EPA-450/3-82-013a
Sulfur Oxides Emissions from
Fluid Catalytic Cracking
Unit Regenerators -
Background information
for Proposed Standards
Emission Standards and Engineering Division
U.S ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
January 1984
-------
r
This report has been reviewed by the Emission Standards and Engineering Division, Office of Air
Quality Planning and Standards, Office of Air, Noise, and Radiation, Environmental Protection
Agency, and approved for publication. Mention of company or product names does not
constitute endorsement by EPA. Copies are available free of charge to Federal employees,
current contractors and grantees, and non-profit organizations - as supplies permit - from the
Library Services Office, MD-35, Environmental Protection Agency, Research Triangle Park,
NC 27711; or may be obtained, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, VA 22161.
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Draft
Environmental Impact Statement
for Fluid Catalytic Cracking Unit Regenerators
,-- N
./ / / Prepared by:
/./ /---••
„ . b^c-> / L-M^^—^ //V/P
J-ack R. Farmer^- / ~r (Hjate)
'Director, Emission Standards and Engineering Division
1 I ^ ^" • B 4 _ . . . _ **
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina
27711
1. The proposed standards of performance would limit emissions of
sulfur oxides from new, modified, and reconstructed fluid catalytic
cracking unit regenerators. Section 111 of the Clean Air Act
(42 U.S.C. 7411), as amended, directs the Administrator to establish
standards of performance for any category of new stationary
sources of air pollution that "... causes or contributes significantly
to air pollution which may reasonably be anticipated to endanger
public health or welfare." EPA Regions V, VI, and IX are particularly
affected, since most fluid catalytic cracking unit regenerators
are located at petroleum refineries in these regions.
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transportation,
Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; the Council on Environmental Quality; members of the
State and Territorial Air Pollution Program Administrators; the
Association of Local Air Pollution Control Officials; EPA Regional
Administrators; Office and Management and Budget; and other interested
parties.
3. The comment period for review of this document is 75 days.
Mr. Gilbert H. Wood, Standards Development Branch, telephone
(919) 541-5578, may be contacted regarding the date of the comment
period.
4. For additional information contact:
Mr. James F. Durham
Chemicals and Petroleum Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Telephone: (919) 541-5671
5. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
iii
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TABLE OF CONTENTS
Title
Page,
List of Tables xi
List of Figures xvii
Abbreviations xix
Metric Conversion Table xx
1.0 SUMMARY 1-1
1.1 Regulatory Alternatives 1-1
1.2 Environmental Impacts 1-1.
1.2.1 Air Emissions Impact 1-1
1.2.2 Water and Solid Waste Impacts ....... 1-1
1.2.3 Energy Impacts 1-2
1.3 Economic Impact 1-2
2.0 INTRODUCTION 2-1
2.1 Background and Authority for Standards 2-1
2.2 Selection of Categories of Stationary Sources . . 2-4
2.3 Procedure for Development of Standards of
Performance 2-6
2.4 Consideration of Costs 2-8
2.5 Consideration of Environmental Impacts 2-9
2.6 Impact on Existing Sources 2-10
2.7 Revision of Standards of Performance 2-11
3.0 THE CATALYTIC CRACKING UNIT PROCESS AND
POLLUTANT EMISSIONS 3-1
3.1 General 3-1
3.1.1 Introduction 3-1
3.1.2 Domestic Growth Trends in Fluid
Catalytic Cracking. . 3-2
3.2 Fluid Catalytic Cracking Processes and
Emissions 3-4
3.2.1 Fluid Catalytic Cracking Unit Process
Equipment 3-4
3.2.2 Factors Affecting Sulfur Oxides Emissions
from FCC Regenerators ..... 3-10
3.2.3 Emissions from FCC Regenerators . . . . . . 3-15
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TABLE OF CONTENTS (Continued)
Title
Page
3.3 Emissions Under Existing Regulations 3-20
3.4 References 3-25
4.0 EMISSION CONTROL TECHNIQUES 4-1
4.1 Introduction 4-1
4.2 Flue Gas Desulfurization 4-1
4.2.1 Applicability of FGD Systems to FCC
Regenerators 4-2
4.2.2 Sodium-Based FGD Systems 4-7
4.2.3 Calcium-Based FGD Systems 4-14
4.2.4 Double Alkali FGD Systems 4-17
4.2.5 Spray Drying FGD Systems 4-20
4.2.6 Wellman-Lord System 4-25
4.2.7 Citrate-Based FGD Systems 4-28
4.3 Feed Hydrotreating 4-36
4.3.1 Process Description 4-36
4.3.2 Potential for Reducing FCC Regenerator
Sulfur Oxides Emissions ............ 4-38
4.3.3 Additional Benefits Derived from FCC
Feed Hydrotreating 4-39
4.3.4 Development Status . 4-41
4.4 Process Changes . 4-42
4.4.1 Zeolite Catalysts 4-42
4.4.2 Transfer Line (Riser) Cracking 4-43
4.4.3 New Regeneration Techniques 4-43
4.4.4 Other Process Changes 4-44
4.5 Sulfur Oxides Reduction Catalysts 4-44
4.5.1 Process Description 4-45
4.5.2 Development Status . 4-46
4.6 References 4-49
5.0 MODIFICATION AND RECONSTRUCTION 5-1
5.1 General Discussion of Modification and
Reconstruction Provisions 5-1
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TABLE OF CONTENTS (Continued)
Title Page
5,1.1 Modification 5-1
5.1.2 Reconstruction 5-2
5.2 Applicability of Modification Provisions to
FCC Regenerators 5-3
5.2.1 Maintenance, Repair, and Replacement . . . 5-3
5.2.2 Increasing Capacity 5-4
5.2.3 Increase in Hours of Operation 5-5
5.2.4 Change in FCC Feedstock Quality 5-5
5.2.5 Addition, Removal, or Disabling of a
System to Control Air Pollutants 5-6
5.3 Applicability of Reconstruction Provisions
to FCC Regenerators 5-6
5.3.1 Conversion to High Temperature
Regeneration 5-6
5.3.2 Addition or Replacement of Regenerator
Combustion Air Blower, Cyclones,
or other Regenerator Internal
Components 5-7
5.4 References 5-8
6.0 MODEL PLANTS AND REGULATORY ALTERNATIVES 6-1
6.1 Model Plants 6-1
6.2 Regulatory Alternatives ... 6-3
6.2.1 Regulatory Alternative I - The
Baseline Level 6-6
6.2.2 Regulatory Alternative II 6-6
6.2.3 Regulatory Alternative III 6-7
6.2.4 Regulatory Alternative IV 6-7
6.3 References 6-10
7.0 ENVIRONMENTAL IMPACTS 7-1
7.1 Introduction 7-1
7.2 Air Pollution Impacts of Regulatory Alternatives. 7-2
7.2.1 Primary Air Pollution Impacts 7-2
7.2.2 Secondary Air Pollution Impact 7-2
vn
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TABLE OF CONTENTS (Continued)
Title Page
7.2.3 Dispersion Modeling . 7-4
7.2.4 Five-year Impacts of Regulatory
Alternatives . 7-7
7.3 Other Environmental Impacts of the Regulatory
Alternatives 7-10
7.3.1 Water Pollution Impacts of Sodium-based
Scrubbers 7-10
7.3.2 Solid Waste Impacts of Sodium-based
Scrubbers 7-13
7.3.3 Energy Impact of Sodium-based Scrubbers. . 7-13
7.3.4 Other Impacts of Sodium-based Scrubbers. . 7-15
7.4 Environmental Impacts of Other Control
Technologies 7-15
7.4.1 Dual Alkali 7-18
7.4.2 Wellman-Lord 7-20
7.4.3 Citrate 7-21
7.4.4 Spray Drying 7-21
7.4.5 Sulfur Oxides Reduction Catalysts .... 7-21
7.5 Environmental Impact of Delayed Standards .... 7-22
7.6 References 7-23
8.0 COST ANALYSIS 8-1
8.1 Introduction 8-1
8.2 Sodium-Based Flue Gas Desulfurization Costs ... 8-2
8.2.1 Capital and Annual Costs for Sodium-Based
High Energy Venturi Scrubbers 8-2
8.2.2 Capital and Annual Costs for Sodium-based
Jet Ejector Scrubbers 8-14
8.2.3 Water and Solid Waste Cost Impacts .... 8-18
8.2.4 Nationwide Cost Impacts 8-19
8.3 Other Control Technology Costs 8-19
8.3.1 Dual Alkali Flue Gas Desulfurization . . . 8-21
8.3.2 Wellman-Lord 8-24
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TABLE OF CONTENTS (Continued)
Title Page
8.3.3 Citrate FGD System Costs 8-24
8.3.4 Spray Drying 8-28
8.3.5 Sulfur Oxides Reduction Catalysts Costs. . 8-28
8.4 Other Cost Considerations 8-35
8.5 References . . 8-39
9.0 ECONOMIC IMPACT 9-1
9.1 Industry Characterization 9-1
9.1.1 General Profile 9-1
9.1.2 Market Factors 9-12
9.1.3 Financial Profile 9-23
9.2 Economic Analysis 9-26
9.2.1 Introduction and Summary 9-26
9.2.2 Economic Impact Methodology 9-26
9.2.3 Economic Impacts 9-43
9.3 Socioeconomic and Inflationary Impacts 9-48
9.3.1 Executive Order 12291 9-49
9.3.2 Small Business Impacts -
Regulatory Flexibility . . . 9-50
9.4 References 9-51
APPENDIX A - EVOLUTION OF THE PROPOSED STANDARDS A-l
A.I Introduction A-2
A. 2 Chronology . A-2
APPENDIX B - INDEX TO ENVIRONMENTAL CONSIDERATIONS .... B-l
APPENDIX C - EMISSIONS DATA . C-l
C.I Introduction — C-2
C.2 Flue Gas Scrubber Emissions Test Data C-2
C.2.1 Guarantee and Compliance Test Results . . C-3
C.2.2 EPA-Conducted Source Test Results .... C-6
C.3 Sulfur Oxides Reduction Catalyst Test Data . . . C-7
C.3.1 Sulfur Oxides Reduction Catalyst Test
Results C-7
C.4 References C-30
IX
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TABLE OF CONTENTS (Concluded)
Title
APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS
MONITORING .................. D-1
D.I Emission Measurement Methods .......... D-2
D.I.I Emission Testing Program ......... D-2
D.I. 2 Modification to EPA Method 8 ....... D-5
D.I. 3 Development of Modified Method 8 Train . . D-5
D.2 Monitoring Systems and Devices ......... D-10
D.2.1 CEMS Monitor S02 Emissions in vppm
Format .................. D~10
D.2. 2 CEMS to Monitor S02 Emissions in Kilograms
S02 Per Kilogram Coke Burn-Off Format . . D-13
D.3 Performance Test Methods ............ D-14
D.3.1 Stack Emissions .............. °-l4
D.3. 2 Feed Sulfur levels ............ D-15
D.4 References ................... D~18
APPENDIX E - PROJECTED GROWTH IN FCCU CAPACITY ...... E-l
E.I Introduction .................. E~2
E.2 Historical FCC Growth Data ........... E-2
E.3 Five- Year Growth Projection ........... E-4
E.4 References ................... E~10
APPENDIX F - ANALYSIS OF HEAVY OIL CRACKER SO EMISSIONS AND
CONTROL COSTS
F.I Introduction ................... F~l
F.2 HOC Model Plant S0x Emissions .......... F-2
F.3 HOC Model Plant Control Costs .......... F-2
F.4 References .................... F'8
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LIST OF TABLES
Tab1e Page
1-1 Assessment of Environmental and Economic Impacts
for Each Regulatory Alternative Considered . . . . . 1-3
3-1 State Air Regulations for SO Emissions Applicable
to Fluid Catalytic Cracking unit Regenerators .... 3-21
4-1 F6D System Commercial Applications 4-3
4-2 Analysis of Elemental Compositions of Coke
and Coal 4.5
4-3 Comparison of Flue Sas Analyses for FCC Regenerators
and Industrial Coal-Fired Boiler 4_6
4-4 Performance Data for Operating Sodium-Based
FGD Systems on FCC Unit Regenerators 4_13
4-5 Summary of Committed Calcium-Based Systems for
U.S. Industrial Boilers as of March 1978 4-18
4-6 Summary of Operating and Planned Industrial
Boiler Double Alkali Systems 4_2l
4-7 Summary of Some Industrial Boiler Spray Drying
Systems 4_26
4-8 Summary of Operating Wellman-Lord Systems in
the U.S 4-29
4-9 Citrate FGD Process Units , 4.35
4-10 Performance Data for Hydrotreating of FCC
Feedstocks s 4_4Q
4-11 Summary of SO Reduction Catalyst Performance Data. . 4-47
/\
6-1 Model FCC Unit Parameters 6-2
6-2 Summary of Regulatory Alternatives. ......... 6-9
7-1 Annual Sulfur Oxides Emissions and Emission
Reductions for Each Regulatory Alternative ..... 7-3
7-2 Parameters for Model FCC Unit Regenerator
Dispersion Model Analysis 7.5
7-3 Results of Dispersion Modeling for Sulfur Oxides
Emissions from Model FCC Units and PSD Increments . . 7-6
7-4 Projected New FCC Unit Construction Schedule .... 7-8
xi
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LIST OF TABLES (Continued)
Table Pafle
7-5 Projected FCC Unit Modification/Reconstruction
Schedule 7-8
7-6 Annual Impacts of Regulatory Alternatives on Sulfur
Oxides Emissions from New and Modified/Reconstructed
FCC Units 7-9
7-7 Aqueous Discharges from FCC Unit Sodium-based
Scrubber Systems 7-11
**•.
7-8 Annual Operating Electricity Requirements for Sodium-
based Scrubber Systems and FCC Units 7-14
7-9 Annual Operating Energy Requirements for Sodium-based
Scrubber Systems and FCC Units . 7-16
7-10 Nationwide Fifth-Year Operating Energy Requirements
for Sodium-based Scrubbing . . 7-17
7-11 Fifth-Year Nationwide Environmental Impacts by
Control System and Regulatory Alternative ...... 7-19
8-1 Capital Cost for Sodium-Based High Energy Venturi
Scrubbing System and Purge Treatment for Model Units . 8-3
8-2 Assumptions Used to Develop Annual Costs . 8-6
8-3 Bases for Determining Annual Costs 8-7
8-4 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 1 8-8
8-5 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 2 8-9
8-6 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing'for Model Units by Regulatory Alternative -
Case 3 . . 8-10
8-7 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 4 8-11
8-8 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 5 8-12
Xll
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LIST OF TABLES (Continued)
Table
Page
8-9 Annual Cost of Sodium-Based High Energy Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 6 . . . . . . 8-13
8-10 Capital Cost for Sodium-Based Jet Ejector Venturi
Scrubbing System and Purge Treatment for Model Units . 8-15
8-11 Annual Cost of Sodium-Based Jet Ejector Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 7 8-16
8-12 Annual Cost of Sodium-Based Jet Ejector Venturi
Scrubbing for Model Units by Regulatory Alternative -
Case 8 8-17
8-13 Comparison of Fifth-Year Nationwide Scrubber System
Costs 8-20
8-14 Dual Alkali Scrubbing System Costs Based on 1.5
Weight Percent Sulfur Feed and Regulatory
Alternative III 8-22
8-15 Wellman-Lord S0? Recovery System Costs Based on
1.5 Weight Percent Sulfur Feed and Regulatory
Alternative III • • • • 8-25
8-16 Citrate FGD System Costs Based on 1.5 Weight Percent
Sulfur Feed and Regulatory Alternative III 8-29
8-17 Spray Drying Costs Based on 1.5 Weight Percent Sulfur
Feed and Regulatory Alternative III ......... 8-33
8-18 Statutes That May Be Applicable to the Petroleum
Refining Industry .... 8-36
8-19 Electrostatic Precipitator Costs ... 8-37
9-1 Refineries with Fluid Catalytic Cracking
Units 1980 9-2
9-2 Percentage Volume Yields of Refined Petroleum
Products from Crude Oil in the U.S. 1971-1978 9-7
9-3 Production of Petroleum Products at United States
Refineries 1969-1978 . ..... 9-8
xm
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LIST OF TABLES (Continued)
T UT Page
Table —a—
9-4 Refinery Facilities of Major Companies 9-9
9-5 Employment in Petroleum and Natural Gas Extraction
and Petroleum Refining 1969-1978 y-11
9-6 Average Hourly Earnings of Selected Industries .... 9-13
9-7 Estimated 1981 United States Gasoline Pool
Composition
9-8 Demand Projections for Major Petroleum Products . . . 9-15
9-9 Price Elasticities for Major Refinery Products
By Sector 9"i/
9-10 Crude Oil Statistics 9"19
9-11 Domestic Oil Exploration and Discoveries 9-20
9-12 Prices: Gasoline, Distillate Fuel Oil, and
Residual Fuel Oil 9-^
Q-2?
9-13 Price Projections y
9-14 Imports of Refined Petroleum Products 9-24
9-15 Exports of Refined Petroleum Products 9-25
9-16 Profit Margins 9-27
Q ?R
9-17 Return on Investment y~^°
9-18 Petroleum Refining - Income Data 9-29
9-19 Refinery Product Yields 9-32
9-20 Refinery Annual Revenue; Small Refinery; 64 Percent
Capacity Utilization: Before FCC Addition 9-JJ
9-21 Refinery Annual Revenue; Small Refinery; 64 Percent
Capacity Utilization: After FCC Addition 9-34
9-22 Refinery Annual Revenue; Large Refinery; 64 Percent
Capacity Utilization: Before FCC Addition 9-35
9-23 Refinery Annual Revenue; Large Refinery; 64 Percent
Capacity Utilization: After FCC Addition 9-36
xiv
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LIST OF TABLES (Continued)
Table Page
9-24 Example: Cash Flow Analysis; Case 2,
Regulatory Alternative II 9-40
9-25 Percent Price Increases by Regulatory Alternative:
Small Model Unit 9-44
9-26 Percent Price Increases by Regulatory Alternative:
Large Model Unit 9-45
9-27 Internal Rates of Return Refinery Utilization
Rate = 64% 9-47
C-l Summary of Sulfur Dioxide Emissions Test Data for Flue
Gas Scrubbers C-9
C-2 Summary of Sulfur Dioxide Emissions Test Data for
Sulfur Oxides Reduction Catalysts. . C-10
C-3 Flue Sas Scrubber Emissions Test Data
Plant A, Guarantee Test C-13
C-4 Flue Gas Scrubber Emissions Test Data
Plant A, Compliance Test C-14
C-5 Flue Gas Scrubber Emissions Test Data
Plant B, Test 1 C-15
C-6 Flue Gas Scrubber Emissions Test Data
Plant B, Test 2 C-16
C-7 Flue Gas Scrubber Emissions Test Data
Plant B, Test 3 C-17
C-8 Flue Gas Scrubber Emissions Test Data
Plant B, Test 4 C-18
C-9 Flue Gas Scrubber Emissions Test Data
Plant B, Test 5 ........ C-19
C-10 Flue Gas Scrubber Emissions Test Data
Plant C, Unit I C-20
C-ll Flue Gas Scrubber Emissions Test Data
Plant C, Unit II- C-22
xv
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LIST OF TABLES (Concluded)
C-12 Flue Gas Scrubber Emissions Test Data Plant D, Compliance
Test
C-13 Flue Gas Scrubber Emissions Test Data Plant D,
Guarantee Test
C-14 Flue Gas Scrubber Emissions Test Data Plant A,
EPA-Conducted Source Test
C-15 Sulfur Oxides Reduction Catalyst Test Data -
Plant E, Test 1
C-16 Sulfur Oxides Reduction Catalyst Test Data Plant F,
Test 1
• • *
D-l S02 Continuous Monitoring Cost
E-l U.S. FCCU Fresh Feed Capacity 1971-1980 ....
E-2 FCCU Regenerator New Unit Construction 1971-1980
E-3 Projected U.S. FCCU Fresh Feed Capacity
F-l Assumptions Used to Develop HOC Model Plants ....
F-2 HOC Model Plant Sensitivity Analysis, Parameters
Used and Resulting S0x Emissions
F-3 HOC Model Plant Control Costs and Cost Effectiveness
C-24
C-26
C-27
C-28
C-29
D-ll
E-3
E-5
E-8
F-3
F-5
F-6
xvi
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LIST OF FIGURES
Figure
3-1. Statewide Distribution of Refineries with
Fluid Catalytic Cracking Units As of January 1980 . .
Page
3-3
3-2. Basic Flow Diagram of Petroleum Refinery Showing
Location of Catalytic Cracking Unit 3-5
3-3. Schematic of a Fluid Catalytic Cracking Unit .... 3-6
3-4. Relationship Between Feed Sulfur and Coke Sulfur . . 3-11
3-5. Comparison Between Feedstock Sulfur/Coke Sulfur
Correlation and Actual FCC Unit Data 3-17
3-6 Comparison Between Model Plant, Pilot Plant, and
Actual FCC Unit Sulfur Oxides Emissions Data .... 3-18
4-1. Process Layout of the Sodium-Based Venturi
Scrubbing System Applied to FCC Regenerators .... 4-9
4-2. Jet Ejector Venturi Scrubber 4-10
4-3. Process Flow Diagram for a Typical Calcium-Based
Wet Scrubbing System 4-16
4-4. Simplified Flow Diagram for a Sodium/Lime
Double Alkali Process 4-20
4-5. Simplified Flow Diagram for Spray Drying
Process 4-24
4-6. Process Flow Diagram Wellman-Lord Process 4-27
4-7. Flow Diagram for the Bureau of Mines Citrate
Process 4-31
4-8 Flow Diagram for the Flakt-Boliden Citrate Process . 4-32
4-9 General Process Schematic for Fee^d Hydrotreating . . 4-37
6-1. Regulatory Alternatives 6-5
C-l. Results of Flue Gas Scrubber Continuous
Monitoring at Refinery A C-ll
C-2. Results of Flue Gas Scrubber Continuous Monitoring
for Industrial Boiler A C-12
D-l. Manual Sampling Port Adapter D-3
xvn
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LIST OF FIGURES (Concluded)
D-2. Experimental EPA Method 8 Train to Include NH3
Scrubber
D-3 Modified EPA Method 8 with Acidified IPA Impinger.
E-l. Size Distribution of New Units Constructed
Between 1971 and 1980
E-2. Projected U.S. FCC Fresh Feed Capacity
D-7
D-9
E-6
E-7
xvm
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ABBREVIATIONS
BACT
CFR
CRC
ESP
FCC
FGD
HTR
L/G Ratio
Mg
Mm3
NAAQS
sd
cd
HDS
Sm3
Nm3
Best Available Control Technology
Code of Federal Regulations
Coke on Regenerated Catalyst
Electrostatic Precipitator
Fluidized Catalytic Cracking
Flue Gas Desulfurization
High Temperature Regeneration
Liquid to Gas Ratio
Megagram
Million cubic meters
National Ambient Air Quality Standards
Stream day
Calendar day
Hydrodesulfurization
Standard .cubic meters
Normal (standard, dry) cubic meters
xix
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METRIC CONVERSION TABLE
Meter (m)
2
Cubic meter (m )
2
Cubic meter (m )
Kilogram (kg)
Megagram (Mg)
Pascal (Pa)
x 3.28
x 6.29
x 35.31
x 2.20
x 1.10
x 14.5 x 10
-5
Degrees Celsius (C°) C x 1.8 + 32
= feet (ft)
= barrel (oil)(bbl)
= cubic feet (ft3)
= pound (Ib)
= ton
= pounds per square
inch absolute (psia)
= degrees fahrenheit (°F)
Prefix
kilo
Mega
PREFIXES
Symbol
k
M
Multiplication
Factor
103
106
XX
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1.0 SUMMARY
1.1 REGULATORY ALTERNATIVES
Standards of performance for sulfur oxides emissions from new and
modified or reconstructed fluid catalytic cracking (FCC) units in the
petroleum refining industry are being developed under the authority of
Section 111 of the Clean Air Act.
Four regulatory alternatives are considered. Regulatory Alternative I,
the baseline level, represents the level of sulfur oxides emission
control currently achieved by FCC units to meet most State and local
sulfur oxides regulations. Alternative II would limit sulfur oxides
emissions from FCC units to 13.0 kg/1,000 kg coke burn-off. Alternative III
would limit sulfur oxides emissions to 9.8 kg/1,000 kg coke burn-off,
and Alternative IV would limit these emissions to 6.5 kg/1,000 kg coke
burn-off. It is anticipated that either flue gas desul furization or
sulfur oxides reduction catalysts will be used by refiners to meet
these regulatory alternatives.
1.2 ENVIRONMENTAL IMPACTS
1.2.1 Air Emissions Impact
Total sulfur oxides emissions from new, modified, and reconstructed
FCC units in the fifth year under Regulatory Alternative I (baseline)
are 78,800 Mg, compared to 20,100, 15,100, and 10,100 Mg under
Alternatives II, III, and IV, respectively. The average percent
emissions reduction from the baseline level are 74, 81, and 87 percent
for Regulatory Alternatives II, III, and IV, respectively.
