a sample so
that the sulfur content is converted to sulfur dioxide,
which can be measured quantitatively. Lamp sulfur is a
critical specification of all motor, tractor, and burner
fuels; ASTM D-1266, D-2784.
LEAD SUSCEPTIBILITY: The variation of the octane number of a
gasoline as a function of the tetraethyl lead content.
LHSV: Liquid hour space velocity: volume of feed per hour per
volume of catalyst.
LHV: Lower heating value of fuels (net heat of combustion).
LIGHT ENDS: Hydrocarbon fractions in the butane and lighter
boiling range.
LIQUEFIED PETROLEUM GAS (LPG): Liquefied light-end gases used
for home heating and cooking. This gas is usually 95 per-
cent propane, and the remainder consists of equal parts of
ethane and butane.
LNG: Liquefied natural gas.
LUBRICATING OILS: A fluid used to reduce friction when intro-
duced between solid surfaces. The major constituents of
lubricating oils are from distillate or residual fractions
of the crude. The manufacture and compounding of lubri-
cating oils are highly specialized and confined to a few
major refineries. Some refineries produce lube base stocks
(bright oils), which are transferred to a refinery special-
izing in lube oil finishing and compounding.
MABP: Molal average boiling point.
h
MABP = 1 X.T, •
i=l X bl
MeABP: Mean average boiling point.
MeABP = MABP + CABP
2
METAXYLENE: One of the three isomers of xylene.
Petroleum Refinery Enforcement Manual Glossary
3/80 8
-------
MID-BOILING POINT: That temperature, usually based on a crude
assay distillation, at which one-half of the material of a
cut has been vaporized.
MIDDLE DISTILLATES: Atmospheric pipe-still cuts boiling in the
range of 300° to 700° FVT. The exact cut is determined by
the specifications of the products.
MID-PERCENT POINT: The vapor temperature at which one-half of
the material of a cut has been vaporized. Mid-percent point
is often used in place of temperature to characterize a cut.
MONOMER: A reactive species fed to a polymerization unit which
reacts in a repetitive manner to form long polymer chains.
Typical monomers are ethylene, propylene, styrene, and vinyl
chloride.
MOTOR OCTANE NUMBER (MON, ASTM ON, F-2): The percentage by
volume of isooctane in a blend of isooctane and n-heptane
that knocks with the same intensity as a fuel being tested.
A standardized test engine operating under standardized
conditions (900 rpm) is used to approximate cruising condi-
tions of an automobile; ASTM D-2723.
NAPHTHA: A pipe-still cut in the range of 160° to 420°F. Pen-
tanes (C5) are the lower boiling naphthas, at approximately
160°F. Naphthas are subdivided according to the actual
pipe-still cuts into light, intermediate, heavy, and very
heavy virgin naphthas. The quantity of the individual cut
varies with the crude. A typical pipe-still operation would
yield:
C5-160°F - Light virgin naphtha
160°-280°F - Intermediate virgin naphtha
280°-330°F - Heavy virgin naphtha
330°-420°F - Very heavy virgin naphtha
Naphthas, the major constituents of gasoline, generally must
be further processed to make suitable quality gasoline.
NEUTRALIZATION NUMBER: The quantity of acid or base that is
required to neutralize all basic or acidic components pre-
sent in a sample of specified quantity. This is a measure
of the amount of oxidation of a product in storage or in
service; ASTM D-664, D-974.
OLEFIN SPACE VELOCITY: Volume of olefin charged per hour to an
alkylation reactor, divided by the volume of acid in the
reactor.
Petroleum Refinery Enforcement Manual Glossary
3/80 9
-------
ORTHOXYLENE: One of the three isomers of xylene.
PARAFFINIC RAFFINATES: Straight-chain, saturated hydrocarbon
fraction remaining after distillation or extraction.
PARAXYLENE: One of the three isomers of xylene.
PERFORMANCE RATING: A method of expressing the quality of a
high-octane gasoline relative to isooctane. This rating is
used for fuels of higher quality than isooctane.
PETROLEUM FRACTION: A major product that may be separated from
petroleum, i.e., gasoline, kerosene, gas oil; an elementary
compound with a constant boiling range. Heavier fractions
have higher boiling ranges than lighter fractions.
PIPE STILL: A heater or furnace containing tubes through which
oil is pumped while being heated or vaporized. Pipe stills
are fired with waste gas, natural gas, or heavy oils. With
provision for rapid heating under conditions of high pres-
sure and temperature, pipe stills are useful for thermal
cracking as well as distillation applications.
POLYMERIZATION: The combination of two or more unsaturated mole-
cules to form a molecule of higher molecular weight. Propy-
lenes and butylenes are the primary feed material for refin-
ery polymerization processes, which use solid or liquid
phosphoric acid catalysts.
POUR BLENDING INDEX (PBI): An empirical quantity related to pour
point, which allows volumetric blending of pour points of
various blend components. This method of blending is most
accurate for blending of similar fractions of the same
crude.
POUR POINT: The lowest temperature at which a petroleum oil will
flow or pour when it is chilled, and poured without distur-
bance at a standard rate. Pour point is a critical specifi-
cation of middle distillate products used in cold climates;
ASTM D-99.
PROPYLENE: A hydrocarbon compound containing three carbon atoms,
seven hydrogen atoms, and a double bond making it unsatu-
rated and highly reactive.
RAFFINATE: The residue recovered from an extraction process. An
example is the S02 extraction of raw kerosene. The S02
raffinate is relatively free of aromatics and other impuri-
ties that have poor burning characteristics.
RAMSBOTTOM CARBON: Recommended to replace Conradson Carbon; ASTM
D-524. Carbon residue expressed in percent by weight.
Petroleum Refinery Enforcement Manual Glossary
3/80 10
-------
RECONSTITUTED CRUDE: A crude to which has been added a specific
crude fraction for the purpose of meeting some product
volume unattainable with the original crude.
REDUCED CRUDE: A crude whose API gravity has been reduced by
distillation of the lighter, lower boiling constituents.
REFORMATS: A reformed naphtha that is upgraded in octane value
by means of catalytic or thermal reforming.
REFORMING: The conversion of naphtha fractions to products of
higher octane value. Thermal reforming is essentially a
light cracking process applied to heavy naphthas to increase
the yields of hydrocarbons in the gasoline boiling range.
Catalytic reforming is applied to various straight-run
cracked naphtha fractions and consists primarily of the
dehydrogenation of naphthenes to aromatics. A number of
catalysts are used, including platinum, platinum-rhenium,
and the oxides of aluminum, chromium, molybdenum, cobalt,
and silicon. A high partial pressure of hydrogen is main-
tained to prevent the formation of excessive coke.
REID VAPOR PRESSURE (RVP): The vapor pressure of a product de-
termined in a volume of air 4 times the liquid volume at
100°F. Reid vapor pressure is an indication of the vapor-
lock tendency of a motor gasoline, as well as of explosion
and evaporation hazards; ASTM D-323.
RESEARCH OCTANE NUMBER (R9N, CFRR, F-l): The percentage by
volume of isooctane in a blend of isooctane and n-heptane
that knocks with the same intensity as a fuel being tested.
A standardized test engine operating under standardized
conditions (600 rpm) is used. Results are comparable to
those obtained in an automatic engine operated at low speed;
ASTM D-2722.
ROAD OCTANE NUMBER: The percentage by volume of isooctane that
would be required in a blend of isooctane and n-heptane to
give incipient knock in an automobile engine operating under
the same conditions of engine load, speed, and degree of
spark advance as that of a fuel being tested.
SCF: Volume of gas in "standard cubic feet." Standard condi-
tions in petroleum and natural gas usage refer to a pressure
base of 14.696 psia and a temperature base of 60°F.
SELECTIVITY: Ratio of desirable to undesirable products.
SENSITIVITY: The difference between the research octane number
and the motor octane number of a given gasoline. Alkylate
is an excellent low-sensitivity gasoline component.
Petroleum Refinery Enforcement Manual Glossary
3/80 11
-------
SERVICE FACTOR: A quantity that relates the actual on-stream
time of a process unit to the total time available for use.
Service factors include both expected and unexpected unit
shutdowns.
SEVERITY: The degree of intensity of the operating conditions of
a process unit. Severity may be indicated by clear research
octane number of the product, percent yield of the product,
or operating conditions alone.