1.2.2 Hater and Solid Haste Impacts
The application of sodium-based scrubbers for control of sulfur
oxides results in a wastewater discharge which must be treated and
disposed. Implementation of Regulatory Alternatives II, III, or IV
1-1
-------
would increase wastewater discharges in the fifth year by 2.4 Mm .
The treated wastestrean would contain about 98 Mg/yr of suspended
solids, 12 kg of dissolved solids, and 98 Mg of chemical oxygen demand.
Sodium-based scrubbing for sulfur oxides emissions control does
not result in any incremental changes in the amount (dry weight) of
solid wastes produced over that resulting from the particulate NSPS.
However, the use of dual alkali flue gas desulfurization would produce
a calcium sludge and increase the volume of solid waste to be disposed.
From preliminary information, application of sulfur oxides reduction
catalysts to FCC units will result in negligible water and solid waste
impacts over the baseline level.
1.2.3 Energy Impacts
The overall energy impacts of implementing Regulatory Alternatives II
through IV are negligible. However, the electrical requirements would
substantially increase for modified or reconstructed units with carbon
monoxide combustion furnaces to employ sodium-based scrubbing. Electricity
consumption would rise approximately 20 percent for these units to
operate jet ejector Venturis.
A more detailed analysis of environmental and energy impacts is
presented in Chapter 7. A summary of these impacts for the regulatory
alternatives is shown in Table 1-1.
1.3 ECONOMIC IMPACT
The nationwide capital and annual costs of Regulatory Alternatives II
through IV are developed for new, modified, and reconstructed FCC
units over the 5-year period from 1982 to 1986. These costs are based
on the application of sodium-based flue gas desulfurization. Table 1-1
summarizes the economic impacts of these costs for each of the regulatory
alternatives.
During this 5-year period, the nationwide cumulative capital
costs of Regulatory Alternative II for the industry would be $72.1 million.
The nationwide fifth-year annual cost to the industry under Alternative II
would be $32.1 million. The nationwide 5-year cumulative capital
costs for Regulatory Alternatives III and IV would each be $80.7 million.
Nationwide annual costs of $35.3 million and $36.7 million would be
incurred in the fifth year for Alternatives III and IV, respectively.
The costs to industry of Alternatives II through IV are expected to be
1-2
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significantly lower through application of sulfur oxides reduction
catalysts.
Economic analysis indicates that the impacts of Alternatives II
through IV are small based on the use of flue gas desulfurization.
Expected price increases in refined products to account for the costs
of the regulatory alternatives are less than 0.40 percent for new,
modified, and reconstructed units with flue gas desulfurization.
Expected price increases would be less for sulfur oxides reduction
catalysts. A detailed economic analysis is presented in Chapter 9.
1-4
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2. INTRODUCTION
2.1 BACKGROUND AND AUTHORITY FOR STANDARDS
Before standards of performance are proposed as a Federal regulation,
air pollution control methods available to the affected industry and the
associated costs of installing and maintaining the control equipment are
examined in detail. Various levels of control based on different technolo-
gies and degrees of efficiency are expressed as regulatory alternatives.
Each of these alternatives is studied by EPA as a prospective basis for a
standard. The alternatives are investigated in terms of their impacts on
the economics and well-being of the industry, the impacts on the national
economy, and the impacts on the environment. This document summarizes the
information obtained through these studies so that interested persons will
be able to see the information considered by EPA in the development of the
proposed standard.
Standards of performance for new stationary sources are established
under Section 111 of the Clean Air Act (42 U.S.C. 7411) as amended, herein-
after referred to as the Act. Section 111 directs the Administrator to
establish standards of performance for any category of new stationary
source of air pollution which "... causes, or contributes significantly
to air pollution which may reasonably be anticipated to endanger public
health or welfare."
• The Act requires that standards of performance for stationary sources
reflect,"... the degree of emission reduction achievable which (taking
into consideration the cost of achieving such emission reduction, and any
nonair quality health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated for that category
of sources." The standards apply only to stationary sources, the construc-
tion or modification of which commences after regulations are proposed by
publication in the Federal Register.
2-1
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The 1977 amendments to the Act altered or added numerous provisions
that apply to the process of establishing standards of performance.
1. EPA is required to list the categories of major stationary sources
that have not already been listed and regulated under standards of perform-
ance. Regulations must be promulgated for these new categories on the
following schedule:
a. 25 percent of the listed categories by August 7, 1980.
b. 75 percent of the listed categories by August 7, 1981.
c. 100 percent of the listed categories .by August 7, 1982.
A governor of a State may apply to the Administrator to add a category
not on the list or may apply to the Administrator to have a standard of
performance revised.
2. EPA is required to review the standards of performance every
four years and, if appropriate, revise them.
3. EPA is authorized to promulgate a standard based on design,
equipment, work practice, or operational procedures when a standard based
on emission levels is not feasible.
4. The term "standards of performance" is redefined, and a new term
"technological system of continuous emission reduction" is defined. The
new definitions clarify that the control system must be continuous and may
include a low- or non-polluting process or operation.
5. The time between the proposal and promulgation of a standard under
Section 111 of the Act may be extended to six months.
Standards of performance, by themselves, do not guarantee protection
of health or welfare because they are not designed to achieve any specific
air quality levels. Rather, they are designed to reflect the degree of
emission limitation achievable through application of the best adequately
demonstrated technological system of continuous emission reduction, taking
into consideration the cost of achieving such emission reduction, any
nonair quality health and environmental impacts, and energy requirements.
Congress had several reasons for including these requirements. First,
standards with a degree of uniformity are needed to avoid situations where.
some States may attract industries by relaxing standards relative to other
States. Second, stringent standards enhance the potential for long-term
growth. Third, stringent standards may help achieve long-term cost savings
2-2
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by avoiding the need for more retrofitting when pollution ceilings may
be reduced in the future. Fourth, certain types of standards for coal-
burning sources can adversely affect the coal market by driving up the
price of low-sulfur coal or effectively excluding certain coals from the
reserve base because their untreated pollution potentials are high. Con-
gress does not intend that new source performance standards contribute to
these problems. Fifth, the standard-setting process should create
incentives for improved technology.
Promulgation of standards of performance does not prevent State or
local agencies from adopting more stringent emission limitations for the
same sources. States are free under Section 116 of the Act to establish
even more stringent emission '1imits than those established under Section 111
or those necessary to attain or maintain the National Ambient Air Quality
Standards (NAAQS) under Section 110. Thus, new sources may in some cases
be subject to limitations more stringent than standards of performance
under Section 111, and prospective owners and operators of new sources
should be aware of this possibility in planning for such facilities.
A similar situation may arise when a major emitting facility is to be
constructed in a geographic area that falls under the prevention of signif-
icant deterioration of air quality provisions of Part C of the Act. These
provisions require, among other things, that major emitting facilities to
be constructed in such areas are to be subject to best available control
technology. The term Best Available Control Technology (BACT), as defined
in the Act, means
... an emission limitation based on the maximum degree of
reduction of each pollutant subject to regulation under this Act
emitted from, or which results from, any major emitting facility,
which the permitting authority, on a case-by-case basis, taking
into account energy, environmental, and economic impacts and
other costs, determines is achievable for such facility through
application of production processes and available methods, systems,
and techniques, including fuel cleaning or treatment or innovative
fuel combustion techniques for control of each such pollutant.
In no event shall application of "best available control technol-
ogy" result in emissions of any pollutants which will exceed the
emissions allowed by any applicable standard established pursuant
to Sections 111 or 112 of this Act. (Section 169(3))
2-3
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Although standards of performance are normally structured in terms of
numerical emission limits where feasible, alternative approaches are some-
times necessary. In some cases physical measurement of emissions from a
new source may be impractical or exorbitantly expensive. Section lll(h)
provides that the Administrator may promulgate a design or equipment stand-
ard in those cases where it is not feasible to prescribe or enforce a
standard of performance. For example, emissions of hydrocarbons from
storage vessels for petroleum liquids are greatest during tank filling.
The nature of the emissions, high concentrations for short periods during
filling and low concentrations for longer periods during storage, and the
configuration of storage tanks make direct emission measurement impractical.
Therefore» a more practical approach to standards of performance for storage
vessels has been equipment specification.
In addition, Section lll(j) authorizes the Administrator to grant
waivers of compliance to permit a source to use innovative continuous
emission control technology. In order to grant the waiver, the Administra-
tor must find: (1) a substantial likelihood that the technology will
produce greater emission reductions than the standards require or an equiva-
lent reduction at lower economic energy or environmental cost; (2) the
proposed system has not been adequately demonstrated; (3) the technology
will not cause or contribute to an unreasonable risk to the public health,
welfare, or safety; (4) the governor of the State where the source is
located consents; and (5) the waiver will not prevent the attainment or
maintenance of any ambient standard. A waiver may have conditions attached
to assure the source will not prevent attainment of any NAAQS. Any such
condition will have the force of a performance standard. Finally, waivers
have definite end dates and may be terminated earlier if the conditions are
not met or if the system fails to perform as expected. In such a case, the
source may be given up to three years to meet the standards with a mandatory
progress schedule.
2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES
Section 111 of the Act directs the Adminstrator to list categories
of stationary sources. The Administrator "... shall include a category
of sources in such list if in his judgment it causes, or contributes
2-4
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significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare." Proposal and promulgation of standards
of performance are to follow.
Since passage of the Clean Air Act of 1970, considerable attention
has been given to the development of a system for assigning priorities
to various source categories. The approach specifies areas of interest
by considering the broad strategy of the Agency for implementing the
Clean Air Act. Often, these "areas" are actually pollutants emitted by
stationary sources. Source categories that emit these pollutants are
evaluated and ranked by a process involving such factors as: (1) the
level of emission control (if any) already required by State regulations,
(2) estimated levels of control that might be required from standards of
performance for the source category, (3) projections of growth and
replacement of existing facilities for the source category, and (4) the
estimated incremental amount of air pollution that could be prevented in
a preselected future year by standards of performance for the source
category. Sources for which new source performance standards were
promulgated or under development during 1977, or earlier, were selected
on these criteria.
The Act amendments of August 1977 establish specific criteria to be
used in determining, priorities for all major source categories not yet
listed by EPA. These are: (1) the quantity of air pollutant emissions
that each such category will emit, or will be designed to emit; (2) the
extent to which each such pollutant may reasonably be anticipated to
endanger public health or welfare; and (3) the mobility and competitive
nature of each such category of sources and the consequent need for
nationally applicable new source standards of performance.
The Administrator is to promulgate standards for these categories
according to the schedule referred to earlier.
In some cases it may not be feasible immediately to develop a standard
for a source category with a high priority. This might happen when a
program of research is needed to develop control techniques or because
techniques for sampling and measuring emissions may require refinement. In
the developing of standards, differences in the time required to complete
the necessary investigation for different source categories must also be
considered. For example, substantially -more time may be necessary if
2-5
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numerous pollutants must be investigated from a single source category.
Further, even late in the development process the schedule for completion
of a standard may change. For example, inability to obtain emission data
from well-controlled sources in time to pursue the development process in a
systematic fashion may force a change in scheduling. Nevertheless, priority
ranking is, and will continue to be, used to establish the order in which
projects are initiated and resources assigned.
After the source category has been chosen, the types of facilities
within the source category to which the standard will apply must be deter-
mined. A source category may have several facilities that cause air
pollution, and emissions from some of these facilities may vary from
insignificant to very expensive to control. Economic studies of the source
category and of applicable control technology may show that air pollution
control is better served by applying standards to the mare severe pollution
sources. For this reason, and because there is no adequately demonstrated
system for controlling emissions from certain facilities, standards often
do not apply to all facilities at a source. For the same reasons, the stan-
dards may not apply to all air pollutants emitted. Thus, although a source
category may be selected to be covered by a standard of performance, not
all pollutants or facilities within that source category may be covered
by the standards.
2.3 PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
Standards of performance must (1) realistically reflect best
demonstrated control practice; (2) adequately consider the cost, the nonair
quality health and environmental impacts, and the energy requirements of
such control; (3) be applicable to existing sources that are modified or
reconstructed as well as new installations; and (4) meet these conditions
for all variations of operating conditions being considered anywhere in the
country.
The objective of a program for developing standards is to identify the
best technological system of continuous emission reduction that has been
adequately demonstrated. The standard-setting process involves three
principal phases of activity: (1) information gathering, (2) analysis of
the information, and (3) development of the standard of performance.
2-6
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During the information-gathering phase, industries are queried
through a telephone survey, letters of inquiry, and plant v.isits by EPA
representatives. Information is also gathered from many other sources,
and a literature search is conducted. From the knowledge acquired about
the industry, EPA selects certain plants at which emission tests are con-
ducted to provide reliable data that characterize the pollutant emissions
from well-controlled existing facilities.
In the second phase of a project, the information about the industry
and the pollutants emitted is used in analytical studies. Hypothetical
"model plants" are defined to provide a common basis for analysis. The
model plant definitions, national pollutant emission data, and existing
State regulations governing emissions from the source category are then
used in establishing "regulatory alternatives." These regulatory
alternatives are essentially different levels of emission control.
EPA conducts studies to determine the impact of each regulatory
alternative on the economics of the industry and on the national economy,
on the environment, and on energy consumption. From several possibly
applicable alternatives, EPA selects the single most plausible regulatory
alternative as the basis for a standard of performance for the source
category under study.
In the third phase of a project, the selected regulatory alternative
is translated into a standard of performance, which, in turn, is written in
the form of a Federal regulation. The Federal regulation, when applied to
newly constructed plants, will limit emissions to the levels indicated in
the selected regulatory alternative.
As early as is practical in each standard-setting project, EPA
representatives discuss the possibilities of a standard and the form it
might take with members of the National Air Pollution Control Techniques
Advisory Committee. Industry representatives and other interested parties
also participate in these meetings.
The information acquired in the project is summarized in the Background
Information Document (BID). The BID, the standard, and a preamble explain-
ing the standard are widely circulated to the industry being considered for
control, environmental groups, other government agencies, and offices
within EPA. Through this extensive review process, the points of view of
2-7
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expert reviewers are taken into consideration as changes are made to the
documentation.
A "proposal package" is assembled and sent through the offices of EPA
Assistant Administrators for concurrence before the proposed standard is
officially endorsed by the EPA Administrator. After being approved by the
EPA Administrator, the preamble and the proposed regulation are published
in the Federal Register.
As a part of the Federal Register announcement of the proposed
regulation, the public is invited to participate in the standard-setting
process. EPA invites written comments on the proposal and also holds a
public hearing to discuss the proposed standard with interested parties.
All public comments are summarized and incorporated into a second volume
of the BID. All information reviewed and generated in studies in support
of the standard of performance is available to the public in a "docket" on
file in Washington, D. C.
Comments from the public are evaluated, and the standard of performance
may be altered in response to the comments.
The significant comments and EPA's position on the issues raised are
included in the "preamble" of a "promulgation package," which also contains
the draft of the final regulation. The regulation is then subjected to
another round of review and refinement until it is approved by the EPA
Administrator. After the Administrator signs the regulation, it is published
as a "final rule" in the Federal Register.
2.4 CONSIDERATION OF COSTS
Section 317 of the Act requires an economic impact assessment with
respect to any standard of performance established under Section 111
of the Act. The assessment is required to contain an analysis of:
(1) the costs of compliance with the regulation, including the extent to
which the cost of compliance varies depending on the effective date of
the regulation and the development of less expensive or more efficient
methods of compliance; (2) the potential inflationary or recessionary
effects of the regulation; (3) the effects the regulation might have on
small business with respect to competition; (4) the effects of the regulation
on consumer costs; and (5) the effects of the regulation on energy use.
Section 317 also requires that the economic impact assessment be as
extensive as practicable.
2-8
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The economic impact of a proposed standard upon an industry is usually
addressed both in absolute terms and in terms of the control costs that
would be incurred as a result of compliance with typical, existing State
control regulations. An incremental approach is necessary because both new
and existing plants would be required to comply with State regulations in
the absence of a Federal standard of performance. This approach requires a
detailed analysis of the economic impact from the cost differential that
would exist between a proposed standard of performance and the typical
State standard.
Air pollutant emissions may cause water pollution problems, and captured
potential air pollutants may pose a solid waste disposal problem. The
total environmental impact of an emission source must, therefore, be analyzed
and the costs determined whenever possible.
A thorough,study of the profitability and price-setting mechanisms of
the industry is essential to the analysis so that an accurate estimate of
potential adverse economic impacts can be made for proposed standards. It
is also essential to know the capital requirements for pollution control
systems already placed on plants so that the additional capital requirements
necessitated by these Federal standards can be placed in proper perspective.
Finally, it is necessary to assess the availability of capital to provide
the additional control equipment needed to meet the standards of performance.
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS
Section 102(2)(C) of the National Environmental Policy Act (NEPA) of
1969 requires Federal agencies to prepare detailed environmental impact
statements on proposals for legislation and other major Federal actions
significantly affecting the quality of the human environment. The objective
of NEPA is to build into the decisionmaking process of Federal agencies a
careful consideration of all environmental aspects of proposed actions.
In a number of legal challenges to standards of performance for
various industries, the United States Court of Appeals for the District
of Columbia Circuit has held that environmental impact statements need
not be prepared by the Agency for proposed actions under Section 111 of
the Clean Air Act. Essentially, the Court of Appeals has determined that
the best system of emission reduction requires the Administrator to take
2-9
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into account counter-productive environmental effects of a proposed
standard, as well as economic costs to the industry. On this basis,
therefore, the Court established a narrow exemption from NEPA for EPA
determination under Section 111.
In addition to these judicial determinations, the Energy Supply and
Environmental Coordination Act (ESECA) of 1974 (PL-93-319) specifically
exempted proposed actions under the Clean Air Act from NEPA requirements.
According to Section 7(c)(l), "No action taken under the Clean Air Act
shall be deemed a major Federal action significantly affecting the quality
of the human environment within the meaning of the National Environmental
Policy Act of 1969." (15 U.S.C. 793(c)(l))
Nevertheless, the Agency has concluded that the preparation of
environmental impact statements could have beneficial effects on certain
regulatory actions. Consequently, although not legally required to do so
by Section 102(2)(C) of NEPA, EPA has adopted a policy requiring that
environmental impact statements be prepared for various regulatory actions,
including standards of performance developed under Section 111 of the Act.
This voluntary preparation of environmental impact statements^ however,
in no way legally subjects the Agency to NEPA requiranents.
To implement this policy, a separate section in this document is
devoted solely to an analysis of the potential environmental impacts associ-
ated with the proposed standards. Both adverse and beneficial impacts in
such areas as air and water pollution, increased solid waste disposal, and
increased energy consumption are discussed.
2.6 IMPACT ON EXISTING SOURCES
Section 111 of the Act defines a new source as "..; any stationary
source, the construction or modification of which is commenced ..." after
the proposed standards are published. An existing source is redefined as a
new source if "modified" or "reconstructed" as defined in amendments to the
general provisions of Subpart A of 40 CFR Part 60, which were promulgated
in the Federal Register on December 16, 1975 (40 FR 58416).
Promulgation of a standard of performance requires States to establish
standards of performance for existing sources in the same industry under
Section lll(d) of the Act if the standard for new sources limits emissions
of a designated pollutant (i.e., a pollutant for which air quality criteria
2-10
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have not been issued under Section' 108 or which has not been listed as a
hazardous pollutant under Section 112). If a State does not act, EPA must
establish such standards. General provisions outlining procedures for
control of existing sources under Section lll(d) were promulgated on
November 17, 1975, as Subpart B of 40 CFR Part 60 (40 FR 53340).
2.7 REVISION OF STANDARDS OF PERFORMANCE
Congress was aware that the level of air pollution control achievable
by any industry may improve with technological advances. Accordingly,
Section 111 of the Act provides that the Administrator "... shall, at
least every 4 years, review and, if appropriate, revise ..." the standards.
Revisions are made to assure that the standards continue to reflect the
best systems that become available in the future. Such revisions will not
be retroactive, but will apply to stationary sources constructed or modified
after the proposal of the revised standards.
2-11
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3.0 THE CATALYTIC CRACKING UNIT PROCESS
AND POLLUTANT EMISSIONS
3.1 GENERAL
3.1.1 Introduction
Catalytic cracking is a petroleum refinery process in which
hydrocarbon molecules in the presence of a catalyst are fractured or
broken into smaller molecules. The catalyst allows the selective
fracturing of heavy distillates (high molecular weight hydrocarbons)
to light products (low molecular weight hydrocarbons). At many petroleum
refineries, catalytic cracking is used to convert gas oils or residual
feedstocks into gasoline and middle distillate blending stocks.
Catalytic cracking is also used to produce light olefins (e.g., propylenes
and butylenes) for gasoline alkylation and petrochemical production,
and to produce cycle oils for use as blending components in heating
oils and fuel oils.
Originally, hydrocarbon cracking was accomplished by a thermal
process. However, this process did not produce sufficient quantities
or qualities of desired products from the heavy feeds. The development
of catalytic cracking allowed greater yields of gasoline blending
stocks and other light products to be obtained while reducing the
yield of heavy residuals or fuel oils. As a result of the improved
yield and quality of products associated with the catalytic cracking
process, catalytic cracking has almost completely replaced thermal
cracking.
Fluidized catalytic cracking (FCC) involves the mixing of the
feedstock with a stream of fine, suspended, catalyst particles (termed
a "fluidized bed"). Upon completion of the cracking reactions, the
cracked hydrocarbon vapors are separated from the catalyst. The
cracked hydrocarbon vapors pass to a fractionating column where the
3-1
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vapors are distilled into the desired products. The spent catalyst,
deactivated during the cracking process, is transferred to a regenerator.
There, a carbon residue called coke, which deposits on the catalyst
particles during the cracking reaction, is burned off. The reactivated
catalyst is then recycled back to the catalytic cracking process.
Sulfur oxides emissions result during catalyst regeneration from
oxidation of sulfur compounds bound in the coke.
Two other types of catalytic cracking are also employed by the
petroleum refining industry to produce gasoline blending stocks and
other products. These are referred to as Thermofor catalytic cracking
and Houdriflow catalytic cracking. In contrast to fluidized catalytic
cracking, these processes use moving catalyst beds. As of January
1980 the Houdriflow process was used by 2 refineries and the Thermofor
process was used by 15 refineries. Since these processes are being
gradually phased out of usage, the remainder of this document will
deal only with fluid catalytic cracking.
3.1.2 Domestic Growth Trends in Fluid Catalytic Cracking
As of January 1980, FCC units were in operation at 126 petroleum
refineries located in the United States (see Figure 3-1). The FCC
units have a combined throughput capacity of about 0.8 x 10 cubic
meters of fresh feed per stream-day (0.8 Mm /sd). Although individual
FCC unit throughput capacities range from 380 to 21,460 m /sd, over
60 percent of the total FCC unit throughput capacity is attributable
to units larger than 7,100 m3/sd. The FCC units located in California,
Louisiana, and Texas account for about 54 percent of the total throughput
capacity.1"10 A state-by-state listing of refineries operating FCC
units is presented in Section 9.1.
Nationwide FCC processing capacity has increased from 0.6 Mm /sd
in 1971 to 0.8 Mm3/sd in 1980 in response to increasing gasoline
demand.1"10'11 Although total gasoline demand is expected to decline
over the next 10 years,11 total processing capacity growth is expected
to continue because the FCC unit has the flexibility to process resi-
dual feeds, high sulfur gas oils, and synthetic (coal-derived) feeds.
Also, the FCC unit is an important contributor to the high octane
12 13 14
unleaded gasoline pool and distillate product inventory. ' '
3-2
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Annual throughput capacity growth similar to that experienced
between 1971 and 1980 is expected to yield a total FCC processing
capacity of 0.93 Mm3/sd in 1987. This growth will come from both new
unit construction and additions to existing capacity. A more detailed
discussion of industry growth is presented in Appendix E.
3.2 FLUID CATALYTIC CRACKING PROCESSES AND EMISSIONS
Up to 50 percent of the total crude oil input to a refinery may
be ultimately processed in the FCC unit. Figure 3-2 shows a gener-
alized flow diagram illustrating the relationship between the FCC unit
and other processes at a petroleum refinery. FCC feedstocks are
derived from the distillation of crude oil and from other refinery
process units. Heavy gas oil from the atmospheric and vacuum dis-
tillation units are typically charged to the FCC unit. Other sources
of gas oil are thermal cracking, lube oil extraction and dewaxing,
coking, and deasphalting processes. Residual feedstocks, such as
vacuum and atmospheric distillation tower bottoms, are becoming a more
important FCC unit feedstock source. The FCC unit feedstocks are
usually blended with recycle oil, a stream of partially cracked hydro-
carbons from the FCC fractionator, before being charged to the FCC.
3.2.1 Fluid Catalytic Cracking Unit Process Equipment
An FCC unit consists of three basic sections: reactor, regenerator,
and fractionator. Figure 3-3 presents a diagram of a generalized FCC
unit. Variations in the design of FCC units exist throughout the
petroleum refining industry, but basic product yields and operating
characteristics are similar.
3.2.1.1 Reactor. Cracking reactions and catalyst/product separation
take place in the reactor section of the FCC unit. The reactor section
in a modern FCC unit usually consists of a riser reactor and a separator
vessel which contains a catalyst disengager and a steam stripper.