SMOKE POINT: A test measuring the burning quality of jet fuels,
kerosene, and illuminating oils. It is defined as the
height of the flame in millimeters beyond which smoking
takes place; ASTM D-1322.
SOUR OR SWEET CRUDE: A general classification of crudes accord-
ing to sulfur content. Various definitions are available:
Sour Crude; A crude that contains sulfur in amounts greater
than 0.5 to 1 percent or that contains 0.05 ft3 or more of
hydrogen sulfide (H^S) per 100 gal, except West Texas crude,
which is always considered sour regardless of its hydrogen
sulfide content. Arabian crudes, although of high sulfur
content, are not always considered sour because they do not
contain highly active sulfur compounds.
Sweet Crude; A sweet crude contains little or no dissolved
hydrogen sulfide and relatively small amounts of mercaptans
and other sulfur compounds.
SPACE VELOCITY: The volume (or weight) of gas or liquid passing
through a given catalyst or reaction space per unit time,
divided by the volume (or weight) of catalyst through which
the fluid passes. High space velocities correspond to short
reaction times. See LHSV and WHSV.
STABILIZATION: A fractionation operation conducted for the pur-
pose of removing high-vapor-pressure components.
STRAIGHT-RUN GASOLINE: An uncracked gasoline fraction distilled
from crude. Straight-run gasolines contain primarily paraf-
finic hydrocarbons and have lower octane values than cracked
gasolines from the same feedstocks.
STRIPPING: An operation in which the significant or desired
transfer of material is from the liquid to the vapor phase.
SWEETENING: The removal of sulfur compounds or their conversion
to innocuous substances in a petroleum product by any of
several processes (doctor treating, caustic and water wash-
ing, etc.).
Petroleum Refinery Enforcement Manual Glossary
3/80 12
-------
SYNTHETIC CRUDE: Wide-boiling-range product of catalytic crack-
ing.
TA: Total alkylate.
TAIL GAS: Light gases (Ci to C3 and H2) produced as byproducts
of refinery processing.
TBP DISTILLATION: See fifteen-five (15/5) distillation.
TETRAETHYL LEAD (TEL): An antiknock additive for gasoline.
THEORETICAL PLATE: A theoretical contacting unit useful in
distillation calculations. Vapors and liquid leaving any
such unit are required to be in equilibrium under the ap-
plicable conditions of temperature and pressure. An actual
fractionator tray or plate is generally less effective than
a theoretical plate. The ratio of the number of theoretical
plates required to perform a given distillation separation
to the number of actual plates used gives the tray effi-
ciency of the fractionator.
TOPPING: Removal by distillation of the light products from
crude oil, leaving in the still all the heavier constitu-
ents.
TREAT GAS: Light gas, usually high in hydrogen, which is re-
quired for refinery hydrotreating processes such as hydro-
desulfurization. The treat gas for hydrodesulfurization is
usually the tail gas from catalytic reforming.
TUBE STILL: See pipe still.
U.S. BUREAU OF MINES ROUTINE METHOD DISTILLATION: See Hempel
distillation.
VAPOR LOCK INDEX: A measure of the tendency of a gasoline to
generate excessive vapors in the fuel line, thus causing
displacement of liquid fuel and subsequent interruption of
normal engine operation. The vapor lock index generally is
related to RVP and to percentages distilled at 158°F.
VIRGIN STOCKS: Petroleum oils that have not been cracked or
otherwise subjected to any treatment that would produce
appreciable chemical change.
VISCOSITY: The property of liquids under flow conditions that
causes them to resist instantaneous change of shape or
instantaneous rearrangement of their parts due to internal
friction. Viscosity is generally measured as the number of
seconds, at a definite temperature, required for a standard
quantity of oil to flow through a standard apparatus.
Petroleum Refinery Enforcement Manual Glossary
3/80 13
-------
Common viscosity scales in use are Saybolt Universal, Say-
bolt Furol, and Kinematic (Stokes).
VOLATILITY FACTOR: An empirical quantity that indicates good
gasoline performance with respect to volatility. It in-
volves actual automobile operating conditions and climatic
factors. The volatility factor is generally defined as a
function of RVP, and of percentages distilled at 158° and
212°F. This factor is used to predict the vapor-lock ten-
dency of a gasoline.
WABP: Weight average boiling point.
WABP = Z
where
X . = weight fraction of component i.
WHSV: Weight hour space velocity: weight of feed per hour per
weight of catalyst.
WICK CHAR TEST: A test used to indicate the burning quality of a
kerosene or illuminating oil. Wick char is defined as the
weight of deposits remaining on the wick after a specified
quantity of sample is burned.
XYLENE: Special name given to dimethyIbenzene.
Petroleum Refinery Enforcement Manual Glossary
3/80 14
-------
BIBLIOGRAPHY
ALKYLATION
Acid-Soluble Oils Occupy Attention of HF Alkylation Users. Oil
and Gas Journal, Apr. 14, 1975. p. 62.
Hydrocarbon Processing, 38 (9): 166-168, Sept. 1959.
Hydrocarbon Processing, 55 (9): 185-188, Sept. 1976.
Hydrocarbon Processing, 57 (9): 173-176, Sept. 1978.
Kirk-Othmer Encyclopedia of Chemical Technology. 3rd ed. Vol 2
John Wiley & Sons, New York, 1978. pp. 50-71.
Petrochemical & Petroleum Refining. The Chemical Engineering
Progress Symposium Series, 57 (34): 39-41, 1961.
Refining Handbook. Hydrocarbon Processing, 57 (9): 173-176,
Sept. 1978.
CATALYTIC CRACKING
Chemical Engineering Progress, 65 (6): 88-93, June 1969.
Hydrocarbon Processing, 51 (5): 89-97, May 1972.
Hydrocarbon Processing, 54 (9): 93-100, Sept. 1975.
Hydrocarbon Processing, 55 (9): 113-120, Sept. 1976.
Hydrocarbon Processing, 57 (9): 101-102, 105, 107-112, Sept.
1978.
Oil and Gas Journal, 70 (44): 49-54, Oct. 30, 1972.
Oil and Gas Journal, 72 (2): 53-55, June 4, 1974.
Petroleum Refinery Enforcement Manual Bibliography
3/80 1
-------
CATALYTIC REFORMING
Cracking/Reforming Combination Has Pluses, Oil and Gas Journal,
Feb. 13, 1978. pp. 118-120.
Hooper, Cecil, and Chambers. Paper presented at the 38th Midyear
API Refining Meeting, Philadelphia, Pennsylvania, May 15,
1973.
Hydrocarbon Processing, 53 (6): 111-114, June 1974.
Hydrocarbon Processing, 55 (5): 75-80, May 1976.
Hydrocarbon Processing, 55 (9): 171-178, Sept. 1976.
Hydrocarbon Processing, 57 (9): 159-166, Sept. 1978.
Nelson, W. L. Petroleum Refining Engineering. 4th ed. McGraw-
Hill Book Co., New York, 1969. pp. 810-818.
Oil and Gas Journal, 70 (21): 52-55, May 22, 1972.
Oil and Gas Journal, 74 (3): 48-52, Jan. 19, 1976.
Radford, Moore, and Petersen. API Division of Refining. Reprint
24-69. May 1969.
Refiners Focus on Octane Reformers. Oil and Gas Journal,
April 30, 1979. pp. 247-253.
COKING
Blazer, and Edelman. Paper presented at the API Refining Meet-
ing, Toronto, Canada, May 10, 1978.
Hydrocarbon Processing, 33 (9): 43-44, Sept. 1954.
Hydrocarbon Processing, 50 (9): 137-141, Sept. 1971.
Hydrocarbon Processing, 54 (4): 145-150, Apr. 1975.
Hydrocarbon Processing, 54 (6): 97-104, June 1975.
Hydrocarbon Processing, 55 (9): 109-112, Sept. 1976.
Hydrocarbon Processing, 57 (9): 101-104, Sept. 1978.
Petroleum Refinery Enforcement Manual Bibliography
3/80 2
-------
CRUDE DISTILLATION
Hydrocarbon Processing, 51 (9):
Hydrocarbon Processing, 55 (9):
Hydrocarbon Processing, 57 (9):
217, Sept. 1972.
106-108, Sept. 1976,
100, Sept. 1978.
DEASPHALTING
Hydrocarbon Processing, 52 (5): 110-113, May 1973.
Hydrocarbon Processing, 57 (9): 197, Sept. 1978.