Preheated feedstocks are blended with recycle oil from the fractionator
and injected into a fluidized stream of regenerated catalyst near the
bottom of the riser reactor. The catalyst temperature ranges from
approximately 590 to 680°C, and the catalyst to feedstock mass ratio
ranges from 4 to 10. The cracking reactions begin as the hot,
regenerated catalyst contacts and vaporizes the feed. As the vaporized
3-4
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•r~ fO
Q S-
CJ
o o
O i—
•r- tQ
in ^->
CO «
CO O
CM
I
oo
3
CD
•r—
U_
3-5
-------
to
O
id
en
co
3-6
-------
hydrocarbons and catalyst particles flow upward through the riser
reactor to the separator vessel, the hydrocarbons are cracked into
lighter product molecules. The cracking reaction is endothermic, so
the reacting mixture cools as it rises to the separator vessel.
During the cracking process in the riser, the catalyst rapidly loses ;
its activity. This occurs as high molecular weight aromatic and
sulfur compounds, originally present in the feed, are preferentially
20
adsorbed on catalyst surfaces where they react to form coke. Deacti-
vation of the catalytic cracking catalyst also occurs through the
absorption of nitrogen and metal compounds.
The separator vessel is designed to separate or disengage the
catalyst particles from the cracked hydrocarbon vapors rapidly to
21 22
minimize secondary reactions. ' Multiple-stage cyclones installed
inside the separator vessel remove most of the catalyst fines from the
cracked hydrocarbon vapors (products). The products and the remaining
entrained catalyst fines exit overhead to the fractionator. The
coke-laden catalyst particles fall through a steam stripper in the
separator vessel where additional entrained light hydrocarbons are
displaced from the void spaces around the catalyst particle using
15 23
steam as the displacing agent. * Both steam and hydrocarbons are
then routed overhead with the products to the fractionator. Stripped
catalyst is transferred to the regenerator to renew catalyst cracking
24 25
activity and to generate heat for the cracking reaction. '
3.2.1.2 Regenerator. Coke, which deposits on the catalyst, blocks
active cracking sites on the catalyst surface. Consequently, coke
deposition reduces catalyst cracking activity. To renew catalyst
activity, coke deposits are burned off the catalyst in the regenerator.
The combustion products (flue gases) are primarily carbon monoxide
(CO), carbon dioxide (C09), and water vapor. Sulfur oxides (SO ) and
C- A
nitrogen oxides (NO ) are also formed due to oxidation of sulfur and
A, ' •-••'.
nitrogen compounds bound in the coke.
Upon entering the regenerator, the spent catalyst particles from
the reactor are suspended in a fluidized bed that is maintained at
elevated temperatures. An air compressor (blower) injects a regulated
amount of air into the regenerator vessel to fluidize the catalyst
3-7
-------
particles and to sustain combustion of the coke. Combustion gases
resulting from catalyst regeneration pass through multiple-stage
cyclones before leaving the regenerator. These cyclones, located
within the regenerator, recover catalyst particles which become
entrained in the regenerator flue gas during regeneration. These
cyclones are generally considered process equipment.
The flue gases are vented from the multiple-stage cyclones and
the regenerator through a pressure control valve. Normally, the flue
gases are passed through air pollution control, heat recovery, and in
some cases, power recovery equipment before discharge to the atmosphere.
To comply with Federal, State, or local air pollution regulations,
many existing FCC unit regenerators are equipped with electrostatic
precipitators (ESP) for final removal of catalyst fines from the flue
gases. A carbon monoxide combustion furnace or boiler is often used
to control carbon monoxide emissions and to recover waste heat. In
some installations, FCC regenerator flue gases pass through turbines
to recover some energy from the flue gas. The recovered energy may be
used to generate electricity. New FCC unit regenerators are required
to meet new source performance standards (NSPS) for particulates
(1.0 kg/1,000 kg coke burn-off) and carbon monoxide (500 vppm). These
standards were promulgated March 8, 1974 (40 CFR 60.102, 40 CFR 60.103).
Catalyst coke is oxidized in conventional regeneration using an
amount of combustion air that is insufficient for complete combustion
to occur. This results in coke on regenerated catalyst (CRC) levels
ranging from 0.1 to 0.6 weight percent15'25 and in the generation of
large quantities of carbon monoxide. Carbon monoxide flue gas concen-
trations from these units can be about 10 volume percent, representing
p£ O"7
a carbon dioxide/carbon monoxide ratio of about 1.0. ' These large
quantities of carbon monoxide are generated in the lower portion of
the regenerator fluidized bed (dense bed) and pass through the upper
portion of the fluidized bed (dilute-phase) and internal cyclones.
The flue gases are then vented to pollution control equipment and to
the atmosphere. Temperatures in the regenerator are about 590°C to
680°C. If excess oxygen is available within the regenerator, the
carbon monoxide undergoes exothermic combustion in the dilute phase or
internal cyclones, causing large temperature excursions and possible
3-8
-------
damage to the catalyst, cyclones, and auxiliary equipment. Carbon
monoxide combustion furnaces are often used with conventional regenerators
to combust carbon monoxide in a controlled manner outside the regenerator
vessel.
The latest regeneration techniques can reduce CRC to about
0.02 percent and flue gas CO content to about 0.05 percent (500 vppm).
The two methods used to achieve this improvement include high tempera-
ture regeneration (HTR) and catalytically promoted carbon monoxide
combustion. In HTR, combustion takes place within the regenerator,.
dense bed. As the name implies, the regenerator dense bed and dilute
phase temperatures are higher than in conventional regenerators. The
energy released in the combustion of CO to CO^ causes this temperature
increase. The dense bed temperature is near 700°C, and the dilute
phase temperature is 730°C to 745"C, although both can be as high as
1 ^ ?7
760°C during HTR operation. ' The advantages of this technique are
more complete catalyst regeneration, lower catalyst inventory, better
heat recovery within the regenerator and low carbon monoxide emissions.
In catalytically promoted carbon monoxide combustion, catalysts promote
and confine the combustion of carbon monoxide to the regenerator dense
bed. This results in efficient heat transfer and minimizes high
temperature excursions and subsequent equipment damage due to dilute
28
phase afterburning. It also permits existing units with metallurgical
constraints to achieve high regeneration efficiencies through partial
carbon monoxide combustion. The regenerator dense bed temperature is
at least 670°C to 700°C, and the dilute phase temperature is 680°C to
720°C.
28
*
Promoters also yield low CRC ratios and give benefits
30
similar to those derived from HTR.
The activity of all catalysts, especially zeolite catalysts, is
25
affected by the CRC. Since large residual coke deposits inhibit
catalyst activity, the low CRC obtained with HTR or carbon monoxide
promoters results in improved product yields, reduced coke formation,
and improved unit profitability. ' Since complete carbon monoxide
combustion occurs within the regenerator and the NSPS for carbon
monoxide emissions can be met through the use of HTR or carbon monoxide
combustion promoters, carbon monoxide combustion furnaces are
required.
3-9
-------
3.2.1.3 Fractionator. Product vapors, steam, and some catalyst
fines passing through the separator vessel cyclones are vented from
the FCC unit to the fractionator. Within the fractionator, the vapors
are separated into gases, catalytic gasoline, and light and heavy
cycle oils. These products are sent to various areas within the
refinery for further processing. Most of the entrained catalyst fines
entering the fractionator settle to the bottom of the fractionator as
a sludge. The catalyst sludge in some refineries is removed and mixed
with the liquid recycle for reinjection into the riser reactor.
Fresh catalyst is added periodically to the FCC unit to make up for
catalyst losses to the atmosphere and products.
3.2.2 Factors Affecting Sulfur Oxides Emissions from FCC Regenerators
The coke which deposits on the FCC catalyst during normal operations
primarily contains carbon, hydrogen, nitrogen, and sulfur. Sulfur
oxides emissions result when the sulfur that is contained in the coke
is oxidized in the regenerator during coke burn-off. Thus, the operating
parameters which directly or indirectly affect the sulfur content of
the coke and the amount of coke burned off in a given period of time
ultimately affect sulfur oxides emissions. The quantity of sulfur
oxides emissions from the FCC unit regenerator can vary considerably
with feedstock quality, regeneration mode, catalyst type, and operating
conditions.
3.2.2.1 Feedstock Quality. The sulfur content of the FCC feed
is the most important factor affecting sulfur oxides emissions from
the FCC unit regenerator. The amount of sulfur in an FCC feed directly
influences coke sulfur and thus, regenerator sulfur oxides emissions.
A high sulfur feed may thus be generally expected to yield higher
sulfur oxides emissions than a low sulfur feed since more sulfur will
be found in the coke.
The amount of sulfur in a feedstock which ends up as coke sulfur
depends on the source of the feedstock. The correlation presented in
Figure 3-4 is derived from pilot plant data and shows a relationship
between feed sulfur and coke sulfur content for feedstocks from various
crude oils. At equivalent levels of feed sulfur, different feeds can
yield different levels of coke sulfur, and thus different sulfur
3-10
-------
*
3
O
2.0 3.0
Feed Sulfur, wt. %
Figure 3-4. Relationship Between Feed
Sulfur and Coke Sulfur33
3-11
-------
33
oxides emissions.32 As shown in Figure 3-4, at 1.0 percent feed
sulfur, California gas oil produces a coke containing approximately
0.55 weight percent sulfur; West Texas gas oils produce approximately
1.5 weight percent coke sulfur; and feeds derived from Kuwait stocks
produce 2.2 weight percent coke sulfur. Regenerator flue gas concen-
trations of sulfur oxides may vary from about 400 ppm by dry volume^
(vppm) to more than 1,700 vppm for units processing these gas oils.'
This variation in levels of coke sulfur is related to the coke
forming tendency of the FCC feed and to the molecular form in which
the sulfur is bound in the hydrocarbon molecules. Certain sulfur-bearing
hydrocarbon molecules, called thiophenes, preferentially form coke on
the FCC catalyst during the cracking reactions. Other sulfur-bearing
molecules tend to crack into hydrogen sulfide and other light hydrocarbons,
The hydrogen sulfide is vented with the products to the fractionator,
leaving less- sulfur to form on the catalyst. Thus, the relative
quantity and molecular structure of the sulfur-bearing hydrocarbon
determines the amount of sulfur in coke.
FCC feedstock sulfur content is approximately equal to the sulfur
content of the crude oil from which the gas oil is derived. A range
of expected sulfur contents for FCC feeds may be derived by identifying
the crude slates from which the feeds originate. Given the unstable
nature of world crude oil supplies, it is difficult to identify possible
future refinery crude slates. An analysis of historical trends and
general crude sulfur content is required to bracket the potential
range of FCC feed sulfur characteristics.
' In 1978, "sweet" crude oil (sulfur content less than 0.5 weight
percent) processing accounted for over 53 percent of the total crude
processing volume.35 The typical sulfur content of crude oil from
mid-continental United States oil fields, such as those in Oklahoma
and Louisiana, is about 0.3 weight percent.35 Other oil fields which
also yield crude oil with this or lower average sulfur contents include
those in Africa, Western Europe, and the Far East (Indonesia). It
is expected that this heavy reliance on sweet stocks will continue,
but decrease slightly from 54 to 49 percent through 1982.
Refiners select and use crude stocks based on overall economics
and supply considerations. The demand for lower quality crude stocks
3-12
-------
(high sulfur content, low gravity) is expected to increase as supplies
of low sulfur crude oil become more expensive and less available. As
a result, the type of crude oil processed by U.S. refineries is expected
to change. It is estimated that the average sulfur content of the
total crude processed in the U.S. will rise to 1.28 weight percent in
1985 and 1.3 weight percent in 1990. In 1976, the average crude oil
•?Q
sulfur content was 0.8 weight percent. Some refiners expect their
future FCC feeds to have a sulfur content near or above 2.0 weight
34 40 41 42
percent. ><™»'ti»'t<- This -js especially true if the highest sulfur
feedstocks from the Middle East (4.6 weight percent) and Mexico (5 weight
percent) are utilized.
Residue and reduced crude processing are also expected to become
important as refiners try to maximize useful liquid yields from each
unit volume of crude oil. Several companies have developed an FCC-type
unit, known as a heavy oil cracker (HOC), which can handle these
residual feeds. ' Asphalt residual treating (ART), a recently
developed FCC-like process, improves the quality of residual and heavy
crude feedstocks by removing carbon residue and other impurities.
The sulfur content of most of these residual feeds may exceed 2.0 weight
percent.
FCC feed sulfur contents may thus range from less than 0.3 weight
percent to a value between 2.5 weight percent and 5.0 weight percent.
Regenerator flue gas sulfur oxides concentrations may range from less
•33
than 200 vppm to over 2,500 vppm for these feeds.
Contaminant metals are also present in all FCC unit feedstocks to
some degree. Concentrations are dependent on the crude oil source,
boiling fraction, and the degree of pretreating. The metals deposit
on the catalyst and tend to nonselectively catalyze undesirable reactions.
These reactions result in a decrease in catalyst activity and an
increase in gas and coke yields, thus greater sulfur oxide emissions.
3.2.2.2 Regeneration Mode. Regeneration mode refers to the
regeneration techniques commonly used by refiners. As described in
Section 3.2.1.2, refiners employ conventional regeneration, high
temperature regeneration, and catalytically promoted carbon monoxide
combustion regeneration to renew catalyst cracking activity. Each
regeneration technique affects how completely coke is burned off the
catalyst particles.
3-13
45
-------
The efficiency of coke burn-off directly affects coke yields,
conversion, gasoline yields, circulation rates, feed preheat require-
ments, and sulfur oxides emissions. Regeneration efficiency is measured
by determining the weight percent carbon remaining on the regenerated
catalyst, CRC. CRC affects sulfur oxides emissions through its associa-
tion with coke production. Efficiently regenerated catalysts, and
catalysts with low CRC complete feed cracking reactions with less
catalyst coke production than catalysts with high CRC. This is because
'coke on regenerated catalysts promotes undesirable coke forming
reactions during cracking.30 Reducing CRC thus reduces coke production
and sulfur oxides emissions.
For a given FCC feed and feed rate, sulfur oxides emissions from
FCC regenerators using high temperature or carbon monoxide-promoted
regeneration may thus be less than the sulfur oxides emissions from
conventional regenerators.
3.2.2.3 Operating Conditions. Fluid catalytic cracking units
have the flexibility to produce a wide variety of products from a wide
variety of feedstocks. Yields of certain products may be optimized by
adjusting the operating conditions within the reactor and regenerator
sections. Unit operations depend upon market demands, emission
limitations, and processing capabilities elsewhere in the refinery.
In optimizing FCC operations for different product requirements,
the amount of coke produced for each unit volume of feed (coke yield)
and the rate at which coke is produced (coke make rate) may vary. For
example, coke yield (as weight percent of the feed) generally increases
as the light product yield from a given FCC feedstock is maximized.
Similarly, coke make rate may be increased by increasing unit through-
put at constant coke yield. Both of these operational changes increase
emissions of sulfur oxides from an FCC unit regenerator.
Refiners sometimes recycle a portion of heavy cycle oils to
increase yields of other products. Maximum distillate production is
obtained, for example, when refiners recycle heavy cycle oil. Conversely,
maximum gasoline yield is obtained when distillate products are recycled.
Due to higher conversion of the feedstock to products, recycling may
result in increased coke production and therefore, increased sulfur
-------
46
oxides emissions. With current zeolite catalyst technology, distillate
23
recycle is rarely used.
3.2.3 Emissions from FCC Regenerators
Pollutant emission rates can be estimated for FCC regenerators by
47
using emission factors described in AP-42. These emission factors
generally represent average emission levels and thus do not reflect
the complete range of emissions from individual FCC units. The range
of FCC pollutant emission rates may be determined by considering the
typical ranges in feed sulfur, coke yield, and FCC capacity, and by
evaluating the stoichiometric relationships involved in regenerating
FCC catalyst.
Catalyst regeneration is similar to solid fuel combustion in a
boiler. This is discussed in more detail in Chapter 4. Flue gas
compositions and flow rates may be calculated by .determining the coke
composition and formation rate and by calculating the amount of air
required to oxidize the coke. Coke formation rates vary depending on
the FCC and how it is operated. Coke yield, expressed as a weight
percentage of the feed, varies between 4 weight percent and 6.5 weight
48
percent for many FCC feeds. The feed density is assumed to be
900 kg/m3.
Coke is composed of carbon, hydrogen, sulfur, and small amounts
of nitrogen and metals. Coke may typically contain from 4 to 12 percent
15 23 25
hydrogen. ' ' The sulfur content of the coke may range from less
than 0.1 to 5 weight percent or more, depending on the type of feed
processed. Assuming that the nitrogen and metals content of coke is
negligible, carbon would represent the balance of coke composition.
Certain regenerator combustion air inlet and flue gas compositions
must also be assumed when calculating emissions. Inlet air to the
regenerator may contain from 76.0 to 78.8 volume percent nitrogen,
20 volume percent oxygen, and from 1.2 to 4.0 volume percent water.
15
The water vapor content is typical for a Gulf Coast location.
Emission calculations are discussed below.
The air flow rates are determined by calculating the amount of
air required to burn the coke that is formed on the catalyst. The
coke burn-off rate assumed for this calculation i.s 5 weight percent of
the fresh feed rate. Coke sulfur content is specified by using the
3-15
-------
correlation between feed sulfur and coke sulfur presented in Figure 3-5.
This correlation is derived from pilot plant data such as presented
in Figure 3-4. Data points showing the relationship between feed
sulfur and coke sulfur for pilot and commercial FCC unit operations
have been plotted onto Figure 3-5 to show that this correlation is
representative of feed sulfur-coke sulfur relationships for many
common FCC feedstocks.
Coke hydrogen content is assumed to be 4 weight percent and
carbon is assumed to represent the balance. Regenerator combustion
air is assumed to contain 78.8 volume percent nitrogen, 20 volume percent
oxygen, and 1.2 volume percent water. Flue gas compositions of carbon
monoxide and oxygen are assumed to be 0.05 and 2.0 volume percent,
respectively.
From these assumptions, air flow rates entering and exiting the
FCC regenerator are determined stoichiometrically. The results of
this emissions analysis are plotted in Figure 3-6. A separate analysis
of emissions from HOC's and other FCCU-like processes, calculated as
described above, is presented in Appendix F. Data points showing the
relationship between feed sulfur and sulfur oxides emissions for pilot
and commercial FCC unit operations have been plotted onto Figure 3-6
to show that the calculated model plant emissions are representative
of actual FCC unit operations.
A sensitivity analysis was performed to determine the effect of
different input values on calculated FCC sulfur oxides emissions.
Results of this analysis show that calculated FCC emissions are relatively
insensitive to all input values except coke sulfur content when sulfur
oxides emissions are reported in a concentration or mass per unit of
coke burn-off format. Model plants are discussed in Section 6.0.
3.2.3.1 Sulfur Oxides. If the above conditions are applied to
FCC units which range in throughput capacity from 800 m /sd to 21,500 m3/sd
and on feed sulfur contents which range from 0.1 weight percent to
3.5 weight percent, a wide range of FCC sulfur oxides emissions is
identified. Flue gas concentrations may range from less than 200 vppm
to approximately 3,000 vppm. Sulfur oxides mass emission rates may
range from approximately 7.5 kg/hr to 4,700 kg/hr.
3-16
-------
T3
C
as
C
o
t-
LU
u
cc
.« X
*- a
Ul
O
u
GC
u_
_i
CO
•s §
01
111
<=.
o
I ' ' ' ' 7
®
rB
'aJ
S-
o
OO
d)
O
OO CO
o
o
-o
O)
O)
u_
fO
a
•t->
•r—
£
4-> O
E O
re! U.
Q! r—
(O
-!-> 3
O 4J
a;
cu
a>
CO
c
o
CO
a.
o
CJ
(±N30a3d 1H3I3AA) 3XOO JO 1N31NOO
LO
I
CO
OJ
3
CD
3-17
-------
100
50
oc
oo
ui
*
8
sT
(39
CO
HI
CO
10
5.0
0-5
0.1
0.1
3,000
1,000
500
100
50
CO
O
i
UJ
10
0.3 0.5 1.0 1.5
FEED SULFUR (vit.%)
3.5
Figure 3-6. Comparison between Model Plant, Pilot Plant, and Actual
FCC Unit Sulfur Oxides Emissions Data.
3-18
-------
A portion of sulfur oxides is present as SCL, as a result of the
. 49 '
reaction:
Few data exist which adequately specify the concentrations of S03 in
the regenerator flue gas. Estimates have ranged from 0.1 to 60 volume
percent of the total sulfur oxides. Typical SO- levels may be less
25 49
than 10 volume percent. ' Recent articles suggest that at high
flue gas excess oxygen contents, SO- emissions may be as significant
en J
as S02. In view of the limited information available on S03 emis-
sions from FCC regenerators, the calculated sulfur oxides emissions
from the FCC regenerators are reported as SO,, emissions.
3.2.3.2 Particulate Matter Emissions. Particulate matter in the
flue gas essentially consists of catalyst fines and some of the impurities
contained in the charging stock. The emission factor for uncontrolled
3
particulate emissions spans a range from 0.27 to 0.98 kg/m fresh feed
(6 kg/1,000 kg of coke burn-off to 22 kg/1,000 kg coke burn-off). 7
Particulate emissions from new sources must meet the NSPS level of
1 kg/1,000 kg of coke burn-off.
s
3.2.3.3 Carbon Monoxide Emissions. Carbon monoxide results from
the incomplete combustion of catalyst coke. New sources are required
to control carbon monoxide flue gas concentrations to less than 500 vppm.
This is accomplished through the use of special regeneration techniques
or through the combustion of the carbon monoxide in a waste heat
incinerator. New units are assumed to use modern regeneration tech-
niques described in Section 3.2.1.2 to control carbon monoxide emissions
to 500 vppm.
3.2.3.4 Nitrogen Oxides Emissions. Nitrogen oxides are formed
in the FCC regenerator by two mechanisms. In the first, nitrogen in
the combustion air combines with oxygen in a temperature-dependent
reaction to form various nitrogen oxides. In the second mechanism,
nitrogen present in the coke combines with oxygen to form nitrogen
oxides. Thermal nitrogen oxides formation is thought to be low at
typical regenerator temperatures (675-735°C). Therefore, the majority
of nitrogen oxides is assumed to result from nitrogen present in the
15 25
coke. The major nitrogen oxide specie is nitric oxide. ' Nitrogen
oxides emissions from conventional regeneration are approximately
3-19
-------
20 vppm. Nitrogen oxides emissions are generally less than 200 vppm
from high temperature regenerators and are, on average, 550 vppm for
conventional regeneration FCC units which utilize promoter catalysts.
Use of sulfur oxides reduction catalysts may increase nitrogen oxides
emissions beyond these levels.51 Effective technologies for the
control of nitrogen oxides emissions have not yet been proven commercially.
There are no applicable Federal regulations for controlling
nitrogen oxides emissions from FCC units.
3.2.3.5 Volatile Organic Compounds (VOC) Emissions. Emissions
of VOC are dependent on the type of regeneration. The VOC emissions
from conventional regeneration are less than 500 vppm before the
carbon monoxide boiler. After the carbon monoxide boiler, the VOC
concentration is less than 10 vppm. The VOC emissions from HTR are
less than 10 vppm.52 There are no applicable.Federal regulations
governing VOC emissions from FCC units.
3.2.3.6 Other Pollutants. Other pollutants from FCC units
include cyanides as HCN and ammonia as NHg. The concentrations of
both these pollutants is about 10 ppm for high temperature regenerators
or after carbon monoxide combustion furnaces used on conventional
52
regenerators.
3.3 EMISSIONS UNDER EXISTING REGULATIONS
Nationwide emissions of sulfur oxides from existing FCC units are
a function of nationwide FCC processing capacity, State sulfur oxides
emission regulations, existing FCC sulfur oxides emission control
systems, and feedstock quality.
Emissions may be estimated by assuming that the FCC unit is
emitting sulfur oxides at a level equal to the State emission limits.
This is a simple calculation requiring knowledge of the emission
limits and unit operating capacities when the sulfur oxides mass
limitation is expressed on a throughput basis.
The formats of State regulations applicable to sulfur oxides
emissions from the FCC unit, however, are inconsistent and vary from
concentration limits (e.g., 2,000 vppm) to mass limitations. In some
States, the entire refinery falls under a "bubble," and an emission
limit is set for the whole refinery rather than specifically for the
FCC regenerator. Table 3-1 summarizes State and local regulations for
3-20
-------
Table 3-1. STATE AIR REGULATIONS FOR SOX EMISSIONS APPLICABLE TO
FLUID CATALYTIC CRACKING UNIT REGENERATORS
EPA
Region State
II New Jersey
New York
III Delaware
Pennsylvania
Virginia
IV Kentucky
Mississippi
V Illinois
Indiana
•
Indianapolis
Michigan
Wayne County
SOX Emission
Regulation
Existing Sources New Sources
2,000 vppm
NAAQS3
NAAQS
500 vppm
2,000 vppm
2,000 vppm
2,000 vppm
2,000 vppm
181-681 kg/hr
28.2 !
-------
Table 3-1. STATE AIR REGULATIONS FOR S0x EMISSIONS APPLICABLE TO
FLUID CATALYTIC CRACKING UNIT REGENERATORS (Continued)
EPA
Region
State
SO Emission Regulation
A
Existing Sources New Sources
Comments
Minnesota
Ohio
Wisconsin
NAAQS
0.62-3.0 kg/
1000 kg feed
NAAQS
NAAQS
Source
Specific
NAAQS
Source specific regu-
lation (includes SIP
regulation)
VI Arkansas NAAQS NAAQS
Louisiana 2,000 vppm 2,000 vppm
New Mexico 4,545 kg/day
10 kg/100
kg SO
released
2 kg/100
kg SOX
released
VI Oklahoma NAAQS NAAQS
Texas NAAQS
total SO emissions
from refinery
refineries releasing
4,545 kg and
27,272 kg/day
of sulfur in process;
90 percent control
refineries releasing
27,272 kg/day of sulfur
in process; 98 percent
control
individual county
regulations
VII Kansas
Missouri
NAAQS
NAAQS
BACT3
NAAQS
NAAQS
NSPS
source specific
if ambient standard i
exceeded, facilities
s
with 454.5 kg SQx/hr
will be required to
reduce emissions
BACT - Best available control technology.
3-22
-------
Table 3-1. STATE AIR REGULATIONS FOR SOX EMISSIONS APPLICABLE TO
FLUID CATALYTIC CRACKING UNIT REGENERATORS (Concluded)
EPA
Region State
Nebraska
VIII Colorado
Montana
Utah
Wyomi ng
IX California
SCAQMD3
BAAQMDb
Hawai i
X Washington
sox Emission Regulation
Existing Sources New Sources
SO emissions
cannot exceed
1971 emissions
2.0 kg/m3
processed
Ambi ent
Ambient
Ambient
Ambient
2,000 vppm
1,000 vppm
Ambient
1,000 vppm
NSPS
0.86 kg/m3
processed
Ambi ent ,
NSPS
NSPS
NSPS
Ambient
0.82 kg/m3
feed
0.38 kg/m3
feed
BACT
Ambient
1,000 vppm,
NSPS
Comments
also AP-42 emission
estimates
total SOg emissions
from refinery
source specific regu-
lation being developed
for plants in non-
attainment areas
applicable
7/1/81 ,
applicable
7/1/85
South Coast Air Quality Management District.
5Bay Area Air Quality Management District.
3-23
-------
47
FCC regenerators. For many of these regulatory formats, calculation
of nationwide emissions requires knowledge of the FCC regenerator
exhaust gas flow rates. This flow rate may change on a weekly basis
and is affected by the feedstock quality, catalyst type, and other
process variables. This makes calculation of nationwide emissions
difficult. In addition, Lowest Achievable Emissions Rate (LAER)
provisions may apply to some of the affected FCC regenerators. LAER
limits FCC regenerator emissions to 300 vppm. It is unclear which, if
any, of the affected FCC regenerators would be subject to these
19
requirements.
Nationwide emissions of sulfur oxides from FCC regenerators can
be approximated by using the EPA emission factors published in AP-42.
The AP-42 emission factors for FCC unit regenerators are averaged
values obtained from emission tests of typical FCC unit operations.
These tests represent the level of sulfur oxides emission control
currently achieved by FCC units to meet most State and local sulfur
oxides regulations. The emission factor for sulfur oxides emissions
from FCC regenerators is 1.413 kg/m3 of fresh feed.47 For a total
nationwide FCC fresh feed capacity of 800,000 m3/sd,53 the nationwide
January 1980 baseline emission of sulfur oxides from FCC units is
413,000 Mg/year. The feed sulfur/sulfur oxides relationship illustrated
in Figure 3-6 is used to estimate sulfur oxides emissions from the
model plants discussed in Section 6.0.
3-24
-------
3.4 REFERENCES
1. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
78(12):136-157. March 24, 1980. Docket Reference Number I-I-I-71.*
2. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
69_( 12) :98-121. March 22, 1971. Docket Reference Number II-1-5.*
3. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
70(13):138-156. March 27, 1972. Docket Reference Number II-I-6.*
4. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
2I(14):102-121. April 2, 1973. Docket Reference Number II-I-10.*
5. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
_72(13):85-103. April 1, 1974. Docket Reference Number II-I-13.*
6. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
73(14):100-118. April 7, 1975. Docket Reference Number II-I-16.*
7. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
74(13):130-153. March 29, 1976. Docket Reference Number II-I-23.*
8. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
75(13):99-123. March 28, 1977. Docket Reference Number II-I-29.*
9. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
26(12):114-140. March 20, 1978. Docket Reference Number II-1-37.*
10. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
27(13):129-153. March 26, 1979. Docket Reference Number II-1-57.*
11. Petroleum Use Study Forecasts Sharp Decline in Demand Growth.
Hydrocarbon Processing. 59_(6):13. June 1980. Docket Reference
Number II-I-76.*
12. Murphy, J.R., and M. Soudek. Modern FCC Units Incorporate Many
Design Advances. Oil and Gas Journal. 75_(2):76. January 17,
1977. Docket Reference Number II-I-28.*
13. Gallagher, J.P., W.H. Humes, and J.O. Siessman. Cat Cracking To
Upgrade Synthetic Crudes. Chemical Engineering Progress. 75(6):56.
June 1979. Docket Reference Number II-1-59.*
14. Hoffman, H.L. Components for Unleaded Gasoline. Hydrocarbon
Processing. _59_(2):59. February 1980. Docket Reference Number
II-I-69.*
15. Letter and Attachments from Flynn, J.P., Exxon Company U.S.A., to
Farmer, J.R., U.S. Environmental Protection Agency. May 8, 1981.
Comments on BID, Volume I, Chapters 3-6. Docket Reference Number
II-D-50.*
3-25
-------
16. Screening Study to Determine Need for SO and Hydrocarbon-NSPS
for FCC Regenerators. U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-450/3-77-046.
August 1976. p. 19. Docket Reference Number II-A-2.*
17. Complete Combustion of Carbon Monoxide in Cracking Process.
Chemical Engineering. November 24, 1975. p. 47. Docket Reference
Number II-I-21.*
18. Supplement No. 8 for Compilation of Air Pollutant Emission Factors,
Third Edition. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. AP-42. May 1978. p. 9.1-2.
Docket Reference Number II-I-41.*
19. Guidelines for Lowest Achievable Emission Rates from 18 Major
Stationary Sources of Particulate, Nitrogen Oxides, Sulfur Dioxide,
or Volatile Organic Compounds. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. Publication No. EPA-450/
3-79-024. April 1979. p. 3.4-2. Docket Reference Number II-A-7.*
20. Blazek, J.L., R.E. Ritter, D.N, Wallace. Hydrotreating FCC Feed
Could Be Profitable. Oil and Gas Journal. 72_(42):IQ4. October 14,
1974. Docket Reference Number II-I-14.*
21. Ford, W.D., G.J. D'Souza, and J.R. Murphy. FCC Advances Merged
in New Design. Oil and Gas Journal. 76_(2l):66. May 22, 1978.
Docket Reference Number II-I-43.*
22. Fluid Catalytic Cracking With Molecular Sieve Catalysts. Petro/
Chem Engineer. May 1969. p. 15. Docket Reference Number II-I-2.*
23. Letter and Attachments from Murphy, J.R., The M.W. Kellogg Company,
to Farmer, J.R., U.S. Environmental Protection Agency. May 7,
1981* Comments on BID, Volume I, Chapters 3-6. Docket Reference
Number II-D-49.*
24. Reference 22. p. 13. Docket Reference Number II-I-2.*
25. Letter and Attachments from Grossberg, A.I.., Chevron Research
Company, to Farmer, J.R., U.S. Environmental Protection Agency.
May 4, 1981. Comments on BID, Volume I, Chapters 3-6. Docket
Reference Number II-D-47.*
26. Shields, R.J., R.J. Fahrig, and C.J. Horecky. FCC Regeneration
Technique Improved. The Oil and Gas Journal. 70(22):45. May
29, 1972. Docket Reference Number II-I-7.*
27. Upson, L.L. Catalytically Promoted Combustion Improves FCC
Operations. National Petroleum Refiners Association Paper AM-79-39.
(Presented at the 1979 NPRA Annual Meeting.) March 25-27, 1979.
p. 2. Docket Reference Number II-I-55.*
3-26
-------
28. Chester, A.W. and F.D. Hartzell. Partial and Complete Carbon
Monoxide Combustion FCC Regeneration with Promoted Cracking
Catalyst Systems. National Petroleum Refiners Association Paper
AM-79-36. (Presented at the 1979 NPRA Annual Meeting.) March
25-27, 1979. pp. 2, 13. Docket Reference Number 11-1-56.*
29. Magee, J.S., R.E. Ritteri and L. Rheaume. A Look at FCC Catalyst
Advances. Hydrocarbon Processing. J5£(9):127-128. September
1979. Docket Reference Number 11-1-64.*
30. Reference 29, p. 128. Docket Reference Number II-I-r64.*
31. Reference 16, p. 21. Docket Reference Number II-A-2.*
32. Sulfur Dioxide/Sulfate Control Study — Main Text. South Coast
Air Quality Management District. May 1978. p. 6.18. Docket
Reference Number 11-1-40.*
33. Ruling, 6.P., J.D. McKinney, and T.C. Readel. Feed Sulfur
Distribution in FCC Product. Oil and Gas Journal. 73(21):74-75.
May 19, 1975. Docket Reference Number II-I-17.*
34. Manda, M.L., Pacific Environmental Services, Inc. Trip Report:
Conoco, Incorporated, Ponca City, Oklahoma. August 14, 1980.
Docket Reference Number II-B-12.*
35. Aalund, L.R. Sour Crude Technology Set for 80's. Oil and Gas
Journal. _78_(12):79. March 24, 1980. Docket Reference Number
II-I-73.*
36. Reference 16, p. 70. Docket Reference Number II-A-2.*
37. Cuddington, K.S. High Sulfur Content Associated with Largest
Petroleum Reserves. Oil and Gas Journal. 28(12):96. March 24,
1980. Docket Reference Number II-1-72.*
38. A Heavy, Sour Taste for Crude-Oil Refiners. Chemical Engineering.
JJ7(10):96. May 19, 1980. Docket Reference Number II-I-74.*
39. U.S. Refiners Facing Major Problems. Oil and Gas Journal.
79_(14):52. April 6, 1981. Docket Reference Number II-I-89.*
40. Letter and Attachments from Albaugh, D., Marathon Oil Company, to
Goodwin, D.R., U.S. Environmental Protection Agency. March 20,
1981. Response to Section 114 information request. Docket
Reference Number II-D-41.*
41. Letter and Attachments from Prichard, J.J., Ashland Petroleum
Company, to Goodwin, D.R., U.S. Environmental Protection Agency.
May 27, 1981. Response to Section 114 information request.
Docket Reference Number II-D-53.*
3-27
-------
42. Letter and Attachments from Larson, W.E., Chevron U.S.A., Incorporated,
to Goodwin, D.R., U.S. Environmental Protection Agency. March 24,
1981. Response to Section 114 information request. Docket
Reference Number II-D-42.*
43. Hemler, C.L., C.W. Strother, B.E. McKay, and G.D. Myers. Catalytic
Conversion of Residual Stocks. National Petroleum Refiners
Association. Paper AM-79-37. (Presented at the 1979 NPRA Annual
Meeting.) March 23-27, 1979. Docket Reference Number II-I-52.*
44. Murphy, J.R. The Refinery of the Future. Pullman Kellogg,
Houston, Texas. (Presented at the Second European Petroleum and
Gas Conference. Amsterdam.) May 20-22, 1980. pp. 2-3. Docket
Reference Number II-I-75.*
45. Reference 12, p. 72. Docket Reference Number II-I-28.*
46. Murcia, A.A., M. Soudek, G.P. Quinn, and G.J. D'Souza. Add
Flexibility to FCCs. Hydrocarbon Processing. j>8:134. September
1979. Docket Reference Number II-I-63.*
47. Reference 18. p. 9.1-6. Docket Reference Number 11-1-41.*
48. Murcia, A.A., M. Soudek, G.P. Quinn, and G.J. D'Souza. FCCU
Design Criteria for Processing Flexibility. National Petroleum
Refiners Association. Paper AM-79-38. (Presented at the 1979
NPRA Annual Meeting.) March 25-27, 1979. p. 22. Docket Reference
Number II-I-53.*
49. Reference 16., p. 27. Docket Reference Number IT-K-2.*
50. McArthur, D.P., H.D. Simpson, and K. Baron. Catalytic Control of
FCC SO Emission Looking Good. Oil and Gas Journal. 79(8):57.
February 23, 1981. Docket Reference Number II-I-87.*
51. Memorandum from Bernstein, G., Pacific Environmental Services,
Inc., to Docket Number A-79-09. May 21, 1982. Results of analysis
of NOV emissions study. Docket Reference Number II-B-21.*
A
52. Reference 16, pp. 32-34. Docket Reference Number II-A-2.*
53. U.S. Department of Transportation. Energy Information Administration.
Petroleum Refineries in the United States and U.S. Territories.
January 1, 1980. Docket Reference Number II-I-67.*
54. Memorandum from Bernstein, G., Pacific Environmental Services,
Inc., to Docket Number A-79-09. April 28, 1982. Results of
Sensitivity Analysis of Input Selection on Model Plant SO Emissions.
Docket Reference No. II-B-26.*
55. Memorandum from Bernstein, G., Pacific Environmental Services, Inc.,
to Docket Number A-79-09. September 20, 1982. Similarity in Control
Costs between Heavy Oil Crackers and Asphalt Residual Treating Process.
Docket Reference No. II-B-29.*
3-28
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*References can be located In Docket Number A-79-09 at the U.S.
Environmental Protection Agency's Central Docket Section, West
Tower Lobby, Gallery 1, Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
3-29
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4.0 EMISSION CONTROL TECHNIQUES
4.1 INTRODUCTION '
There are four basic techniques applicable to controlling sulfur
oxides emissions from fluidized catalytic cracking (FCC) unit regenerators:
(1) Flue gas desulfurization
(2) Feed hydrotreating
(3) FCC unit process changes
(4) Sulfur reduction catalysts
Flue gas desulfurization processes remove sulfur oxides from the
flue gases vented from the FCC unit regenerator. The sulfur oxides
are converted to a liquid waste, solid waste, or salable product.
Sulfur oxides emissions from the regenerator can be controlled indirectly
by using hydrotreating to reduce the sulfur content of the FCC unit
feedstock. FCC unit process changes can reduce the amount of coke
deposited on the catalyst and, subsequently, reduce the amount of
sulfur oxides vented from the regenerator. An emerging technique for
controlling regenerator sulfur oxides emissions involves the use of
special FCC unit sulfur oxides reduction catalysts. Each of the
techniques is discussed in the following sections.
4.2 FLUE GAS DESULFURIZATION
Flue gas desulfurization (FGD) involves the removal of sulfur
oxides from a waste gas stream. Two broad categories are used to
classify FGD processes: (1) disposable FGD systems (often referred to
as "throwaway" systems) and (2) regenerable FGD systems. Disposable
FGD systems use processes where all waste streams are discarded.
Regenerable FGD systems use processes where the waste stream is treated
for regeneration of the sorbent and often the recovery of salable
sulfur compounds such as elemental sulfur and sulfuric acid.
4-1
-------
Over 100 different FGD processes have been proposed. However,
many of these processes have not been developed beyond the laboratory
or pilot plant phase. Currently* there are six FGD systems that are
in commercial use in the United States. The six systems and their
applications are summarized in Table 4-1.
Six FGD systems have been selected as candidates for application
to FCC unit regenerators. The FGD systems selected are:
• Sodium-based FGD systems
• Calcium-based FGD systems
• Double alkali FGD systems
• Wellman-Lord FGD systems
• Citrate FGD systems
• Spray drying FGD systems
Sodium-based FGD systems are currently being used to control
sulfur oxides emissions from FCC unit regenerators. A citrate scrubber
is currently under construction for FCC unit regenerator application.
The calcium-based, double alkali, and spray drying FGD systems are
currently operating or being installed at industrial and utility
boiler locations in the United States. Flow rates and characteristics
for flue gases from FCC unit regenerators are similar to flue gases
from industrial and utility boilers. Similarities between boilers
and FCC unit regenerators are discussed in Section 4.2.1. Other FGD
systems not discussed here, such as magnesium oxide, have only been
installed at a limited number of industrial/utility boilers.
4.2.1 Applicability of FGD Systems to FCC Regenerators
Sodium-based scrubbing systems have been effectively applied to
seven FCC regenerators at five refineries to control both particulate
and sulfur oxides emissions. These seven FCC regenerators with
sodium-based scrubbers represent 11 percent of nationwide FCC processing
capacity. The performance characteristics of sodium-based scrubbers
are discussed in Section 4.2.2. Citrate scrubbers have been demonstrated
in utility boiler applications. A citrate scrubber is currently under
construction for an FCC unit regenerator application. Performance
characteristics for this scrubber system are discussed in Section 4.2.7.
Application of the calcium-based, double alkali, Wellman-Lord, and
spray drying FGD systems presently used on utility and industrial
4-2
-------
TABLE 4-1. FGD SYSTEM COMMERCIAL APPLICATIONS
FGD
Process
Number of Operational FGD Systems
FCC Unit Industrial3 Utility3
Regenerators Boilers Boilers
Sodium
based
Calcium
based
Double
al kal i
Spray drying
Magnesium
oxide
Well man-Lord
Citrate
7 119 3
2 28
21 -
4b 10b
1
3C 4C
le la'd
Reference 3.
This represents the number of contracts signed for spray drying
systems as of February 1981. See Reference 2.
Reference 4.
As of November 1979, 1 industrial boiler application was planned.
eUnder construction.
4-3
-------
boilers may depend on similarities between FCC regenerator and boiler
flue gases. FCC regenerator flue gas compositions are dictated by the
catalyst coke composition. Boiler flue gas compositions depend on the
properties of the boiler fuel.
The coke formed on the FCC catalyst is a carbonaceous material
similar to the coal used in solid fuel-fired industrial boilers.
Approximate elemental analyses of catalyst coke and bituminous coal
are shown in Table 4-2. The catalyst coke is burned off the catalyst
during regeneration by adding air to the regenerator. The regeneration
process is thus similar to the combustion processes which take place
in boilers. Given the similarities between catalyst coke and other
solid fuels, the combustion process which takes place in the FCC
regenerator may be expected to yield flue gases which are similar to
those derived from coal-fired boilers.
A comparison between FCC regenerator flue gases and industrial
boiler flue gases is presented in Table 4-3.10 FCC regenerator flue
gas compositions were determined from a survey of State emission test
data, stoichiometric relationships, and from AP-42 emission factors.
Boiler flue gas parameters are calculated values for a field erected
watertube boiler which burns high sulfur Eastern United States coal.
As suggested by the information presented, the ranges in concentration
of most FCC regenerator flue gas constituents overlap the boiler flue
gas concentrations. FGD systems installed on FCC regenerators will
thus experience similar inlet concentrations as boiler FGD systems.
The primary difference between FCC regenerator flue gases and
boiler flue gases is the particulate emissions. Boiler particulate
emissions are primarily fly ash, while catalyst fines comprise the
majority of regenerator particulate emissions. Both fly ash and
catalyst fines are erosive and may cause abnormal wear in an improperly
designed or operated FGD system.11'
Hydrocarbon emissions from FCC regenerators may be higher than
those from boilers, especially if they are uncontrolled (see Table 4-3),
The effects of hydrocarbon concentration on scrubber operation are not
4-4
-------
Table 4-2. ANALYSIS OF ELEMENTAL COMPOSITIONS OF
COKE AND COAL
Composition (wt. %)
Selected U.S.
El ement
Carbon
Hydrogen
Su.1 fu r
Nitrogen
Other:
Moisture
Volatile Matter
Ash
Catalyst Coal
Coke5'6'7 Free,
84.5 - 96.0 74.0
4.0 - 12.0 4.8
0.0- 4.5 0.3
0.0 - 1.0 0.9
NAa l.O
NA 17.7
NA 3.3
s, Ash
Dry Basis8
- 90.4
- 5.7
- 4.0
- 1.7
- 31.0
- 49.3
- 11.7
Not available.
4-5
-------
Table 4-3. COMPARISON OF FLUE GAS ANALYSES FOR
FCC REGENERATORS AND INDUSTRIAL COAL-FIRED BOILER3
Unit Capacity
Flue Gas Flow Rate
(Nm3/min)
Flue Gas Temperature (°C)
Flue Gas Composition
N2 vol. %n
02 vol. %n
C02 vol . %n
CO vol. %n
Particulates (g/m )°
SOY (vpprn)0
0
NOY (vppm)
3 o
Hydrocarbons (g/m )
Moisture vol . %
FCC Regenerator
800-21,500 m3/sdc
280-8, 500d
230-420e>f
81-84g;h
0.1-8.01'9
9-16J''f
0-6.9f>1
0.4-1.5k
120-1, 600e>1
64-250k
1.0k
10_23m,f
Industrial
Coal -Fired
Boilerb
52 MW
2,700
210
81.0
4.2
14.6
0
9.6
2,800
410
0
7.5
Uncontrolled emissions.
Estimated for high sulfur Eastern U.S. coal (3.54 wt. % S) assuming 120
percent theoretical air for the boiler. See Reference 10.
Reference 14.
Reference 15.
Reference 16.
Reference 17.
Reference 18.
h
Reference 19.
Reference 20.
JReference 21.
Calculated from AP-42 emission factor for 9500 m3/min air flow and
21,500 m3/sd. See Reference 9.
Reference 22.
'"Reference 23.
nDry basis.
°Wet basis.
4-6
-------
known; presently operating FCC regenerator FGD systems may remove some
13
hydrocarbons from the flue gas stream.
Other differences in flue gas compositions are minor and are not
expected to invalidate the applicability of FGD systems to FCC regenerators.
There are two specific areas of concern in applying FGD systems
to FCC regenerator flue gas. FCC units are very durable and can often
operate continuously from 2 to 4 years. Therefore, any FGD system for
an FCC unit application should have a similar on-line reliability.
Also, because of potentially significant S03 emissions, the selection
of a regenerable system may be limited to ones that can tolerate
sulfates.
The scrubbing systems identified here for application to FCC
units have had varying degrees of on-line reliability to date. To
ensure acceptable FGD reliability for FCC regenerator applications
certain precautions should be exercised. Plugging of the capture
system can be minimized through the use of venturi collectors (not
tray towers or packed towers) and a continuous wash of the mist eliminator.
Spare capture modules should also be used so maintenance can be performed
on-line. Other portions of the FGD systems that have potential maintenance
problems routinely have redundant equipment. Sodium-based FGD systems in
use on FCC units have very high reliability due to the use of redundant
equipment. Some of these scrubbers have run for over 38 months without
a shutdown.
4.2.2 Sodium-Based FGD Systems'
4.2.2.1 Process Description. Sodium-based FGD processes are
capable of achieving high sulfur oxides removal efficiencies over a
wide range of inlet sulfur oxides concentrations. However, these
processes consume a premium chemical and produce an aqueous waste for
disposal which contains sodium sulfite and sulfate salts. Sodium-based
FGD systems currently use an aqueous solution of sodium hydroxide
(NaOH), sodium bicarbonate (NaHCO,), or sodium carbonate (NA2C03) to
absorb sulfur oxides from the flue gases. Sodium alkali sorbents are
highly reactive relative to calcium-based sorbents. Also, the reactant
liquid is a clear solution rather than a slurry because of the high
24
4-7
-------
solubility of sodium salts.
which take place are:
2NaOH + SCL *
The sulfur oxides absorption reactions
2NaHC0
Simultaneously some sodium sulfite reacts with the oxygen in the flue
gases to produce sodium sulfate:
The resulting product is primarily a sodium sulfite, bisulfite, and
sulfate solution which is removed from the process for disposal.
4.2.2.2 System Design. A generalized flow diagram for the
sodium-based FGD system as applied to the FCC unit regenerator is
presented in Figure 4-1. This system may be described in terms of
three basic processes:
(1) Reagent preparation
(2) Particulate removal and sulfur oxides absorption
(3) Waste preparation and disposal
The reagents used in FCC applications of sodium-based FGD systems
are either sodium hydroxide (MaOH) or sodium carbonate (Na2C03).
Sodium systems currently in use on utility and industrial boilers
employ sodium hydroxide, sodium carbonate, or sodium bicarbonate
(NaHCO.,) as the sorbent. Storage silos are required for solid or
O
liquid reagents; mixing tanks are required for solid reagents.