DESALTING
Hydrocarbon Processing, 55 (9): 106-108, Sept. 1976.
Hydrocarbon Processing, 57 (9): 177-178, Sept. 1978.
Petroleum Refining With Chemicals. Elsevier Publishing Co.,
New York, 1956, p. 8.
HYDROCRACKING
Bennet, and Elkes. Paper presented at NPRA Meeting, Houston,
Texas, Nov. 6-8, 1974.
Celestions. Paper presented at the Ninth Arab Petroleum Con-
gress, Dubai, Mar. 10-16, 1975.
Craig, Fowler, and Raczynski. Paper presented at the American
Chemical Society Meeting, Minneapolis, Minnesota, Apr. 14,
1969.
Edelman. Paper presented at the Japanese Petroleum Institute,
May 8, 1975.
Hydrocarbon Processing, 31 (6): 108-109, June 1952.
Hydrocarbon Processing, 34 (6): 118-122, June 1955.
Hydrocarbon Processing, 34 (9): 152-154, Sept. 1955.
Hydrocarbon Processing, 36 (9): 233-235, Sept. 1957.
Hydrocarbon Processing, 39 (11): 251-253, Nov. 1960.
Hydrocarbon Processing, 45 (5): 149-152, May 1966.
Petroleum Refinery Enforcement Manual
3/80 3
Bibliography
-------
Hydrocarbon Processing, 49 (8): 113-114, Aug. 1970.
Hydrocarbon Processing, 49 (11): 187-191, Nov. 1970.
Hydrocarbon Processing, 52 (9): 131-133, Sept. 1973.
Hydrocarbon Processing, 54 (5): 74-81, May 1975.
Hydrocarbon Processing, 55 (7): 105-108, July 1976.
Hydrocarbon Processing, 55 (9): 129-170, Sept. 1976.
Hydrocarbon Processing, 57 (9): 121-158, Sept. 1978.
Oil and Gas Journal, 69 (41): 75-77, Oct. 11, 1971
Oil and Gas Journal, 70 (24): 94, June 12, 1972.
Oil and Gas Journal, 71 (38): 66-68, Sept. 17, 1973
Oil and Gas Journal, 72 (33): 65, 68, Aug. 17, 1974.
Oil and Gas Journal, 73 (11): 59-63, Apr. 28, 1975.
Paper F & L No. 72-44. NPRA Fuels and Lubricants Meeting,
New York, Sept. 1972.
Paper No. 51-69. API Division of Refining Meeting, Chicago,
Illinois, May 13, 1969.
Petroleum Engineer, 28 (3): C-37 through C-44, Mar. 1956.
Skripek. Paper presented at the 19th Annual Meeting of the
AIChE, Houston, Texas, Mar. 16, 1926.
Turnock. Paper presented at the Japanese Petroleum Institute,
May 8-9, 1975.
ISOMERIZATION
Alkylation and Isomerization. Oil and Gas Journal, Jan. 26,
1959. p. 18.
Burbridge. Paper presented at NPRA, San Antonio, Texas,
Mar. 23-25, 1975.
Burbridge, B. W., and J. R. Rolfe. BP's Isom Process Goes Com-
mercial. Hydrocarbon Processing, 45 (8): 168, Aug. 1966.
Collins. Paper presented at NPRA, San Antonio, Texas, Mar. 19-21,
1978.
Petroleum Refinery Enforcement Manual Bibliography
3/80 4
-------
Erickson, R. A., and G. F. Asselin. Isomerization Means Better
Yields. Chemical Engineering Progress, No. 3, 1965.
pp. 53, 61.
Hydrocarbon Processing, 57 (9): 167-172, Sept. 1978.
Lafferty, W. L., Jr., and R. W. Stokeld. Alkylation and Isomeri-
zation. Origin and Refining of Petroleum, ACS-CIC Joint
Conference, May 25-28, 1979. pp. 130-149.
Lawrence, P. A., and A. A. Rawlings. Advances in Isomerization,
Proceedings of the World Petroleum Congress, 1967.
pp. 4-136.
Nelson, W. L. Petroleum Refinery Engineering. 4th ed. McGraw-
Hill Book, New York, 1969. pp. 750-756.
NPRA Annual Meeting, San Antonio, Texas, Mar. 24, 1975.