For FCC-applied sodium-based scrubbing systems, particulate
removal and sulfur oxides absorption occur in a venturi scrubber. Two
scrubber designs, the jet ejector and high energy venturi scrubber,
are in use on FCC units. Selection of venturi type depends upon the
1 ^ ?fi
pressure of the flue gas exiting the regenerator. '
The jet ejector venturi scrubber, shown in Figure 4-2, consists
of a spray nozzle and venturi throat. The scrubbing liquor, sprayed
27
into the venturi through the nozzle at 513 to 925 kPa, induces a
draft, drawing regenerator flue gas into the scrubber. Thus, the
jet-ejector venturi operates with negligible pressure drop. This type
4-8
-------
(optional)
Stacjkv—T
Gas Distribution
Nozzle
Blower
Air
Reheater
Fuel Gas
Make-up water
Venturi
Scrubber
\\
CKE
pH Monitor
Flue
~Gas
Slurry^
Clarifier
Water
Effluent Discharge
Sulfite
Oxidation
Reactor
Air Compressor
Figure 4-1. Process Layout of the Sodium-Based
Venturi Scrubbing System Aoplied to
FCC Regenerators"
4-9
-------
SCRUBBING
LIQUID
SPRAY NOZZLE
VENTURI
DIRTY GAS
TO LIQUID
SEPARATOR DRUM
Figure 4-2. Jet Ejector Venturi Scrubber
4-10
-------
of venturi has been applied to existing FCC units with carbon monoxide
boilers which cannot be backpressured to use a high energy venturi
scrubber. The high energy venturi scrubber, a wet-wall venturi, has
been applied to two new FCC units with high temperature regeneration
and an overall flue gas pressure drop of about 10.3 kPa. Typical
liquid-to-gas (L/6) ratios for the jet ejector scrubber are 6.7 to
3 3
13.4 m of scrubbing liquor per 1,000 m of flue gas. Typical L/G
3 3
ratios for the high energy venturi scrubber are 0.7 to 4.0 m /I,000 m
12
of flue gas.
Sulfur oxides removal occurs by reaction between the sodium-based
scrubbing liquor and the sulfur oxides in the gas stream. Particulate
removal occurs by inertia! impaction of the scrubbing liquor with the
entrained particulates. These solid-liquid and gas-liquid mass transfer
interactions occur within the venturi scrubber. Contactors other than
Venturis are used in industrial and utility boiler applications. In
these applications, the contactors operate at low pressure drops and
are designed only for sulfur oxides control. A separate control
device is usually required to control particulate emissions.
Gases from the venturi pass into a separator vessel. Here the
flue gases are separated from entrained scrubbing liquor. The flue
gases are directed to a stack, reheated if necessary, to maintain
plume buoyancy, and vented to the atmosphere. The scrubbing liquor
collected in the separator vessel is recirculated back to the venturi
scrubber with a small purge stream sent to the wastewater treatment
system.
Changes in flue gas flow rates are compensated for in the scrubber
by altering the scrubbing liquor flow rate to maintain a constant L/G
ratio. In the jet ejector venturi scrubber, the scrubbing liquor
pressure at the spray nozzle affects the flue gas flow rate and the
; 28
scrubbing liquor flow rate.
As flue gas sulfur oxides react with the reagent in the scrubbing
liquor, the pH of the liquor falls, reducing the sulfur oxides removal
efficiency of the scrubbing system. To maintain scrubber efficiency
and liquor pH between 6 and 7 as well as to minimize corrosion and
7 29
erosion, ' sodium carbonate, hydroxide, or bicarbonate is added to
the scrubbing liquor.
4-11
-------
30
A portion of the recirculating liquor is continuously removed
from the scrubber system. This stream, consisting of collected
particulate and spent scrubbing liquor (mostly sodium salts), is
directed to oxidation and clarification tanks or ponds to reduce
chemical oxygen demand and remove suspended particulates. The treated
stream is then disposed to surface water, evaporative ponds, or injected
into deep wells. Solid wastes are most commonly disposed in a landfill.'
4.2.2.3 Development Status. Sodium scrubbing systems are commercially
available technologies. These systems have been applied to seven FCC
unit regenerators at five petroleum refineries, and to 80 percent of
the commercial industrial boilers with FGD equipment in the U.S.
Table 4-4 summarizes the location and performance of sodium-based FGD
systems presently applied to FCC regenerators.
4.2.2.4 System Performance. A scrubber vendor claims that up to
95 percent reduction in sulfur oxides has been achieved by sodium-based
13
scrubbers in actual FCC unit emission tests. From available FCC unit
performance test data summarized in Table 4-4 and found in Appendix C,
a 97 percent removal efficiency was achieved on one FCC unit with an
37
inlet S02 concentration of 280 ppm. Scrubber sulfur oxides outlet
concentrations of 9 to 100 vppm have been observed in other FCC tests
(see Appendix C). Although designed to accommodate inlet sulfur
oxides levels as high as 3,000 vppm, the performance of sodium-based
scrubbers applied to FCC unit catalyst regenerators has not been
assessed at high inlet sulfur oxides concentrations. Since model unit
regenerator flue gas sulfur oxides concentrations are as high as 2,700
vppm, it is necessary to evaluate scrubber outlet concentrations under
these conditions. Information on sodium-based scrubber operation at
high sulfur oxides concentrations was obtained from EPA tests of
coal-fired industrial boilers. FCCU catalyst regenerator flue gas is
similar to the flue gases generated by fossil fuel-fired boilers in
flow rate, temperature, and in the composition of nitrogen, oxygen,
carbon dioxide, carbon monoxide, particulates, sulfur oxides, and
nitrogen oxides. Thus, sulfur oxides control technologies applicable
to fossil fuel-fired boilers are also applicable to FCCU catalyst
regenerators.
Fossil fuel-fired boilers emit high concentrations of sulfur
oxides when burning high sulfur fuels.
4-12
At one facility EPA conducted
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a continuous monitoring program on a sodium-based scrubber system
installed on a boiler that was burning coal with 3.25 to 3.73 weight
percent sulfur. During a 2-day period in the testing, scrubber inlet
sulfur dioxide concentrations ranged from about 1,670 to 2,760 vppm on
an hourly basis. Outlet concentrations varied during this period from
about 9 to 55 vppm, and represent emission reductions of up to 98 percent.
The performance of other sodium-based scrubbers on industrial boilers
ranges from 80 to 98 percent control of sulfur dioxide at inlet
concentrations ranging from 150 to 2,100 vppm. Thus, sodium-based
scrubbing systems will substantially reduce high flue gas sulfur
dioxide concentrations and are therefore applicable over the expected
range of FCCU catalyst regenerator sulfur dioxide emissions.
Venturi scrubbers installed on FCC regenerator flue gas streams
also control particulate emissions. Tests performed at a new FCC
regenerator show the unit to be in compliance with the new source
performance standard for particulate emissions (1 kg/1,000 kg coke
burn-off).29 This unit employs a high energy venturi scrubber.
Emissions from one FCC regenerator with a jet ejector scrubber system
are well within the particulate new source performance standard (NSPS)
although it is not a new source (see Appendix C for a summary of
results).15 In this case, State particulate emission limitations are
well below the new source standard.
4.2.3 Calcium-Based FGD Systems41
4.2.3.1 Process Description. Calcium-based FGD systems use an
aqueous slurry of insoluble calcium compounds to absorb sulfur oxides
from the flue gases. Lime (calcium oxide, CaO) or finely ground lime-
stone (calcium carbonate, CaCOg) is mixed with water to form a slurry.
The absorption of sulfur oxides by the slurry involves both gas-liquid
and liquid-solid mass transfer. The chemistry is complex and involves
many side reactions. The overall reactions are:
Lime '
39
S02 + CaO + 1/2H20
S02 + 1/202 + CaO H
Limestone
2H20
S0
2 T CaC03 + 1/2H20 ->• CaS03«l/2H20
4-14
C0
-------
S0
CaC0
2H20
2 1/202 3
The resulting product is a calcium sulfite and calcium sulfate
precipitate, which is removed from the process for disposal.
4.2.3.2 System Design. A generalized flow diagram for a calcium-
based FGD system is presented in Figure 4-3. The basic design of the
system can be divided into four process components.
(1) Reagent preparation
(2) Sulfur oxides absorption
(3) Solids separation
(4) Solids disposal
The reagent preparation for calcium-based FGD systems used for
utility boiler applications often consists of limestone crushing and
grinding, and/or lime production. For an FGD system designed for the
significantly lower flue gas flow rates typical of an industrial
boiler or FCC unit regenerator, lime or preground limestone would
probably be purchased and delivered to the facility. Thus, the reagent
preparation system for an FCC unit regenerator application would
consist of storage silos and either lime slaking or limestone slurrying
equipment.
The absorption of sulfur oxides occurs in a gas-liquid. contactor
(often referred to as an "absorber"). Various types of contactors
(e.g., venturi scrubbers, packed towers, spray towers) are used depending
on the specific FGD system design. Gases from the absorber are vented
to a stack. The absorber liquid effluent flows to a reaction vessel
or hold tank where calcium sulfite and sulfate crystals precipitate.
The hold tank is designed to provide adequate residence time for
solids precipitation as well as for dissolution of the calcium reagents.
A continuous effluent stream is pumped from the hold tank and circulated
to the absorber.
A purge stream from the hold tank is sent to a solid-liquid
separator to remove the solids from the system. Solids separation or
dewatering can be accomplished using a variety of methods depending on
the location of the disposal site and the method of disposal used.
The solids content of the waste sludge from a calcium-based FGD system
normally ranges from 30 to 85 percent by weight.
4-15
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Sludge disposal is one of the major disadvantages of calcium-based
FGD systems in comparison to other types of FGD systems. Dewatered
sludge is generally sent to a pond or landfill for disposal. Some
companies have attempted to process the waste sludge into building
materials or other salable products, but additional developmental work
remains.
4.2.3.3 Development Status. Both lime and limestone FGD systems
are currently commercially available. Calcium-based FGD systems are
the most common type of FGD systems used in the United States to
control sulfur oxides emissions from utility coal-fired boilers. A
recent survey reported that lime or limestone FGD systems were in
operation at 28 facilities, under construction at 35 facilities, and
being planned at 16 facilities. Calcium-based FGD systems have recently
been installed at two industrial boiler locations in the United States
(refer to Table 4-5). No calcium-based FGD systems have been installed
on FCC unit regenerators.
4.2.3.4 System Performance. Calcium-based FGD systems have
achieved sulfur oxides removal efficiencies of at least 90 percent for
44
flue gas streams from coal-fired utility boilers and at least 88 percent
for flue gas streams from industrial boilers. Inlet sulfur oxides
concentrations for industrial boilers may range from 200 to 2,000 ppm.'
A summary of the design characteristics for operating and planned
calcium-based FGD systems applied to industrial boilers is presented
in Table 4-5.
4.2.4 Double Alkali FGD Systems46
4.2.4.1 Process Description. Double alkali FGD systems (also
referred to as "dual alkali") use an aqueous sodium-based alkali
solution to absorb sulfur oxides from the flue gases. A second calcium-
based alkali solution is used to regenerate the active sodium solution.
Although there are other types of double alkali processes which have
been investigated, the sodium/calcium double alkali process is the
most developed. The principal chemical reactions for a sodium/calcium
double alkali system are:
Absorption
2NaOH
Na0CO^ + SO,
45
4-17
-------
Table 4-5. SUMMARY OF COMMITTED CALCIUM-BASED SYSTEMS FOR
U.S. INDUSTRIAL BOILERS AS OF MARCH 197843
Company and
Location
Armco Steel ,
Middletown, OH
Carborundum
Abrasives,
Buffalo, NY
Rickenbacker
Air Force Base
Columbus, OH
Bunge, Inc.
Cairo, IL
Pfizer, Inc.
East St. Louis, IL
Scrubber
Reagent, Air Flow
Vendor scm/m
Lime, 2,400
Koch Engi-
neeri ng
Lime, 850
Carborundum
Environmental
Systems
Lime/Lime- 1,600
stone,
Research
Cottrell-Bahco
Lime, 1,250
Dravo Corp./
Nati onal
Lime Assoc.
Lime, 1,100
Pfizer, Inc.
S02 Design
Fuel Removal
Type % Sulfur Efficiency %
Coal 0.8 NAa
Coal 2.2 95
Coal 3.6 90
Coal 3.0 94
Coal 3.5 95
aMot available.
4-18
-------
•ZMaHSO-
Regeneration
Ca(OH)9 + 2NaHSO
Ca(OH),
+ CaS03«l/2H20
CaS04»2H20
CaS03«l/2H20 + 3/2H20
•2NaOH
: c. o ' c.
Ca(OH)2 + Na2S04 + 2H20 ^2NaOH
The sodium hydroxide (NaOH) solution is recycled in the process. The,
calcium sulfite and calcium sulfate precipitate is removed for disposal.
4.2.4.2 System Design. A generalized flow diagram for a double
alkali FGD system is presented in Figure 4-4. In general, the double
alkali FGD system uses technology common to sodium-based and calcium-
based FGD systems.
The reagent preparation equipment consists of storage silos, Time
slaker, and mix tanks. Absorption of sulfur oxides occurs in a gas-liquid
contactor. The type of contactor varies depending on the FGD system
design. Gases from the contactor are vented to a stack. A portion of
the effluent is recirculated back to the contactor. The remainder of
the effluent flows to a reaction vessel into which is added the calcium-
based alkali solution. The reactor effluent is pumped to a thickener.
There the precipitated calcium salts are separated from the solution.
The regenerated NaOH solution is returned to the reagent hold tank.
Sludge containing the calcium sulfite/sulfate solids is further
concentrated in a vacuum filter to about 50 percent solids by weight.
The solids are washed, generally with one or two displacement washes
to recover sodium salts. The washed solids are then sent to a pond or
landfill for disposal. The filtrate and wash water are recycled to
the thickener.
4.2.4.3 Development Status. Several process vendors currently
commercially offer double alkali FGD systems in the United States.
Double alkali FGD systems are presently operating or planned for use
at 10 industrial boiler sites. Table 4-6 summarizes double alkali
FGD systems applied to industrial boilers. The smallest application
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is treating a 230 Sm /min gas stream, and the largest application is
treating a 8,600 Sm /min gas stream. No double alkali FGD systems
have been installed on FCC unit regenerators.
4.2.4,4 System Performance. Double alkali FGD systems have
achieved sulfur oxides removal efficiencies of at least 90 percent for
flue gas streams from coal-fired boilers with inlet concentrations as
high as 2,000 ppm and as low as 800 ppm. Design features and performance
characteristics for operating dual alkali FGD systems are presented in
Table 4-6.
4.2.5 Spray Drying FGD Systems"
4.2.5.1 Process Description. Spray drying FGD systems use an
alkaline solution to absorb sulfur oxides from the flue gases. However,
unlike the other types of FGD systems discussed, the L/G ratios for a
spray drying FGD system are insufficient to saturate the gas stream
with water. Consequently, the flue gas sulfur oxides react with the
alkaline solution or slurry, dispersed in the gases as fine droplets.
The droplets are quickly dried by the heat contained in the flue gases
and become solid particles. The alkaline solution is prepared using
soda ash or lime. Reaction between the alkaline solution and sulfur
oxides proceeds both during and following the drying process. The
mechanisms of the S02 removal reactions are not well understood. It
has not been determined whether sulfur oxides removal occurs
predominantly in the liquid phase, by absorption into the finely
atomized droplets being dried, or by reaction between gas phase sulfur
oxides and the slightly moist spray dried solids. The overall chemical
reactions for this process are shown below.
SO,
In addition to these primary reactions,
the following reactions:
Na2S03 + 1/202
SO,
sulfate salts are produced by
Na2S04
CaS04»2H20
4-22
-------
The resulting product is a dry mixture of sodium or calcium salts and
unreacted sorbents which are collected using conventional particulate
control equipment. Generally, particulate matter in the flue gases is
not collected upstream of a spray drying F6D system. Thus, spray
drying FGD systems provide both sulfur oxides and particulate emission
control.
4.2.5.2 System Design. A generalized flow diagram for a spray
drying FGD system is presented in Figure 4-5. Flue gases from the
combustion device enter a spray dryer at temperatures generally between
130 to 160°C. The alkaline slurry is sprayed into the dryer as a
finely atomized mist for contact with the hot flue gases. Gases exit
the spray dryer and are routed to a conventional particulate collection
device such as an electrostatic precipitator (ESP) or baghouse where
spent reactant is removed for disposal. Systems using a baghouse for
particulate removal report additional sulfur oxides sorption occurring
in the baghouse. Care must be taken to maintain flue gas temperature
well above saturation at this point to avoid condensation on the
solids collection device surfaces.
Accessory equipment consists of reagent preparation and dry waste
disposal facilities. In general, reagent preparation facilities
include dry storage, a mix tank, and associated tanks and pumps.
Facilities for handling the collected spray dryer waste product and
transporting it to the ultimate disposal site are similar to those
normally associated with baghouse or ESP collection devices.
4.2.5.3 Development Status. Spray drying FGD systems for removing
sulfur oxides from boiler flue gases have been demonstrated by pilot-scale
testing on industrial boiler sized systems (280 to 560 m /min) at
several utility locations in the United States where low sulfur coals
were being burned. This technology is currently being offered
commercially by several companies. Four spray drying FGD systems have
been sold for industrial boiler applications and 10 for utility boiler
applications. No spray drying FGD systems have been installed on
FCC unit regenerators.
4.2.5.4 System Performance. Pilot plant studies have shown
spray drying FGD can achieve sulfur oxides removal efficiencies up to
90 percent for low-sulfur utility and industrial coal-fired boiler
4-23
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applications. Removal efficiencies from 75 to 85 percent have been
guaranteed by vendors for recent installations of spray drying F6D
systems at industrial boiler sites (refer to Table 4-7).
4.2.6 Wellman-Lord System4'52'53
4.2.6.1 Process Description. The Wellman-Lord system utilizes a
regenerable sodium sulfite-bisulfite system to remove sulfur dioxide
from the flue gas. The sodium sulfite scrubbing liquor reacts with
sulfur dioxide in the flue gas to form sodium bisulfite and sodium
sulfate. Thermal regeneration of the sodium sulfite produces a
concentrated stream of sulfur dioxide. This sulfur dioxide can be
further processed to elemental sulfur at the refinery sulfur plant.
The Wellman-Lord process consists of two basic stages, absorption
and regeneration. The principal chemical reactions for these stages
are:
Absorption
Na2S03
2Na2S03
2Na2S03
Regeneration
2NaHSO-
4.2.6.2 System Design. A generalized flow diagram of the Wellman-
Lord system is presented in Figure 4-6. Flue gas enters a variable
throat venturi scrubber for particulate removal, cooling, and saturation
of the flue gas. The flue gas then passes through a mist-eliminator.
Within the absorber, the flue gas passes counter-currently through a
tray-type absorber with sodium sulfite-bisulfite absorbing liquor.
The scrubbed flue gas then passes through a mist-eliminator and is
vented to the stack.
Spent scrubbing liquor is filtered to remove suspended solids and
is heated in the evaporator to regenerate the scrubbing liquor. In
the evaporator, the sulfur dioxide is stripped from the scrubbing
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liquor, regenerating the sodium sulfite. A purge stream removes small
quantities of sodium sulfate, formed during absorption, and sodium
thiosulfate, formed during regeneration, from the absorbing solution.
This purge solution may contain 27 percent solids by weight. Soda ash
is added to the scrubbing liquor to replenish sodium lost to purge.
The scrubbing liquor is then returned to the absorber.
Vapors from the evaporator are cooled, condensed, and stripped of
sulfur dioxide with steam. The vapors flow to a sulfur dioxide compressor
system. From the compressor sulfur dioxide can be further processed
in a Glaus, liquid sulfur dioxide, or other end plant.
In general, reagent preparation facilities include soda ash
storage and handling equipment.
4.2.6.3 Development Status. Wellman-Lord systems for removing
sulfur oxides from flue gas have been installed on seven Glaus sulfur
plants, seven sulfuric acid plants, three industrial boilers, and four
4
utility boilers.
4.2.6.4 System Performance. Actual performance achieved by
Wellman-Lord systems is 90 percent or greater removal of sulfur dioxide.
A summary of operating Wellman-Lord systems in the U.S. is presented
in Table 4-8.
4.2.7. Citrate-Based FGD Systems55'56'57'58'59'60
4.2.7.1 Process Description. Two citrate processes are currently
available, the Bureau of Mines process and the Flakt-Bol iden process.
A third, the Peabody process, has been used in one pilot plant study
and represents a specific application of the Bureau of Mines process
with modification.
The Bureau of Mines and Flakt-Boliden citrate processes are
essentially the same in terms of S02 removal. Both processes use a
citric acid buffered solution to absorb SO,, from the flue gases. The
basic reactions which occur during absorption are:
so
If
Where: Git = citrate ion
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63
The first equation accounts for over 90 percent of the SO,, removal
61
from the flue gases. The three citrate disassociation equilibria
provide buffering to keep the pH in the optimum range for absorption
(4 to 5 for the Bureau of Mines process, 3 to 5 for the Flakt-Boliden
Cp
process. For specific applications, the exact pH needed (determined
by the S02 concentration in the feed) is maintained by adding sodium
hydroxide or soda ash to form the sodium citrate absorbent solution.
During the absorption process, some of the S0?, approximately
1.5 percent of the amount absorbed for the Bureau of Mines process
and less than 1 percent for the Flakt-Boliden process, is oxidized,
forming sulfate ions and, thus, sulfuric acid by the following reaction:
HSO: + H* + 1/20, ^H.SO.
O (L t T*
In addition, the S03 that'is not removed in the gas scrubbing system
forms sulfuric acid in the citrate solution. The sulfuric acid is
neutralized through the addition of caustic (NaOH), or soda ash, by
the following reaction:
H2S04 + ZNaOH >* Na2S04 + 2H20
The resulting sodium sulfate decahydrate is continuously removed from
the citrate solution by vacuum, crystallization. The crystallized sulfate,
Glauber's salt, may then be disposed of as a waste or sold for use as
a secondary feedstock in the chemical industry.
4.2.7.2 System Design. Both the Bureau of Mines and the Flakt-Boliden
system can be considered in terms of the following steps:
• Flue gas pretreatment
• S02 absorption
• Absorbent regeneration
• Sulfur product recovery
• Purge treatment
A generalized flow diagram for the Bureau of Mines system and the
Flakt-Boliden system are shown in Figures 4-7 and 4-8, respectively.
Flue Gas Pretreatment. In both systems, the offgases are cleaned
prior to entering the absorber. Offgases may be cleaned first by a
variety of high efficiency particulate collectors and then by electrostatic
mist precipitators (wet ESP) or venturi scrubbers. This flue gas
precleaning is designed to remove particulates, chlorides, and sulfuric
acid mist. A waste stream from the scrubber is generated and needs to
4-30
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be disposed of in an environmentally acceptable manner. Removal of
acid mist helps to minimize sodium sulfate formation in the absorber.
Sodium sulfate formation would increase the purge requirements.
65
Offgases are typically cooled to 46 to 66°C during pretreatment.
SO, Absorption. In both systems, the cooled, saturated gases enter
the bottom of a packed-column absorption tower where they flow counter-
current to the absorbent (i.e., the sodium-citrate buffered solution).
The absorption process is pH dependent. As SO,, enters the absorbent
solution, the pH decreases. The citrate acts as a buffer, maintaining
the pH in the desired range for absorption. Absorption takes place at
66
atmospheric pressure between 38 and 54°C. The cleaned gases are
released to the atmosphere, after passing through a demister.
Absorbent Regeneration. The two systems differ in both the absorbent
regeneration and the sulfur product recovery steps. In the Bureau of
Mines system, the absorbent, now loaded with S02, is sent to a closed
reactor that is agitated and operates at 52 to 54°C and about 206 kPa.
In the reactor, the S02-laden absorbent is reacted with hydrogen
sulfide (H2S). The following reaction takes place:
68
HSO" + H
+ 2H2S
3S
3H20
This reaction regenerates the absorbent and produces a slurry of
elemental sulfur and regenerated absorbent. Unreacted H2S is combined
with the offgases prior to entering a catalytic (or thermal) incinerator.
Within the incinerator, the H«S is oxidized to S07. The combined gas
69
stream then enters the offgas pretreatment system.
In the Flakt-Boliden system, the S02-laden absorbent is pumped
from the bottom of the absorption tower to the top of a stripping
tower. The stripping, which may take place at atmospheric pressure or
under vacuum,70 is accomplished by steam treatment in countercurrent
flow to the S0?-laden absorbent. The steam accepts the S02 from the
citrate solution, reversing the chemical reactions given in Section 4.2.4.1.
This stripping process thus regenerates the absorbent and produces a
mixture of S02 and water that exits the stripper at the top.
Sulfur Product Recovery. In the Bureau of Mines system, the elemental
sulfur-regenerated absorbent slurry leaves the reactor. The elemental
sulfur is separated from the absorbent by either oil or air flotation.
4-33
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The flotation process results in two separate streams; one is a concentrated
sulfur slurry, the other, the absorbent. The concentrated sulfur
slurry is treated to remove the sulfur from the slurry by melting the
regenerated sulfur and decanting the remaining absorbent. The molten
sulfur drawn off is a high-quality molten yellow sulfur.
In the Flakt-Boliden system, the mixture of SOp and water leaving
the stripping tower is cooled in a condenser where most of the water
is separated. The condensate, containing only a small amount of S02,
is returned to the stripping tower. The concentrated S02 gas can be
conveyed directly to a Claus plant for the production of elemental
sulfur, to a contact plant for sulfuric acid production, or to a
refrigeration unit for condensation to liquid SCL.
Purge Treatment. In both systems, the absorbent reclaimed during the
absorbent regeneration step contains small amounts of sodium sulfate.
Before the absorbent is recycled to the absorption tower, a small
stream is sent to a crystal!izer where the sodium citrate and sodium
sulfate are selectively crystallized. The sulfate is removed as
Glauber's salt by cooling the solution to a temperature well above the
freezing point of water.
4.2.7.3 Developmental Status. The Bureau of Mines citrate process
was devised in 1968 for application in the nonferrous smelting industry.
A pilot plant was constructed and operated in 1970 at the Magma Copper
Company's San Manuel smelter in Arizona. Another pilot plant was
constructed at the Bunker Hill base metal smelter in Kellogg, Idaho,
in 1976. The first commercial unit was completed in 1979 at a powerplant
owned and operated by St. Joe Minerals Co. The Flakt-Boliden process
is based on work begun in the early 1970s by the Boliden Company of
Sweden, the Norwegian Technical Institute Sintef, and Flakt (Svenska
Flaktfabriken). A pilot plant using the Flakt-Boliden process has
been used at the Boliden works in Sweden, treating copper and lead
smelter flue gases'. The Electric Power Research Institute is sponsoring
a pilot plant at TVA's Colbert Steam Plant in Alabama. Although
neither process has been applied to any FCC unit regenerator, one is
currently under construction to control SCL emissions from the FCC
unit regenerator at the Saber refinery in Corpus Christi, Texas.
Table 4-9 summarizes the application of citrate process systems.
4-34
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4.2.7.4 System Performance. The pilot plant studies of the
Bureau of Mines process have shown SO,, removal efficiencies over
90 percent and up to 99 percent. It has been stated that sulfur
recovery efficiencies can be in excess of 99 percent for refinery
applications.
The Flakt-Boliden process is also capable of removing over 90 percent
72
of the S02 from the flue gas. A summary of the design characteristics
of previous, operating, and planned citrate process systems is found in
Table 4-9.
4.3 FEED HYDROTREATING
Hydrotreating is a refinery process used to pretreat catalytic
cracking feeds and other process feeds by removing metal, nitrogen,
and sulfur compounds. Hydrotreating is also used to stabilize and to
improve the quality of finished products (e.g. kerosine, fuel oils,
lubrication oils) prior to being sold. The decision by a refiner to
install a hydrotreating unit is based primarily on process and economic
considerations. Feeds are hydrotreated to remove sulfur to lower the
sulfur content of refinery products; to remove metals, nitrogen,
sulfur compounds to prevent po-isoning of catalysts used in refinery
processes and, consequently, achieve longer runs, better cracking
selectivity, and improved product yield; and to remove corrosive
compounds to prolong the operating life of refinery process equipment.
The hydrotreating of feedstocks prior to processing by catalytic
cracking removes sulfur compounds from the FCC feed. The amount of
sulfur contained in coke deposits on the cracking catalysts and ultimately
converted to sulfur oxides in the FCC regenerator is determined by the
characteristics of sulfur compounds in the FCC feed. In general,
processing a high sulfur FCC feed results in higher FCC regenerator
sulfur oxides emissions than processing a low sulfur FCC feed. Therefore,
feed hydrotreating will contribute to lowering FCC regenerator sulfur
oxides emissions to the atmosphere.
4.3.1 Process Description
74
Many commercial hydrotreating processes are available. Although
variations exist between these processes the basic operations are
similar. A generalized diagram of the hydrotreating process is shown
in Figure 4-9.
4-36
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The FCC feedstock to be treated is combined with hydrogen gas and
preheated to about 370°C at high pressures. This combined feedstream
enters a reactor containing catalysts which initiate reactions between
the hydrogen and the hydrocarbon molecules. Depending on how sulfur
is bound to the hydrocarbon molecules, sulfur in the hydrocarbon
molecules can be replaced by hydrogen to form primarily saturated
hydrocarbons, hydrogen sulfide, and other gases. Hydrogen also
reacts with nitrogen compounds in the feedstock to form ammonia.
There is a net consumption of hydrogen during this process.
Effluent from the reactor vessel is cooled and separated into its
liquid and gaseous components. The gaseous fraction contains mostly
unreacted hydrogen, hydrogen sulfide, and ammonia. Both the hydrogen
sulfide and ammonia are scrubbed from the light hydrocarbon stream and
are disposed or recovered separately. The unreacted hydrogen is
recovered and returned to the reactor. The desulfurized liquid fraction
is separated into light and heavy hydrocarbon products that are used
as feedstocks for fluid catalytic cracking units and other refinery
74 75
processes or are sold as finished products. '
4.3.2 Potential for Reducing FCC Regenerator Sulfur Oxides Emissions
Reductions in sulfur oxides emissions from FCC regenerators are
related to the amount of sulfur removed from the FCC feedstock.
Hydrotreating units (HOT) are capable of reducing FCC feedstock sulfur
levels to over 98 percent.74"78 Coke sulfur and regenerator sulfur
oxides emissions, however, are not reduced by equivalent amounts.
Pilot plant studies and commercial operations have shown that when
various FCC feedstocks containing 1.7 to 2.8 weight percent sulfur are
desulfurized 88 to 96 percent and charged to an FCC unit, coke sulfur
and sulfur oxides emissions are only reduced 62 to 94 percent. '
This difference in sulfur reductions is attributable to variations
in the feedstock characteristics. FCC feedstocks are a combination of
straight chain, ring, multiple ring, and other hydrocarbon molecules.
The sulfur present in the feedstock may be bound in relatively simple
molecules such as mercaptans or in complex ring molecules called
thiophenes. Feedstocks which have relatively high proportions of
polyaromatic compounds and thiophenes are more difficult to hydrotreat
than those feedstocks that contain simple sulfur compounds. More
4-38
-------
hydrogen and higher desulfurization severity (higher temperature and
pressure) are required to achieve high reductions of sulfur from
^ *u- u • * ^ 76,79,81,82
aromatic and thiophenic feeds.
When hydrotreated feeds are charged to the FCC unit, the remaining
feed sulfur distributes between the products and the coke. If the HOT
feedstock contains primarily simple sulfur compounds, reductions in
coke sulfur and regenerator sulfur oxides emissions may approximate
the reductions in FCC feed sulfur content. If the HOT feedstock
contains high proportions of polyaromatics and thiophenes, however,
reductions in coke sulfur and sulfur oxides emissions may be considerably
lower than the FCC feed sulfur reductions. The sulfur-containing
molecules which remain in hydrotreated aromatic feedstocks preferentially
form coke. These hydrotreated feedstocks thus yield higher coke
sulfur and sulfur oxides emissions than other hydrotreated feedstocks
7fi 7Q 81 82
with identical sulfur contents. >'y>° ' Performance data for
hydrotreating of FCC feedstocks is presented in Table 4-10.
4.3.3 Additional Benefits Derived From FCC Feed Hydrotreating
There are many properties of high sulfur FCC feeds which make
these potential feedstocks undesirable. Feeds which contain sulfur in
non-thiophenic forms give high hydrogen sulfide yields and high sulfur
gasoline when charged to an FCC unit. Sulfur in thiophenic compounds
yields high sulfur cycle oils and high sulfur in coke. High molecular
weight ring compounds in aromatic feeds preferentially adsorb on the
FCC catalyst and form coke. The high nitrogen and metals contents
either poison the FCC catalyst or increase the yields of undesirable
87
products such as coke and gas.
Hydrotreating of potential FCC feedstocks, including gas oils,
deasphalted oils, atmospheric tower bottoms, and various residual
feeds, improves the feed cracking characteristics and reduces feed
sulfur, nitrogen, and metals contents. Desulfurized FCC feedstocks
exhibit improved yields of gasoline blending stocks, lower product
sulfur levels, and reduced coke and gas yields over untreated
r oi OO QQ
feedstocks. ' A gasoline yield improvement of up to 20 percent
90
for desulfurized over untreated FCC feedstocks has been observed.
Also, FCC throughput may, in some cases, be increased due to higher
first pass conversion of the feed into useful products. These yield
4-39
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114
and product quality shifts result from the hydrogenation and saturation
of organic sulfur and polyaromatic compounds in the feed. The magnitude
of the yield and quality shifts depends on the quality of the untreated
feedstock and the degree of hydrotreating.
The hydrotreating of FCC feedstocks may also result in air quality
benefits beyond the reduction in FCC regenerator sulfur oxides emissions.
Because there are no government or industry-wide sulfur content specifi-
cations for gasoline, catalytic cracked gasoline is normally not
hydrotreated prior to blending with other gasoline stocks. However,
by removing sulfur compounds, hydrotreating of FCC feedstocks reduces
the sulfur content of gasoline obtained by catalytic cracking. Lower
sulfur contents in gasoline result in reduced sulfur oxides emissions
to atmosphere from the combustion of gasoline in motor vehicle engines.
4.3.4 Development Status
As of January 1979, 31 refineries were pretreating all or a
portion of their FCC charge stock. The total U.S. FCC feed hydrotreating
3
capacity was 142,000 m /sd or about 18 percent of the total FCC fresh
feed capacity. It is expected that this percentage will increase as
91
refiners increase their ability to process high sulfur crudes.
Economic and process considerations affect the decision by a
refiner to install an FCC feed hydrotreating unit. It is unlikely
that an FCC feed hydrotreater would be installed solely to comply with
regenerator sulfur oxides limitation. The investment required by a
refiner to install a hydrotreating unit varies with the type of
hydrotreating process selected and the types of feedstocks to be
treated. Typical capital costs for hydrotreating units range from
3 92
$2,000 to $10,000 per cubic meter of feed per stream day (m /sd).
In general, the costs for hydrotreating gas oils are at the lower end
of the range and the costs for hydrotreating residuum are at the upper
end of the range. For example, the capital cost for a 2,500 m /sd
hydrotreating unit processing Middle East vacuum gas oil at 90 percent
OA
desulfurization is approximately $8 million. The capital cost for
3
an 8,000 m /sd hydrotreating unit processing Arabian Heavy residuum at
93
98 percent desulfurization is approximately $80 million. Because a
net consumption of hydrogen occurs during hydrotreating, hydrogen
4-41
-------
costs can be significant. In most refineries, sufficient hydrogen to
handle normal hydrotreating requirements is available as a byproduct
73
from catalytic reforming. However, if separate hydrogen manufacturing
facilities are needed, the capital costs for a new hydrotreating unit
at a specific refinery will be higher than the costs estimated for the
example hydrotreating units.
A major process consideration influencing a refiner's decision to
install a hydrotreating unit is the need to protect catalysts susceptible
to poisoning by sulfur, nitrogen, and metal compounds in process
feedstocks. Without hydrotreating the feedstock, catalyst life is
greatly reduced. Therefore, the cost of hydrotreating is justified by
longer catalyst life, better product yields, and better product quality.
Other process considerations include a refiner's desire to protect
refinery equipment from corrosive compounds and to meet finished
product specifications.
4.4 PRXESS CHANGES
Since sulfur oxides emissions from the FCC regenerator are determined,
for any given feedstock, by the amount of coke formed on the FCC
catalyst, process adjustments which decrease coke production may also
reduce sulfur oxides emissions. Three technological developments have
given FCC operators considerable flexibility in controlling product
yields, operating conditions, and sulfur oxides emissions. These
94
are:
(1) Zeolite catalysts
(2) Transfer line (riser) cracking
(3) High temperature or carbon monoxide-promoted regeneration.
Other process changes, such as adjustments in the type and quantity of
feed recycle, may also be used to reduce regeneration sulfur oxides
emissions.
4.4.1 Zeolite Catalysts
Catalyst evolution has resulted in high activity zeolite catalysts
which have higher cracking activity, greater liquid yields and improved
stability over early amorphous catalysts. ' High activity zeolite
catalysts can reduce the production of coke on FCC catalysts when
compared to older catalysts. Aromatic compounds preferentially form
4-42
-------
coke on the FCC catalyst and increase sulfur oxides emissions; because
of their high activity, zeolite catalysts can promote the dehydrogenation
of feed aromatic compounds and, therefore, reduce sulfur oxides emissions.
The amount of time the catalyst is in contact with the FCC hydrocarbon
feed and other factors such as feed temperature may result in greater
coke formation. Refiners may periodically adjust the contact time
97
to maximize the yields of certain products. To control sulfur
oxides emissions from the regenerator, a refiner may choose to minimize
catalyst/hydrocarbon contact times and coke production.
4.4.2 Transfer Line (Riser) Cracking
The development of zeolite -catalysts spurred the development of
transfer line or riser cracking. Transfer line cracking refers to the
action of cracking the FCC hydrocarbon feed partially or entirely
within the pipe that transfers the regenerated catalyst and feed
hydrocarbons to the separator vessel. In early FCC units, most
hydrocarbon cracking occurred on a fluidized bed of catalyst, hydrocarbons,
and steam inside what is now called the separator vessel.
Short contact time riser cracking techniques result in optimal
utilization of high activity zeolite catalysts. Zeolite catalysts in
conjunction with riser cracking enable the refiner to reduce coke
OQ
formation. In part, the degree of control is dependent on the
characteristics of the FCC hydrocarbon feed.
4.4.3 New Regeneration Techniques
Variables associated with regeneration have an impact on regenerator
emissions. The efficiency of coke burn-off during the regeneration
process directly affects the production of coke during the hydrocarbon
cracking reactions, and thus affects emissions from the regenerator.
Regeneration efficiency is measured by determining the weight percent
of carbon that remains on the regenerated catalyst (CRC). Since large
coke deposits (high CRC) inhibit zeolite catalyst activity, it is
usually desirable to minimize CRC by efficiently burning off the coke
99
deposits.
New techniques have been developed to simultaneously increase
regeneration efficiency and reduce the emissions of carbon monoxide
from the FCC regenerator. High temperature regeneration uses higher
4-43
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102
temperatures than conventional regeneration to burnoff catalyst coke
deposits. Carbon monoxide oxidation-promoted regeneration uses catalysts
to promote the complete combustion of carbon monoxide.
Conventional regeneration techniques presently used by most
refiners yield CRC on the order of 0.1 to 0.6 weight percent. ' '
The latest regeneration techniques can reduce CRC to about 0.02 weight
percent.
It is difficult to separate emissions effects which result from
process changes involving catalysts, riser cracking, or complete
regeneration techniques. It has been estimated that the combined
effect of these process changes has been a 40 percent reduction in
94
sulfur oxides emissions from units which have used the processes.
Process changes which involve catalysts, riser cracking variables, and
regenerator conditions may alter coke production from over 6 percent
to 4 percent by weight of the FCC feed for commonly used feedstocks.
Such a change would be expected to yield greater than 33 percent
reductions in regenerator sulfur oxides emissions for a given feedstock
if coke sulfur remains constant.
4.4.4 Other Process Changes
Other process changes which affect regenerator sulfur oxides
emissions involve changes in the coke make rate. Often, small portions
of the heavy FCC products are recycled from the fractionator for
additional cracking to increase the yields of certain products.
Maximum gasoline yield is obtained, for example, by recycling a portion
103
of the distillate product material. This action, however, increases
coke production and mass emissions of sulfur oxides. It has been
estimated that a 5 volume percent decrease in heavy oil recycle would
104
result in a decrease in coke production of 0.3 weight percent. An
increase in conversion increases gasoline production. This action,
however, also increases coke production and mass emissions of sulfur
oxides.
4.5 SULFUR OXIDES REDUCTION CATALYSTS
An emerging technology for the control of FCC regenerator sulfur
oxides emissions uses special catalysts which influence the movement
4-44
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of sulfur within the FCC unit. Sulfur oxides formed during catalyst
regeneration are captured on these special catalysts, thus preventing
emissions to the atmosphere. In the FCC reactor and separator vessel,
the captured sulfur oxides are transformed into hydrogen sulfide and
vented with the cracked hydrocarbon vapors to the fractionator and
ultimately to the refinery sulfur plant. Reductions as high as 90 percent
have been achieved in small scale bench and pilot plant tests, while
op inc 1 n Q
up to 80 percent reduction has been obtained in commercial tests. '
About 8 percent of nationwide FCC unit processing capacity utilize
first generation sulfur oxides reduction catalysts. These catalysts
have limited sulfur oxide reduction capabilities and typically achieve
30 to 40 percent sulfur oxide emissions reduction over normal catalysts.
4.5.1 Process Description
Although several oil companies and catalyst vendors are developing
the sulfur reduction catalyst sulfur oxides control technique, the
82 10Q
reaction mechanisms involved are similar ' and are summarized
below:
111
Regenerator Reactions:
S (in coke) +
S02 + 1/2 02
SO- + metal (in catalyst)-
Reactor/Separator Reactions:
MS0 + 4H
MS + 4H20
Sulfur Burning
S02 Oxidation
•MSO. Metal Sulfate
Formation
Metal Sulfate
Reduction
MS + H20
•MO + H2S
Sulfide Hydrolysis
Sulfur in the catalyst coke is oxidized to sulfur dioxide and
sulfur trioxide in the FCC regenerator. The sulfur trioxides combine
with metals (usually aluminum or magnesium) in the special catalyst to
form metal sulfates which are stable under internal regenerator conditions.
The regenerated catalyst and the metal sulfates are then routed to the
reactor as in normal FCC operations.
4-45
-------
79
Interpretations of the reaction mechanisms which convert the
metal sulfates to hydrogen sulfide in the reactor/separator vary
slightly. Amoco suggests that the metal sulfates are reduced in the
presence of the hydrocarbon feed and that the metal sul fides are
hydrolyzed in the steam stripper section of the separator vessel.
Patents issued to Chevron indicate that the steam stripper may not be
involved in the sulfide hydrolysis. In either case, the hydrogen
sulfide thus formed is vented to the FCC fractionator with the product
stream. The hydrogen sulfide is eventually separated from the liquid
products and processed into elemental sulfur at the refinery sulfur
recovery plant. The catalyst is returned to the regenerator vessel to
burn off coke deposits and to begin the sulfur oxides capture process.
As with conventional fluid catalytic cracking, the process is continuous.
The sulfur active catalysts may be present in several forms in
the catalyst inventory. It may either be incorporated into the cracking
catalyst or added as a separate solid which would constitute a portion
of the total FCC catalyst inventory.
4.5.2 Development Status
Sulfur oxides reduction catalysts have been under development for
several years. Many bench scale and pilot plant tests have been
conducted, and a limited number of commercial tests have been performed.
Results of bench scale, pilot plant, and commercial tests show that
sulfur oxides emissions reductions are high as 90 percent have been
112
achieved with development sulfur oxides reduction catalysts.
Several problems have been encountered by some of the process developers
in obtaining pilot plant results in commercial operations. Nevertheless,
a recent commercial scale test of a commercially available sulfur
oxides reduction catalyst, summarized in Appendix C, and other commercial
scale tests of developmental sulfur oxides reduction catalysts, summarized
in Table 4-11, show that sulfur oxides reduction catalysts are capable
of reducing the regenerator emissions from an FCC unit processing a
1 percent sulfur feed by about 80 percent.106'108'11 Based on these
commercial test data, sulfur oxides reduction catalysts are expected
to achieve 80 percent reduction in sulfur oxides emissions from FCC
units processing 1 to 2 percent sulfur feeds when developed.
4-46
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Table 4-11. Summary of SOV REDUCTION CATALYST
11?
PERFORMANCE DATA11^
Company
ARCO
ARCO
ARCO
Chevron
Chevron
Chevron
Mobil
Mobil
Texaco
API
Davison
Davison
Davison
Davison
Davi son
FCC Unit
Regeneration
Mode
Conventional
HTR with
CO Promoter
HTR with
CO Promoter
Conventional
with CO
Promoter
Conventional
with CO
Promoter
--
HTR
HTR
HTR
Conventional
with CO
Promoter
Conventional
Conventional
Conventional
Conventional
Conventional
Feed
Sulfur Estimated SO
Level Emission ,
(Weight Reduction '
Percent) (Percent)
1.10
1.18
0.31
0.99
1.19
0.45
1.27
1.0
1.26
1.16
0.48-0.58
0.48-0.58
0.56
0.52
0.48-0.58
73
57
30
94
88
67
72
66
57
41
45
58
66
55
80
Controlled SO
Emission
Level
(kg/1,000 kg
coke burn-off)
8.5° >d
14.7d
' 7.7d
1.6
4.2
5.0c'e
10.0
10.1
15.1
20. Of
11C
8.5C
7.1C
9.0C
4.0C
Estimated percent reduction was obtained by comparing actual SO
emissions with SO reduction catalysts in use to estimated baseline
emissions. Estimated baseline emissions were obtained by using the
average feed sulfur level during catalyst testing and the SOX emissions/
feed sulfur relationship found in Figure 3-6.
Estimated percent emission reduction may include the effects of first
generation SO reduction catalysts as well as the developmental SOX
reduction catalyst.
GEmissions originally reported in vppm were converted to kg/1,000 kg
coke burn-off by using Figure 3-6.
The low SO emission levels obtained during testing do not represent
equilibrium conditions and do not indicate that long-term operation
under these conditions would be feasible.
eDue to problems with the operation of the FCC unit which predated the
test, SO reduction catalyst addition was terminated before the
desired level of emission reduction was achieved.
Unit was operated in the partial CO combustion mode. This may have
affected the SO reduction capabilities of the S0x reduction catalyst
being evaluated.
4-47
-------
In some instances, emissions of oxides of nitrogen (NOX) have
increased two to seven fold when operating the sulfur oxides reduction
98
catalysts at high sulfur oxides reduction levels. When N0x emissions
were controlled by altering the catalyst, problems with rapid deactivation
105
of catalyst sulfur oxides retention capability and yield debits
(reductions in product quantity and quality) were encountered. Nitrogen
oxides emissions data from FCC units operating with and without the
sulfur oxides reduction catalysts were obtained in order to evaluate
NO emissions increases due to the use of the catalysts. An analysis
of these data showed that NO emissions increases resulting from use
A
of these catalysts are not signficant. However, CO promoted conventional
regeneration FCC units appear to have high N0x emissions without
sulfur oxides reduction catalysts, and even higher NO emissions with
A
sulfur oxides reduction catalysts. The significance of this increase
is unknown due to the limited number for sulfur oxides reduction
catalyst emission tests performed.
113
4-48
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4.6 REFERENCES
1. Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurization. U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-600/7-79-178i.
November 1979. p. 1-5. Docket Reference Number II-A-10.*
2. Letter and Attachments from Murphy, J.R., The M.W. Kellogg Company,
to Farmer, J.R., U.S. Environmental Protection Agency. May 7,
1981. Comment on BID Volume I, Chapters 3-6. Docket Reference
Number II-D-49.*
3. Reference 1. p. 2-3. Docket Reference Number II-A-10.*
4. Letter and Attachments from Pedroso, R.I., Davy McKee Corporation,
to Farmer, J.R., U.S. Environmental Protection Agency. April 13,
1981. Comments on BID Volume I, Chapters 3-6. Docket Reference
Number II-D-45.*
5. Manda, M., Pacific Environmental Services, Inc. Trip Report:
Conoco, Incorporatedj Ponca City, Oklahoma. August 14, 1980. p.
4. Docket Reference Number II-B-12.*
6. Telecon. Sorrentino, C., Amoco Research and Development with
Manda, M. Pacific Environmental Services, Incorporated. October 28,
1980. Discussion of FCCU operation and format of standard. Docket
Reference Number II-E-6.*
7. Letter and Attachments from Flynn, J.P., Exxon Company U.S.A., to
Farmer, J.R., U.S. Environmental Protection Agency. May 8, 1981.
Comments on BID Volume I, Chapters 3-6. Docket Reference Number
II-D-50.*
8. Babcock and Wilcox. Steam, Its Generation and Use.. 38th Edition.
New York, New York. 1975. pp. 5-11, 5-15. Docket Reference
Number II-I-15.*
9. Supplement No. 8 for Compilation of Air Pollutant Emission Factors
3rd Edition, (Including Supplements 1-7). U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. AP-42. May 1978. p. 9.1-6. Docket Reference Number II-I-41.*
10. Memorandum from Peterson, P., Pacific Environmental Services,
Inc., to Docket Number A-79-09. April 22, 1982. Comparison of
Theoretical Flue Gas Composition for an FCC Unit Regenerator and
a Coal-Fired Boiler Unit. Docket Reference Number II-B-21.*
11. Reference 1. p. 2-55. Docket Reference Number II-A-10.*
12. Manda, M., Pacific Environmental Services, Inc. Trip Report.
Exxon Company, U.S.A., Baton Rouge, Louisiana. July 24, 1980.
Docket Reference Number II-B-10.*
4-49
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13. Cunic, J.D., S.A. Diamond, P.E. Reeder, and L.M. Williams. FCC
Stack Scrubbers Do Double Duty. The Oil and Gas Journal. 76_(23}:72.
May 22, 1978. Docket Reference Number 11-1-42.*
14. Cantrell, Ailleen. Annual Refining Survey. Oil and Gas Journal.
78(12):130-157. March 24, 1980. Docket Reference Number II-I-71.*
15. Letter and Attachments from Westphal, F.A., Exxon Company, U.S.A.,
to Londres, E.J., New Jersey Bureau of Air Pollution Control.