Oil and Gas Journal, 56 (13): 73-76, Mar. 31, 1958.
Oil and Gas Journal, 60 (34): 59-61, Oct. 26, 1970.
POLYMERIZATION
Jones. Advances in Catalysis. Vol. 3. Academic Press, Inc.,
New York, 1956. p. 219
Hydrocarbon Processing, 37 (5): 173-176, May 1958.
Hydrocarbon Processing, 47 (9): 163, 169, 170, Sept. 1968.
SULFUR RECOVERY
Chemical Engineering, 71 (15): 128-130, July 20, 1964.
Chemical Engineering Progress, 68 (8): 51-52, Aug. 1972.
Chemical Engineering Progress, 68 (12): 29-34, Dec. 1973.
Hydrocarbon Processing, 51 (3): 105-108, Mar. 1972.
Hydrocarbon Processing, 54 (4): 102-111, Apr. 1975.
Sulfur, No. 101, July/Aug. 1972. p. 26.
Petroleum Refinery Enforcement Manual Bibliography
3/80 5
-------
THEORY OF REACTORS
Carnahan, B., H. A. Luther, and J. 0. Wilkes. Applied Numerical
Methods. John Wiley & Sons, Inc., New York, 1969.
Levenspiel, 0. Chemical Reaction Engineering. John Wiley &
Sons, Inc. New York, 1972.
Nelson, W. L. Petroleum Refinery Engineering. 4th ed. McGraw-
Hill Book Co., New York, 1969. pp. 694-818.
Peterson, E. E. Chemical Reaction Analysis. Prentice-Hall, Inc.,
Englewood Cliffs, New Jersey, 1965.
Smith, J. M. Chemical Engineering Kinetics. McGraw-Hill Book
Co., New York, 1956.
TOWER DESIGN
Nelson, W. L. Petroleum Refinery Engineering. McGraw-Hill Book
Co., New York, 1969. pp. 465-537.
TREATING
Acid Gas Removal
Hydrocarbon Processing, 31 (6): 108-109, June 1952.
Hydrocarbon Processing, 57 (9): 123, Sept. 1978.
Chemical Sweetening
Hydrocarbon Processing, 57 (9): 182, 183, 189-191, 206, 212,
214, Sept. 1978.
Hydrotreating
Celestions. Paper presented at the Ninth Arab Petroleum, Dubai,
Mar. 10-16, 1975.
Coates. Paper presented at the NPRA Meeting, San Antonio, Texas,
Mar. 19-21, 1977.
Craig, Fowler, and Raczyniski. Paper presented at the American
Chemical Society Meeting, Minneapolis, Minnesota, Apr. 14,
1969.
Hydrocarbon Processing, 39 (11): 251-253, Nov. 1960.
Hydrocarbon Processing, 54 (5): 74-81, May 1975.
Petroleum Refinery Enforcement Manual Bibliography
3/80 6
-------
Hydrocarbon Processing, 57 (9): 122, 126-128, 132, 134, 140-148,
150, 151, 154-156, Sept. 1978.
Oil & Gas International, 11 (2): 34-35, Feb. 1971.
Oil and Gas Journal, 70 (24): 94, June 12, 1972.
Oil and Gas Journal, 71 (38): 66-68, Sept. 17, 1973.
Paper F&L No. 72-44. NPRA Fuels and Lubricants Meetings,
New York, Sept. 1972.
Paper No. 51-69. API Division of Refining Meeting, Chicago,
Illinois, May 13, 1969.
Yamamoto. Paper presented at the API Refining Meeting, Chicago,
Illinois, May 12, 1977.
Hydrodesulfurization
Edelman. Paper presented at the Japanese Petroleum Institute,
May 8, 1975.
Hydrocarbon Processing, 34 (6): 118-122, June 1955.
Hydrocarbon Processing, 34 (9): 152-154, Sept. 1955.
Hydrocarbon Processing, 36 (9): 233-235, Sept. 1957.
Hydrocarbon Processing, 45 (5): 149-152, May 1966.
Hydrocarbon Processing, 52 (9): 131, Sept. 1973.
Hydrocarbon Processing, 55 (7): 105-108, July 1976.