February 14, 1979. Wet scrubber emission tests. Docket Reference
Number II-D-2.*
16. Stack Sampling at Champ!in Petroleum, Corpus Christi, Texas, on
October 28-29, 1975. Texas Air Control Board. Austin, Texas.
Account No. 110-656-2. November 26, 1975. Docket Reference
Number II-I-22.*
17. Stack Sample at Shell Refinery, Deer Park, Texas, on July 14-15,
1977. Texas Air Control Board. Austin, Texas. Account No. 112-062-0.
October 3, 1977. Docket Reference Number II-1-33.*
18. Stack Sampling at Shell Oil Company - Odessa Refinery, Odessa,
Texas, on October 19-20, 1976. Texas Air Control Board. Austin,
Texas. Account No. 112-064-6. November 8, 1976. Docket Reference
Number II-I-26.*
19. Stack Sampling at Texaco, Inc., Port Arthur, Texas, on November 3-4,
1976. Texas Air Control Board. Austin, Texas. Account No. 113-279-2.
December 3, 1976. Docket Reference Number II-1-27.*
20. Stack Sampling at Phillips Petroleum, Borger, Texas, on June 24,
and 25, 1975. Texas Air Control Board. Austin, Texas. Account
No. 110-392-0. July 16, 1975. Docket Reference Number II-1-18.*
21. Stack Sampling at Exxon Refinery, Baytown, Texas. Texas State
Department of Health. January 22-26, 1973. Docket Reference
Number II-1-9.*
22. Stack Sampling at Union 76 Refinery, Nederland, Texas, on July 8-9,
1976. Texas Air Control Board. Austin, Texas. Account No. 114-147-3.
July 27, 1976. Docket Reference Number II-1-25.*
23. Stack Sampling at Mobil Oil Corporation Beaumont Refinery on
February 9-10, 1977. Texas Air Control Board. Austin, Texas.
Account No. 109-145-0. April 4, 1977. Docket Reference Number
II-I-30.* '
24. Reference 1. pp. 2-147 to 2-160. Docket Reference Number II-A-10.*
25. Exxon Research and Engineering Company. Fluid Catalytic Cracking
Unit Flue Gas Scrubbing. Florham Park, New Jersey. March 1979.
p. 14. Docket Reference Number II-I-50.*
4-50
-------
26. Reference 25. pp.2-3. Docket Reference Number II-I-50.*
27. Reference 13. p. 70. Docket Reference Number II-I-42.*
28. Reference 25. p. 6. Docket Reference Number II-I-50.*
29. Manda, M.5 Pacific Environmental Services, Inc. Trip Report:
Marathon Oil Company, Garyville, Louisiana. September 24, 1980.
Docket Reference Number II-B-13.*
30. Dickerman, J.C. Applicability of FGD Systems to Industrial
Boilers, EPA-600/9-81-019b, Vol. 2, Radian Corporation, Durham,
North Carolina. (Presented at the EPA Symposium on Flue Gas
Desulfurization. Houston. October 28-31, 1980.) p. 3. April
1981. Docket Reference Number II-A-16.*
31. Reference 30. p. 2. Docket Reference Number II-A-16.*
32. Emission testing for Exxon Company, U.S.A., Baton Rouge, Louisiana.
Kemron Environmental Services. Baton Rouge, Louisiana. June 15, 1978.
Docket Reference Number 11-1-44.*
33. Kemron Environmental Services. Emission Testing for Exxon Company,
U.S.A., Baton Rouge, Louisiana. June 20, 1979. pp. 4-6. Docket
Reference Number II-I-60.*
34. Sulfur Dioxide Sampling and Continuous Monitoring at Exxon Baytown
Refinery, Baytown, Texas. Texas Air Control Board. Austin,
Texas. Account No. 07-HG-0232-0. January 11, 1979. p. 4.
Docket Reference Number II-1-48.*
35. Stack Sampling at Exxon Refinery, Baytown, Texas, on September 4-5,
1975. Account number 104-703-5. Texas Air Control Board.
Austin, Texas. November 19, 1975. Docket Reference Number
II-I-20.*
36. Stack Sampling at Exxon Refinery, Baytown, Texas, on April 21-22,
1976. Account number 104-703-5. Texas Air Control Board.
Austin, Texas. June 25, 1976. Docket Reference Number II-I-24.*
37. Letter and Attachments from Albaugh, D., Marathon Oil Company, to
Goodwin, D.R., U.S. Environmental Protection Agency. March 20,
1981. Response to Section 114 information request. Docket
Reference Number II-D-41.*
38. Continuous Sulfur Dioxide Monitoring of a Petroleum Refinery,
Marathon Oil Company, Garyville, Louisiana. Emission Measurement
Branch, U.S. Environmental Protection Agency. Research Triangle
Park, North Carolina. August 5, 1981. Docket Reference Number
II-A-18.*
4-51
-------
39. Continuous Emission Monitoring for Industrial Boilers, General
Motors Corporation Assembly Division, St. Louis, Missouri.
Volume I, System Configuration and Results of the Operational
Test Period. U.S. Environmental Protection Agency. Research
Triangle Park, North Carolina. June 1980. Docket Reference
Number II-A-11.*
40. Reference 1. p. 2-153. Docket Reference Number II-A-10.*
41. Reference 1. pp. 2-7 to 2-79. Docket Reference Number II-A-10.*
42. Reference 1. p. 2-9. Docket Reference Number II-A-10.*
43. EPA Industrial Boiler F6D Survey: First Quarter 1979. U.S.
Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-600/7-79-067b. April 1979. pp. 109, 113,
148, 159. Docket Reference Number II-A-8.*
44. Evaluation of Three 20 MW Prototype Flue Gas Desulfurization
Processes. Electric Power Research Institute. Palo Alto, California.
EPRI FP-713. March 1978. p. 4-5. Docket Reference Number
II-I-36.*
45. Reference 1. p. 2-67. Docket Reference Number II-A-10.*
46. Reference 1. pp. 2-79 to 2-111. Docket Reference Number II-A-10.*
47. Reference 1. pp. 2-161 to 2-171. Docket Reference Number II-A-10.*
48. Reference 1. p. 2-84, 2-93. Docket Reference Number II-A-10.*
49. Reference 1. p. 2-164. Docket Reference Number II-A-10.*
50. Kelly, M.E. and J.C. Dicker-man. Current Status of Dry Flue Gas
Desulfurization Systems. Volume 2, EPA-600/9-81-019b. Radian
Corporation. Durham, North Carolina. (Presented at the EPA
Symposium on Flue Gas Desulfurization. Houston, Texas.
October 28-31, 1980). April 1981. p. 8. Docket Reference
Number II-A-17.*
51. Reference 50. pp. 3 to 7. Docket Reference Number II-A-17.*
52. Reference 1. pp. 2-111 to 2-131. Docket Reference Number II-A-10.*
53. Fluid Catalytic Cracking Emission Control by the Wellman-Lord and
the Davy Saarberg-Hoelter FGO processes. Davy McKee Engineers
and Constructors. Lakeland, Florida. Report No. 1491/0. March
1981. Docket Reference Number II-A-14.*
54. Reference 1. p. 2-119. Docket Reference Number II-A-10.*
4-52
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55. Madenburg, R.S. and R.A. Kurey. Citrate Process Demonstration
Plant - A Progress Report. In Proceedings: Symposium on Flue
Gas Desulfurization. Hollywood, FL, November 1977 (Volume II).
U.S. Environmental Protection Agency. Research Triangle Park,
N.C. Publication No. EPA-600/7-78-058b. pp. 707-735. Docket
Reference Number II-A-21.*
56. Control Techniques for Sulfur Oxide Emissions from Stationary
Sources. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-450/3-81-004. April 1981.
pp. 4.2-122 to 4.2-132. Docket Reference Number II-A-23.*
57. Madenburg, R.S. and T.A. Seesee. H2S Reduces S02 to Desulfurize
Flue Gas. Chemical Engineering. July 14, 1981. pp. 88-89.
Docket Reference Number 11-1-94.*
58. Farrington, James and Sue Bengtsson. Citrate Solution Absorbs
S0~. Chemical Engineering. June 16, 1980. pp. 88-89. Docket
Reference Number 11-1-93.*
59. Feasibility of Primary Copper Smelter Weak Sulfur Dioxide Stream
Control. U.S. Environmental Protection Agency. Cincinnati, OH.
Publication No. EPA-600/2-80-152. July 1980. pp. 153-171.
Docket Reference Number II-A-22.*
60. Telecon. Nissen, Bill, Bureau of Mines with Meardon, Ken, Pacific
Environmental Services, Incorporated. February 11, 1982. Information
on citrate scrubber operation. Docket Reference Number II-E-5.*
61. Reference 55. p. 712. Docket Reference Number II-A-21.*
62. Reference 58. p. 88. Docket Reference Number li-I-93.*
63. Reference 57. p. 89. Docket Reference Number II-I-94.*
64. Reference 58. p. 88. Docket Reference Number II-I-93.*
65. Reference 59. p. 163. Docket Reference Number II-A-22.*
66. Reference 58. p. 89. Docket Reference Number 11-1-93.*
67. Reference 59. p. 163. Docket Reference Number II-A-22.*
68. Reference 57. p. 89. Docket Reference Number II-I-94.*
69. Reference 57. p. 89. Docket Reference Number II-I-94.*
70. Reference 58. p. 89. Docket Reference Number II-I-93.*
71. Reference 57. p. 88. Docket Reference Number II-I-94.*
72. Reference 58. p. 88. Docket Reference Number II-I-93.*
4-53
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73. Refining Processes Handbook. Hydrocarbon Processing. 59:97-98.
September -1980. Docket Reference Number II-I-79.*
74. Reference 73. pp. 97-134. Docket Reference Number 1 1- 1-79.*
75. Sulfur Dioxide/Sulfate Control Study - Main Text. South Coast
Air Quality Management District. El Monte, California. May
1978. pp. 6.88 to 6.89. -Docket Reference Number II-I-40.*
76. Ritter, R.E., J.J. Blazek, and D.N. Wallace. Hydrotreating FCC
Feed Could Be Profitable. The Oil and Gas Journal. 72_(M}:IQ2.
October 14, 1974. Docket Reference Number II-I-14.*
77. McCullock, D.C. Feed Hydrotreating Improves FCCU Performance.
The Oil and Gas Journal. T3L(27):56. July 21, 1975. Docket
Reference Number II-I-19.*
78. Yanik, S.J., J.A. Frayer, G.P. Huling, and A.E. Somers. Latest
Data on Gulf HDS Process. Hydrocarbon Processing. _56.(5):98.
May 1977. Docket Reference Number II-I-31.*
79. Letter and Attachments from Sorentino, C. , Amoco Oil Company, to
Manda, M., Pacific Environmental Services, Incorporated. October 15,
1980. Responses, to request for FCC operations data. Docket
Reference Number II-D-28.*
80. Huling, G.P., J.D. McKinney, and T.C. Readal. Feed Sulfur Distribution
in FCC Product. The Oil and Gas Journal. 73_(18):73. May 19,
1975. Docket Reference Number II-I-17.*
81. Manda, M., Pacific Environmental Services, Inc. Trip Report:
Shell Oil Company, Houston, Texas. July 23, 1980. Docket Reference
Number II-B-9.*
82. Manda, M., Pacific Environmental Services, Inc. Trip Report:
Chevron U.S.A., Incorporated, Richmond, California. April 3,
1980. Docket Reference Number II-B-3.*
83. Reference 73.
84. Reference 73.
p. 114. Docket Number II-I-79.*
p. 108. Docket Number II-I-79.*
85. Letter from Sorrentino, C., Amoco Oil, to J. Farmer, EPA. January 3,
1981. 114 Response. Docket Reference Number II-D-54.*
86. HDS FCC Equals More Gasoline. Oil and Gas Journal, p. 115.
May 17, 1976. Docket Reference Number .
87. Reference 78. p. 99. Docket Reference Number II-I-31.*
88. Reference 78. pp. 100-101. Docket Reference Number II-I-31.*
89. Reference 76. p. 99. Docket Reference Number II-I-14.*
4-54
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90. Reference 70. p. 97. Docket Reference Number II-I-31.*
91. Aalund, L.R., Sour Crude Technology Set for the 80's. The Oil
and Gas Journal. _78(12):78. March 24, 1980. Docket Reference
Number II-I-73.*
92. Reference 73. . p. 97-144. Docket Reference Number II-I-79.*
93. Reference 73. p. 107. Docket Reference Number II-I-79.* ,
94. Vasalos, I.A., E.R. Strong, C.K.R. Hsieh, and G.J. D'Souza. New
Cracking Process Controls FCCU sulfur oxides. The Oil and Gas
Journal. _7J5.(25): 142. June 27, 1977. Docket Reference Number
II-I-32.* .
95. Magee, J.S., Ritter, R.E., et.al. How Cat Cracker Feed Composition
Affects Catalyst Octane Performance. National Petroleum Refiners
Association Paper AM-80-48. (Presented at the 1980 NPRA Annual
Meeting.) March 23-25, 1980. p. 4. Docket Reference Number
II-I-70.*
96. Magee, J.S. and Ritter, R.E. Recent Advances in Fluid Cracking
Catalyst Technology. National Petroleum Refiners Association
Paper AM-79-35. (Presented at the 1979 NPRA Annual Meeting.)
March 25-27, 1979. p. 1. Docket Reference Number II-I-54.*
97. Fluid Catalytic Cracking with Molecular Sieve Catalysts. Petro/
Chem Engineering. 41_(5):15. May 1969. Docket Reference Number
II-I-2.*
98. Reference 95. p. 5. Docket Reference Number II-I-70.*
99. Magee, J.S., Ritter, R.E., and Rheaume, L. A Look at FCC Catalyst
Advances. Hydrocarbon Processing. .58(9):128. September 1979.
Docket Reference Number II-I-64.*
100. Shields, R.J., Fahrig, R.J., and Horecky, C.J. FCC Regeneration
Technique Improved. The Oil and Gas Journal. 70_(22):45. May 29,
1972. Docket Reference Number II-I-7.*
101. Letter and Attachments from Grossberg, A.L., Chevron Research
Company, to Fanner, J.R., U.S. Environmental Protection Agency.
May 4, 1981. Comments on BID Volume I, Chapters 3-6. Docket
Reference Number II-D-47.*
102. Murcia, A.A., M. Soudek, G.P. Quinn, and G.J. D'Souza. FCCU
Design Criteria for Processing Flexibility. National Petroleum
Refiners Association Paper AM-79-38. (Presented at the 1980 NPRA
Annual Meeting.) March 25-27, 1979. Docket Reference Number
II-I-53.*
103. Reference 102. p. 8. Docket Reference Number II-I-53.*
4-55
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104. Letter from D.P. Martin, Gulf Oil Company, to G. Bernstein,
Pacific Environmental Services, Incorporated. Information on FCC
unit feed sulfur contents, coke make rates, and recycle.
November 17, 1980. Docket Reference Number II-D-33.*
105. Manda, M., Pacific Environmental Services, Inc. Trip Report:
Standard Oil of Indiana (AMOCO), Chicago, Illinois. April 1,
1980. Docket Reference Number II-B-1.*
106. Telecon. Beyaert, B., Chevron U.S.A., Incorporated, with Manda, M.,
Pacific Environmental Services, Incorporated. November 21, 1980.
Chevron's commercial sulfur oxides Catalysts. Docket Reference
Number II-E-3.*
107. Manda, M., Pacific Environmental Services, Inc. Trip Report:
Atlantic Richfield Petroleum Products Company, Harvey, Illinois.
April 2, 1980. Docket Reference Number II-B-2.*
108. Letter and Attachments from Buffalow, O.T., Chevron U.S.A.,
Incorporated, to Goodwin, D.R., U.S. Environmental Protection
Agency. June 29, 1981. Response to Section 114 information
request. Docket Reference Number II-D-57.*
109. Chevron Research Company. Catalyst for Removing Sulfur from a
Gas. United States Patent No. 4,152,298. May 1, 1979. Docket
Reference Number II-I-58.*
110. Johnson, J.M. Presentation at the NAPCTAC Meeting on Behalf of
the American Petroleum Institute. In: National Air Pollution
Control Techniques Advisory Committee, Minutes of Meeting, December 1
and 2, 1981. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. December 22, 1981. p. 11-19.
Docket Reference Number II-B-18.*
111. National Air Pollution Control Techniques Advisory Committee,,
Minutes of Meeting, December 1 and 2, 1981. U.S. Environmental
Protection Agency. Research Triangle Park, North Carolina.
December 22, 1981. p. 11-51. Docket Reference Number II-B-18.*
112. Memorandum from Bernstein, G., Pacific Environmental Services,
Inc., to Docket Number A-79-09. April 28, 1982. Results of
Analyses of Commercial Tests of Developmental Sulfur Oxides
Reduction Catalyst Performance. Docket Reference Number II-B-25.*
113. Memorandum from Bernstein, G., Pacific Environmental Services,
Inc., to Docket Number A-79-09. May 21, 1982. Results of Analysis
of NOV Emissions Study. Docket Reference Number II-B-20.*
/\
114. Memorandum from McDonald, R., U.S. Environmental Protection
Agency, to Docket Number A-79-09. March 23, 1982. Sulfur Oxides
and Nitrogen Oxides Related to Catalytic Cracking of Hydrodesulfurized
Gas Oil. Docket Reference Number II-B-19.*
4-56
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115. Letter and attachments from Gill, W., Texas Air Control Board, to
Rhoads, T.W., Pacific Environmental Services, Inc. December 15,
1981. Compliance Test for the Southwestern Refining Company FCC
Unit. Docket Reference Number II-D-85.*
116. Questions and Answers on Refining Technology; Transcription of
NPRA Q&A Symposia, 1975-1979 and Comprehensive Five-year Index.
National Petroleum Refiners Association. Washington, D.C.
p. 79-69. Docket Reference Number II-1-109.*
*References can be located in Docket Number A-79-09 at the U.S.
Environmental Protection Agency's Central Docket Section, West
Tower Lobby, Gallery 1, Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
4-57
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5.0 MODIFICATION AND RECONSTRUCTION
In accordance with the provisions of Title 40 of the Code of
Federal Regulations (CFR), Sections 60.14 and 60.15, an existing
facility can become an affected facility and, consequently, subject to
the standards of performance if it is modified or reconstructed. An
"existing facility," defined in 40 CFR 60.2, is a facility of the type
for which a standard of performance is promulgated and the construction
or modification of which was commenced prior to the proposal date of
the applicable standards. The following discussion examines the
applicability of modification/reconstruction provisions to the fluid
catalytic cracking unit regenerator.
5.1 GENERAL DISCUSSION OF MODIFICATION AND RECONSTRUCTION PROVISIONS
5.1.1 Modification
Modification is defined in §60.14 as any physical or operational
change to an existing facility which results in an increase in the
emission rate of the pollutant(s) to which the standard applies.
Paragraph (e) of §60.14 lists exceptions to this definition which will
not be considered "modifications, irrespective of any changes in the
emission rate. These changes include:
1. Routine maintenance, repair, and replacement,
2. An increase in the production rate not requiring a capital
expenditure as defined in §60.2,
3. An increase in the hours of operation,
4. Use of an alternative fuel or raw material if, prior to
proposal of the standard, the existing facility was designed to
accommodate that alternative fuel or raw material,
5. The addition or use of any system or device whose primary
function is the reduction of air pollutants, except when an emission
control system is removed or replaced by a system considered to be
less environmentally beneficial,
5-1
-------
6. The relocation or change in ownership of an existing facility.
As stated in paragraph (b), emission factors, material balances,
continuous monitoring systems, or manual emission tests are to be used
to determine emission rates expressed as kg/hr of pollutant. Paragraph (c)
affirms that the addition of an affected facility to a stationary
source through any mechanism — new construction, modification, or
reconstruction — does not make any other facility within the stationary
source subject to standards of performance. Paragraph (f) provides
for superseding any conflicting provisions. And, (g) stipulates that
compliance be achieved within 180,days of the completion of any modification.
5.1.2 Reconstruction
Under the provisions of §60.15, an existing facility becomes an
affected facility upon reconstruction, irrespective of any change in
emission rate. Reconstruction is the replacement of components of an
existing facility to such an extent that: (1) the fixed capital cost
of the new components exceeds 50 percent of the fixed capital cost
that would be required to construct a comparable entirely new facility,
and (2) it is technologically and economically feasible to meet the
applicable standards of performance. When the replacement of components
of an existing facility meets the cost criterion for reconstruction,
the Administrator of the EPA shall determine whether the replacement
constitutes reconstruction. As stated in §60.15(f), the Administrator's
determination of reconstruction will be based on:
(1) The fixed capital cost of the replacements in comparison to
the fixed capital cost that would be required to construct a
comparable new facility; (2) the estimated life of the facility
after the replacements compared to the life of a comparable
entirely new facility; (3) the extent to which the components
being replaced cause or contribute to the emissions from the
facility; and (4) any economic or technical limitations on compliance
with applicable standards of performance which are inherent in
the proposed replacements.
The purpose of the reconstruction provision is to ensure that an
owner or operator does not perpetuate an existing facility by replacing
all but minor components, support structures, frames, housing, etc.,
rather than totally replacing it in order to avoid being subject to
applicable performance standards. In accordance with §60.5, EPA will,
upon request, determine if an action taken constitutes reconstruction.
5-2
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5.2 APPLICABILITY OF MODIFICATION PROVISIONS TO FCC REGENERATORS
Several changes, either physical or operational, that could be
encountered while expanding or modernizing an existing FCC unit are
presented below along with the anticipated effect on sulfur oxides
emissions.
5.2.1 Maintenance, Repair, and Replacement
Maintenance, repair, and component replacement which are
considered routine for a source category irrespective of any changes
in sulfur oxides emissions are not considered modifications under
§60.14(e)(l). An increase in sulfur oxides emissions is not expected
to occur as a result of normal maintenance or replacement of FCC
regenerator components.
The FCC regenerator usually operates for 2 to 6 years continuously
before maintenance, repair, or replacement of internal components is
12 '
necessary. ' After this time, the unit is shut down and purged so
that the regenerator can be inspected for wear. This procedure is
called a turnaround. During the 2 to 4 week turnaround period, routine
maintenance or repairs may be required due to the erosion of internal
surfaces by catalyst particles or to the build-up of coke deposits on
certain components. Routine maintenance or repair performed during
an FCC unit regenerator turnaround may include inspecting and, if
necessary, repairing the air distribution system, standpipe, slide
valves, plenum chamber, catalyst overflow weir, and regenerator grid
and seals. The regenerator refractory lining is also inspected for
4
wear and patched, if necessary. Routine maintenance and repair of
the FCC regenerator would normally be expected to decrease or have no
effect on sulfur oxides emissions.
FCC unit regenerator internal components may require periodic
replacement due to excessive erosion or corrosion of internal surfaces.
For example, the regenerator internal cyclones may be replaced after a
3
typical service life of 10 years. If the cyclones are replaced with
equivalent cyclones, particulate emissions usually decrease due to the
increased catalyst capture efficiency of the new cyclones. However,
the new cyclones are not expected to affect sulfur oxides emissions
from the FCC unit regenerator. Cyclone replacement may contribute to
the cost of reconstruction. This is discussed in Section 5.3.
5-3
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5.2.2 Increasing Capacity
An increase in capacity is not considered a modification under
§60.14 if the increase can be accomplished without incurring a capital
expenditure on the existing facility. A capital expenditure is defined
as "an expenditure for a physical or operational change to an existing
facility which exceeds the product of the applicable 'annual asset
guideline repair allowance percentage1 specified in the latest edition
of Internal Revenue Service Publication 534 and the existing facility's
basis, as defined by Section 1012 of the Internal Revenue Code" (40 CFR,
§60.2).
A refiner may decide to increase the capacity of an existing FCC
unit to improve the yield pattern of certain products, meet product
demands, and increase profitability. FCC unit capacity may be increased
by increasing the regenerator combustion air flow rate, increasing the
regenerator internal pressure, or through oxygen enrichment of the
regenerator combustion air. These changes may be achieved without a
capital expenditure as defined by Section 1012 of the Internal Revenue
Code.
In many cases FCC unit capacity is determined by the quantity of
coke which can be burned off within the regenerator. A common technique
employed by a refiner to increase FCC unit capacity is to install an
additional blower to the unit's air distribution system. The additional
blower increases the quantity of combustion air which moves through
the catalyst bed and increases catalyst coke burn-off rate. This
allows more catalyst to be fed to the riser reactor and increases the
quantity of fresh feed that can be processed. An alternate means of
increasing regenerator coke burn-off capacity is through oxygen enrichment
of the regenerator combustion air. The increased coke burn-off rate
may result in an increase in sulfur oxides emissions. The increased
air flow rate requires increased gas handling capacity in the regenerator
cyclones and more downstream flue gas handling equipment, such as
coolers and precipitators.
FCC unit fresh feed capacity may be increased by reducing the
coke make rate especially when the unit is air blower limited, or by
reducing the amount of recycle oils processed in the unit. The coke
make rate can be reduced by processing high quality feedstocks or by
5-4
-------
hydrotreating. Catalyst selection, improved regeneration, and decreased
conversion all reduce the coke make rate. Recycle may be reduced or
eliminated through catalyst selection, increased conversion, or through
alternate use of recycle oils instead of reinjection into the FCC
unit. These changes would allow the refiner to increase FCC unit
fresh feed capacity.