Hydrocarbon Processing, 57 (9): 125, 129-133, 135-139, 148, 149,
153, 154, 156, Sept. 1978.
Johnson. Paper presented at the Petroleum Society of CIM Meet-
ing, Edmonton, Canada, May 30-June 3, 1977.
Oil and Gas Journal, 73 (17): 59-63, Apr. 28, 1975.
Petroleum Engineer, 28 (3): C-37 through C-44, Mar. 1956.
Young, and Richards. Paper presented at the NPRA Meeting,
San Francisco, California, Mar. 29, 1977.
Petroleum Refinery Enforcement Manual Bibliography
3/80 7
-------
Visbreaking
Hydrocarbon Processing, 55 (9): 109-112, Sept. 1976.
Hydrocarbon Processing, 57 (9): 101, 102, 106, Sept. 1978.
Petroleum Refinery Enforcement Manual Bibliography
3/80 8
-------
INSTRUCTIONS
1. REPORT NUMBER
Insert the EPA report number as it appears on the cover of the publication.
2. LEAVE BLANK
3. RECIPIENTS ACCESSION NUMBER
Reserved for use by each report recipient.
4. TITLE AND SUBTITLE
Title should indicate clearly and briefly the subject coverage of the report, and be displayed prominently. Set subtitle, if used, in smaller
type or otherwise subordinate it to main title. When a report is prepared in more than one volume, repeat the primary title, add volume
number and include subtitle for the specific title.
5. REPORT DATE
Each report shall carry a date indicating at least month and year. Indicate the basis on which it was selected (e.g., date of issue, date of
approval, date of preparation, etc.}.
6. PERFORMING ORGANIZATION CODE
Leave blank.
7. AUTHOR(S)
Give name(s) in conventional order (John R. Doe, J. Robert Doe, etc.). List author's affiliation if it differs from the performing organi-
zation.
8. PERFORMING ORGANIZATION REPORT NUMBER
Insert if performing organization wishes to assign this number.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Give name, street, city, state, and ZIP code. List no more than two levels of an organizational hirearchy.
10. PROGRAM ELEMENT NUMBER
Use the program element number under which the report was prepared. Subordinate numbers may be included in parentheses.
11. CONTRACT/G R ANT NUMBE R
Insert contract or grant number under which report was prepared.
12. SPONSORING AGENCY NAME AND ADDRESS
Include ZIP code.
13. TYPE OF REPORT AND PERIOD COVERED
Indicate interim final, etc., and if applicable, dates covered.
14. SPONSORING AGENCY CODE
Leave blank.
16. SUPPLEMENTARY NOTES
Enter information not included elsewhere but useful, such as: Prepared in cooperation with, Translation of, Presented at conference of,
To be published in, Supersedes, Supplements, etc.
16. ABSTRACT
Include a brief (200 words or less) factual summary of the most significant information contained in the report. If the report contains a
significant bibliography or literature survey, mention it here.
17. KEY WORDS AND DOCUMENT ANALYSIS
(a) DESCRIPTORS - Select from the Thesaurus of Engineering and Scientific Terms the proper authorized terms that identify the major
concept of the research and are sufficiently specific and precise to be used as index entries for cataloging.
(b) IDENTIFIERS AND OPEN-ENDED TERMS - Use identifiers for project names, code names, equipment designators, etc. Use open-
ended terms written in descriptor form for those subjects for which no descriptor exists.
(c) COSATI FIELD GROUP - Field and group assignments are to be taken from the 1965 COSATI Subject Category List. Since the ma-
jority of documents are multidisciplinary in nature, the Primary Field/Group assignment(s) will be specific discipline, area of human
endeavor, or type of physical object. The application(s) will be cross-referenced with secondary Field/Group assignments that will follow
the primary posting(s).
18. DISTRIBUTION STATEMENT
Denote releasability to the public or limitation for reasons other than security for example "Release Unlimited." Cite any availability to
the public, with address and price.
19. &20. SECURITY CLASSIFICATION
DO NOT submit classified reports to the National Technical Information service.
21. NUMBER OF PAGES
Insert the total number of pages, including this one and unnumbered pages, but exclude distribution list, if any.
22. PRICE
Insert the price set by the National Technical Information Service or the Government Printing Office, if known.
EPA Form 2220-1 (9-73) (Reverse)
------- |