FCC unit capacity can also be increased by increasing the regenerator
internal pressure. The results of the increased internal pressure are
similar to that of increasing regenerator combustion air flow rate.
The increased regenerator internal pressure allows more combustion air
to come in contact with the catalyst and increases the catalyst coke
burn-off rate. The increased coke burn-off rate may result in an
increase in sulfur oxides emissions. Regenerator internal pressure is
increased by modifying the compression equipment through rotor or
blade replacement, or through addition of a booster compressor upstream
or downstream from the existing compressor. In addition, a refiner
may install thin internal liners in the regenerator to reduce the
metal temperature of the shell.
5.2.3 Increase in Hours of Operation
An increase in emissions from an existing facility due to an
increase in the hours of operation is not considered a modification
under §60.14(e)(3). FCC units operate, on average, 24 hours per day,
365 days per year. An exception to this is when the unit is shut down
for maintenance. It is unlikely that refiners would alter the hours
of operation of their FCC units.
5.2.4 Change in FCC Feedstock Quality
Changes in FCC feedstock quality, such as a change to higher
sulfur content feeds, a change to a higher contaminant metals content
feed, or an increase in recycle rate, may result in an increase in
sulfur oxides emissions from the FCC unit regenerator. Changes in the
crude supply or product demand may necessitate a change in feedstock
quality. A change to a higher sulfur content feed may not only increase
regenerator sulfur oxides emissions, but also result in corrosion of
certain regenerator internal components due to the higher sulfur
levels present in the gases contained within the regenerator. A
5-5
-------
change In sulfur oxides emissions which results from a change in
feedstock quality is not considered a modification provided the existing
facility was designed to accommodate that feedstock.
For a specific feedstock and unit throughput, hydrodesulfurization
will decrease the sulfur oxides emissions from the FCC unit regenerator.
In general, HDS can remove the sulfur from high sulfur feeds and
decrease sulfur oxides emissions from the regenerator. However, HDS
can also increase the yields of certain desirable products and improve
O
overall feed cracking characteristics. This may enable a refiner to
increase unit capacity or process higher sulfur feeds and thus increase
regenerator sulfur oxides emissions.
5.2.5 Addition, Removal, or Disabling of a System to Control Air
Pollutants
The addition or use of any system or device whose primary function
is to reduce air pollutants, except the replacement of such a system
or device by a less efficient one, is not considered a modification
under §60.14.
The intentional removal or disabling of any emission control
component of an existing FCC unit regenerator which would cause an
increase in sulfur oxides emissions would be a modification.
5.3 APPLICABILITY OF RECONSTRUCTION PROVISIONS TO FCC REGENERATORS
FCC units operate for long periods of time without major servicing.
Many units installed in the early 1940's are still operational. There
are only a few expansions or modernizations to the FCC regenerator
which may contribute to the cost of reconstruction.
5.3.1 Conversion to High Temperature Regeneration
An action that might be considered as a reconstruction of the FCC
unit regenerator is the conversion to high temperature regeneration
(HTR). HTR revamping of an FCC regenerator generally requires the
replacement of cyclones, the plenum chamber, cyclone diplegs, the
regenerator grid and seals, and the catalyst overflow weir. These
components must be constructed from stainless steel rather than carbon
steel in order to withstand the higher temperatures. It is possible
that an HTR revamp may exceed 50 percent of the capital cost to construct
an entirely new FCC unit regenerator.
5-6
-------
5.3.2 Addition or Replacement of Regenerator Combustion Air Blower,
Cyclones, or Other Regenerator Internal Components
Although the addition or replacement of regenerator combustion
air blowers, internal cyclones, or other internal components was dis-
cussed in Sections 5.2.1 and 5.2.2 under Modification, this activity
may contribute to the reconstruction of an FCC unit regenerator. The
cost of a major turnaround may exceed 50 percent of the capital cost
of a new FCC regenerator.
5-7
-------
5.4 REFERENCES
1 Fluid Catalytic Cracking with Molecular Sieve Catalysts. Petro/
Chem Engineering. 41:12. May 1969. Docket Reference Number
II-I-2.*
2. Luckenback, E.C. How to Update A Catalytic Cracking Unit.
Chemical Engineering Progress. 75^:56. February 1979. Docket
Reference Number II-1-49.*
3. Manda, M.L., Pacific Environmental Services, Inc. Trip Report:
Conoco, Incorporated, Ponca City, Oklahoma. August 14, 1980.
Docket Reference Number II-B-12.*
4. Manda, M.L., Pacific Environmental Services, Inc. Trip Report:
Oklahoma Refining Company. Oklahoma City, Oklahoma. August 13,
1980. Docket Reference Number II-B-11.*
5. Macerato, F. and S. Anderson. 03 Enrichment Can Step Up FCC
Output. Oil and Gas Journal. 79(9):101-106. March 2> 1981.
Docket Reference Number II-I-88T*"
6. Reference 2, p. 58. Docket Reference Number II-I-49.*
7. Ritter, R.E., J.J. Blazek, and D.N. Wallace. Hydrotreating FCC
Feed Could be Profitable. Oil and Gas Journal. 72(41):99-100.
October 14, 1974. Docket Reference Number II-I-1T7*
8. Screening Study to Determine Need for SOX and Hydrocarbon NSPS
for FCC Regenerators. U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-450/3-77-046.
August 1976. p. 54. Docket Reference Number II-A-2.*
9. Reference 8, p. 21. Docket Reference Number II-A-2.*
*References can be located in Docket Number A-79-09 at the U.S.
Environmental Protection Agency's Central Docket Section, West
Tower Lobby, Gallery 1, Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
5-8
-------
6.0 MODEL PLANTS AND REGULATORY ALTERNATIVES
The purpose of this chapter is to define model plants and identify
regulatory alternatives. Model plants are parametric descriptions of
types of plants that, in EPA's judgment, will be constructed, modified,
or reconstructed. The model plant parameters are used as a basis for
estimating the environmental, economic, and energy impacts associated
with the application of regulatory alternatives to the model plants.
6.1 MODEL PLANTS
Each FCC unit and, hence, each regenerator is unique from a
technical standpoint. FCC unit types and sizes, flow rates, feedstock
quality, regeneration mode, recycle rates, air flow rates, and emission
rates vary from one unit to another. For this reason, no single model
plant can adequately characterize the FCC units. Accordingly, several
model FCC units were specified in terms of some appropriate parameters
to span the range of anticipated FCC unit sizes, feedstock quality,
flow rates, and emissions.
Table 6-1 lists model FCC unit parameters used in the environmental,
energy, cost, and economic analyses of the regulatory alternatives. A
total of six model FCC units have been selected. Model FCC units are
based primarily on FCC unit capacity and on the sulfur content of the
regenerator flue gas. Two different flue gas flow rates and three
different flue gas sulfur oxides concentrations were chosen to represent
typical ranges of processing capacity and feed sulfur.
The selection of model FCC unit parameters is based on published
literature, information obtained during plant visits, and calculations.
Model unit capacities are identified on the basis of current and
historical FCC construction, as described in Appendix E. The two
3 3
selected capacities, 2,500 m /sd and 8,000 m /sd, are representative of
FCC units which are presently being constructed or which have been
6-1
-------
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6-2
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constructed in the last 10 years * Recycle rates are based on the
current U.S. average FCC recycle capacity of approximately 15 percent
of the fresh feed.
Air flow rates and emissions are calculated by using the methods
described in Chapter 3. Coke .yield is assumed to be 5 weight percent
of the fresh feed. Coke sulfur levels are identified by specifying
the FCC feed sulfur content and by using the correlation between feed
sulfur and coke sulfur (Figure 3-5). This correlation and thus model
FCC unit sulfur oxides emissions are representative of actual FCC unit
emissions for many common FCC feedstocks. Feed sulfur levels of 0.3,
1.5, and 3.5 weight percent are representative of low, intermediate,
and high sulfur feeds, respectively.
The regenerator flue gas excess oxygen is assumed to be two
volume percent and the carbon monoxide concentration is assumed to be
500 vppm. These values are consistent with current technologies for
meeting the carbon monoxide emission requirements. Excluding the
sulfur oxides emissions which would result from FCC units with carbon
monoxide combustion furnaces firing sulfur-containing fuel, the three
feeds yield regenerator flue gas sulfur oxides concentrations of
13 kg/1,000 kg coke burn-off, 46 kg/1,000 kg coke burn-off, and
88 kg/1,000 kg coke burn-off. These correspond to regenerator flue
gas sulfur oxides concentrations of 400 vppm, 1,400 vppm, and 2,700 vppm,
respectively. These emissions are calculated as sulfur dioxide and
are dependent only on feed sulfur content. Changes in coke yield from
4.0 to 6.5 and greater weight percent of fresh feed do not result in
significant variations in sulfur oxides emissions when reported as
kg/1,000 kg coke burn-off or as vppm. Thus, sulfur oxides emissions
reported as kg/1,000 kg coke burn-off or in vppm are independent of
the coke yield.
Emissions of other pollutants including cyanides, ammonia, and
nitrogen oxides are discussed in Chapter 3. Since these emissions are
a minor portion of the total FCC regenerator emissions, they are not
specified as part of the model unit emissions.
6.2 REGULATORY ALTERNATIVES
Regulatory alternatives are possible courses of action that could
be taken to reduce emissions from a source. In this case, regulatory
6-3
-------
alternatives identify sulfur oxides emission levels which FCC regenerators
could achieve by using demonstrated control technologies. As discussed
in Chapter 4, FCC sulfur oxides emissions may be reduced by using flue
gas desulfurization (FGD) or sulfur oxides reduction catalysts. These
control technologies form the bases for the emission levels defined by
the regulatory alternatives. Hydrodesulfurization is a process used
by refiners to improve product quality and yields. Due to the expense
of hydrodesulfurization, it is expected that refiners will install
these process units primarily for yield and quality improvements
rather than sulfur oxides control. Therefore, hydrodesulfurization is
not considered as a control technology for this analysis.
To assess the environmental, energy, and economic impacts of
using FGD or sulfur oxides reduction catalysts to meet the regulatory
alternatives, the affects of these control technologies on the FCC
unit and its operation must be known. The impacts of using FGD are
easily quantified due to the large body of literature on this subject.
Also, sodium-based FGD systems have been installed on FCC regenerator
flue gas streams, and they do not impact unit operations or product yields.
Sulfur oxides reduction catalysts are an emerging technology
which have not been used in long-term commercial operations. Their
effects on product yield, sulfur plant operation, and emissions have
not been completely determined. Impact analyses for this control
technology may thus contain significant uncertainties.
To reduce the uncertainty involved in calculating the impacts of
each model plant and regulatory alternative combination, the impacts
will be evaluated based on the use of sodium-based FGD systems alone
to meet the regulatory alternatives. Although the emission levels for
the regulatory alternatives are based on the performance of sulfur
oxides reduction catalysts and-flue gas desulfurization, impacts are
evaluated by assuming that the FGD system reduces model plant sulfur
oxides emissions to the levels defined by the regulatory alternatives.
These levels of scrubbing represent the amount by which model plant
sulfur oxides emissions must be reduced to meet each regulatory
alternative.
Four regulatory alternatives have been selected. These are
illustrated graphically in Figure 6-1. Each regulatory alternative,
6-4
-------
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6-5
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its technological basis, and level of scrubbing is discussed in the
following sections.
6.2.1 Regulatory Alternative I - The Baseline Level
Baseline control is defined as the level of emission reduction
currently achieved by an industry and is typically dictated by State
or local regulations. As discussed in Chapter 3, the baseline level
represents the level of control required for existing FCC units to be
in compliance with most State and local sulfur oxides regulations.
The baseline level (Alternative I) is illustrated in Figure 6-1.
Baseline sulfur oxides emissions range from 13 to 88 kg/1,000 kg coke
burn-off (400 to 2,700 vppm) for commonly used FCC feedstocks of 0.3
to 3.5 weight percent sulfur, respectively.
6.2.2 Regulatory Alternative II
Regulatory Alternative II would require that sulfur oxides
emissions from FCC units be limited to 13 kg sulfur oxides/1,000 kg
coke burn-off (400 vppm). The equivalent levels of scrubbing required
to meet Regulatory Alternative II are: 85 percent for the 3.5 weight
percent sulfur feedstock model units to reduce flue gas sulfur oxides
content from 88 to 13 kg/1,000 kg coke burn-off (2,700 to 400 vppm),
71 percent for the 1.5 weight percent sulfur feedstock model units to
reduce flue gas sulfur oxides content from 46 to 13 kg/1,000 kg coke
burn-off (1,400 to 400 vppm), and little or no scrubbing for the
0.3 weight percent sulfur feedstock model units whose baseline sulfur
oxide emissions are 13 kg/1,000 kg coke burn-^off (400 vppm). The
economic, environmental, and energy impacts for Regulatory Alternative II
will be determined based on these levels of scrubbing.
The basis for this alternative is to allow refiners an opportunity
to use sulfur oxides reduction catalysts to meet this regulatory
alternative. Depending upon the sulfur levels of FCC unit feeds
charged to their units, most refiners will be able to utilize the
sulfur oxides reduction catalyst technology, while a few may use flue
'gas desulfurization. The emerging sulfur oxides reduction catalyst
technology can be used to meet Regulatory Alternative II when feeds up
to approximately 2.3 weight percent sulfur are charged to the FCC
unit.
6-6
-------
6.2.3 Regulatory Alternative III
Regulatory Alternative III would require that sulfur oxides
emissions from FCC units be limited to 9.8 kg sulfur oxides/1,000 kg
coke burn-off (300 vppm). The levels of scrubbing required to meet
Regulatory Alternative III are: 89 percent for the 3.5 weight percent
sulfur feedstock model units to reduce flue gas sulfur oxides content
from 88 to 9.8 kg/1,000 kg coke burn-off (2,700 to 300 vppm), 79 percent
for the 1.5 weight percent sulfur feedstock model units to reduce flue
gas sulfur oxides content from 46 to 9.8 kg/1,000 kg coke burn-off
(1,400 to 300 vppm), and 25 percent for the 0.3 weight percent sulfur
model units to reduce flue gas sulfur oxides emissions from 13.0 to
9.8 kg/1,000 kg coke burn-off (400 to 300 vppm). The energy, economic,
and environmental impacts of Regulatory Alternative III will .be determined
based on these levels of scrubbing.
As with Alternative II, the basis for this alternative is to
allow refiners an opportunity to use sulfur oxides reduction catalysts
to meet this regulatory alternative. Depending on the sulfur levels
of FCC unit feeds charged to their units, most refiners are expected
to utilize the sulfur oxides reduction catalyst technology, while a
few may use flue gas desulfurization. The emerging sulfur oxides
reduction catalyst technology can be used to meet this alternative
when feeds up to about 1.7 weight percent sulfur are charged to the
FCC unit.
6.2.4 Regulatory Alternative .IV
Regulatory Alternative IV would require that sulfur oxides emissions
from FCC units be limited to 6.5 kg sulfur oxides/1,000 kg coke burn-off
(200 vppm). The levels of scrubbing required to meet Regulatory
Alternative IV are: 93 percent for the 3.5 weight percent sulfur
feedstock model units to reduce flue gas sulfur oxides emissions from
88 to 6.5 kg/1,000 kg coke burn-off (2,700 to 200 vppm), 86 percent
for the 1.5 weight percent sulfur feedstock model units to reduce flue
gas sulfur oxides emissions from 46 to 6.5 kg/1,000 kg coke burn-off
(1,400 to 200 vppm), and 50 percent for the 0.3 weight percent sulfur
feedstock model units to reduce sulfur oxides emissions from 13 to
6.5 kg/1,000 kg coke burn-off (400 to 200 vppm). The energy, economic,
and environmental impacts of Regulatory Alternative IV are based on
these levels of scrubbing.
6-7
-------
This alternative is based on the use of sodium-based flue gas
scrubbing. This alternative can be met on a continuous basis, over
the entire range of expected feed sulfur content, by a properly operating
and maintained flue gas scrubber. It is expected that refiners whose
FCC units are processing feeds containing approximately 1.0 weight
percent sulfur or less may be able to use sulfur oxides reduction
catalysts to meet Regulatory Alternative IV.
Table 6-2 presents a summary of the model units, the regulatory
alternatives, and the equivalent scrubbing levels for each regulatory
alternative.
6-8
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6.3 REFERENCES
1. Cantrell, A. Annual Refining Survey. Oil and Gas Journal.
78(12):130-157. March 24, 1980. Docket Reference Number II-I-71.*
*References can be located in Docket Number A-79-09 at the U.S.
Environmental Protection Agency's Central Docket Section,
West Tower Lobby, Gallery 1, Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
6-10
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7.0 ENVIRONMENTAL IMPACTS
7.1 INTRODUCTION
Sodium-based scrubbing is the demonstrated control technology
applied to FCC units, and it is expected that this would be the most •
widely applicable control system upon implementation of a regulatory
alternative. As such, the environmental impacts analyses are focused
upon sodium-based scrubbing. However, refiners may opt to utilize
alternative control technologies as discussed in Chapter 4.0. These
other control technologies may be an attractive alternative to sodium-based
scrubbing particularly for FCC units at refineries where water avail-
ability or wastewater discharges are restricted. In Section 7.4, the
environmental impacts for other control technologies are discussed and
compared to sodium-based scrubbing. The environmental impacts for all
of the other control technologies are based on the same parameters as
the sodium-based scrubber systems. Table 6-2 lists the sulfur oxides
emissions levels for the regulatory alternatives which serve as the
basis for the analyses.
The focus of this analysis is to determine the incremental increase
or decrease over the baseline control level in air pollution, water
pollution, solid waste, and energy impacts of the regulatory alternatives.
The baseline control level reflects existing levels of control of FCC
unit sulfur oxides emissions as required by State and local regulations.
This level is represented by Regulatory Alternative I.
This chapter first addresses the air pollution impacts of implementing
each of the regulatory alternatives. The sulfur oxides emission
reductions are independent of the control technology applied, and,
therefore, sodium-based scrubbing as well as other control technologies
would result in the same reductions. Water pollution, solid waste,
and energy impacts for sodium-based scrubbing are addressed in
7-1
-------
Sections 7.3.1, 7.3.2, and 7.3.3, respectively. The environmental
impacts associated with other control technologies are discussed in
Section 7.4.
7.2 AIR POLLUTION IMPACTS OF REGULATORY ALTERNATIVES
The following discussion on air pollution impacts pertains to the
application of each control technology discussed in Chapter 4.0. In
addition to sodium-based scrubbing, these controls include dual alkali,
Wellman-Lord, citrate, spray drying, and use of sulfur oxides reduction
catalysts.
7.2.1 Primary Air Pollution Impacts
Emissions from model FCC units include particulate matter, sulfur
oxides, and carbon monoxide. Since particulate and carbon monoxide
emissions are already controlled by new source performance standards
(NSPS), only sulfur oxides emissions are discussed here.
Annual sulfur oxides emissions and emission reductions by regulatory
alternative for the model units are presented in Table 7-1. Annual
sulfur oxides emissions from model units range from 260 to 11,100 megagrams
per year; emission reductions from the baseline level range from
zero to 93 percent depending on regulatory alternative and model unit.
7.2.2 Secondary Air Pollution Impact
Secondary air pollutants which result from the use of pollution
control equipment are not usually associated with an uncontrolled
facility. No secondary air pollution problems are anticipated due to
the application of sodium-based or other scrubbers to FCC unit regenerators.
In some instances, nitrogen oxides (NO ) emissions from FCC units
V\
increased when operated with sulfur oxides reduction catalysts in
place. Nitrogen oxides emission data from FCC units operating with
and without the sulfur oxides reduction catalysts were obtained in
order to evaluate NO emissions increases due to the use of the catalysts.
/\
An analysis of these data showed that NO emissions increases resulting
A
from use of these catalysts are not significant. However, CO promoted
conventional regeneration FCC units appear to have high NOX emissions
without sulfur oxides reduction catalysts and even higher NO emissions
J\
with sulfur oxides reduction catalysts. The significance of this
increase is unknown due to the limited number of SO reduction catalyst
1
tests performed.
7-2
-------
Table 7-1. ANNUAL SULFUR OXIDES. EMISSIONS AND EMISSION REDUCTIONS
FOR EACH REGULATORY ALTERNATIVE3
Regul atory
Alternative
I
(Basel ine)
II
III
IV
Model
Unit
Size
(m3/sd)
2,500
8,000
2,500
8,000
2,500
8,000
2,500
8,000
Fresh
Feed
Sulfur
Content
(wt. %)
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
0.3
1.5
3.5
Annual
Sulfur
Oxides
Emissions
(Mg/yr)
520
1,860
3,480
1,650
5,950
11,100
520
520
520
1,650
1,650
1,650
390
390
390
1,240
1,240
1,240
260
260
260
830
830
830
Annual
Reductions in
Sulfur Oxides
Emissions from
Baseline
(Mg/yr)
-
-
-
-
-
0
1,340
2,970
0
4,290
9,500
130
1,470
3,100
410
4, 710
9,910
260
1,600
3,230
830
5,120
10,300
Percent
Reduction
from
Baseline
0
0
0
0
0
0
0
71
85
0
71
85
25
79
89
25
79
89
50
86
93
50
86
93
aAssumes that the FCC unit operates 357 days per year, 24 hours per day.
Sulfur oxides emissions calculated on the basis of 400 vppm for feed sulfur
content of 0.3 weight percent, 1,400 vppm for feed sulfur content of
1.5 weight percent, and 2,700 vppm for feed sulfur content of 3.5 weight
percent.
Total sulfur oxides calculated as SO,,.
7-3
-------
7.2.3 Dispersion Mod eli ng
Mathematical modeling of the ambient air is used to predict the
concentration of sulfur oxides in the atmosphere at various distances
from model FCC units. This analysis of pollutant dispersion enables
assessment of the effect of each regulatory alternative on air quality
near the FCC unit. All modeling was conducted using the CRSTER model.
Since FCC units are likely to be located in urban/refinery areas
characterized by considerable surface roughness and heating from
combustion sources, the urban mode of the model was used. Emission
concentrations were examined at distances from 0.1 to 10 km downwind
of the FCC unit to determine the maximum dispersion impacts. Other
input variables used in the model appear in Table 7-2. For the baseline
cases (Regulatory Alternative I and Regulatory Alternative II for
units charging 0.3 weight percent sulfur feedstocks), the model FCC
parameters are based on the use of electrostatic precipitators (required
for particulate control), whereas all other cases use sodium-based
28
scrubbing. Dispersion modeling results are shown in Table 7-3.
The results of the dispersion modeling indicate that the application
of scrubbers to FCC units may increase ground level concentrations of
sulfur oxides. Scrubber stack gases are cooler and have a lower plume
rise than the baseline case and therefore, increased ground level
concentration of sulfur oxides. From Table 7-3, 1- and 3-hour maximum
ground level sulfur oxides concentrations are higher for Alternative III
than Alternative I (the baseline case) for an FCC unit processing a
0.3 weight percent sulfur feedstock. The increase in ground level
sulfur oxides concentrations due to scrubbers may be mitigated through
use of greater stack heights or exit velocities than those specified
for the model, plants in Table 7-2.
Prevention of significant deterioration (PSD) increments are
presented in Table 7-3 to allow comparisons with the dispersion modeling
results. Based on these results, PSD regulations would preclude the
construction of new FCC units in Class I (pristine) air quality areas
regardless of regulatory alternative. Modeling, results show that FCC
units meeting Alternative II, III, or IV and all but those FCC units
processing high sulfur feeds under Alternative I could operate in PSD
7-4
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Class II areas. FCC units could operate in PSD Class III areas
regardless of regulatory alternative.
Sulfur oxides emissions under all regulatory alternatives are in
compliance with national ambient air quality standards (NAAQS).
Primary NAAQS limit annual concentrations to 80 micrograms/m (arithmetic
mean), and secondary NAAQS to 1,300 micrograms/m maximum for any
3-hour period. The modeled FCC unit maximum ground level sulfur
oxides concentration.is realized by an 8,000 m /sd model unit charging
a 3.5 weight percent sulfur feedstock. In this worst case, the modeled
3-hour and annual maximum sulfur oxides emissions are 14 mg/m at 3 km
2
downwind of the FCC unit and 543 mg/m 1 km downwind of the FCC unit,
respectively.
7.2.4 Five-Year Impacts of Regulatory Alternatives
The projected number of affected new and modified/reconstructed
model FCC units are presented by year in Tables 7-4 and 7-5. From
historical FCC growth data presented in Appendix E, it is expected
that 10 new FCC units will be constructed in this period. As shown in
Table 7-4, units built in 1986 will probably be designed to process
higher sulfur feeds than those built in 1982.
The available growth data, summarized in Appendix E, also indicate
that up to 70 different units may increase throughput and emissions in
a 5-year period. Many of these throughput and emission increases,
however, occur as a result of normal unit turnarounds, routine maintenance,
changes in feed availability, unit optimization, or construction not
2 8
involving the FCC unit. The actual number of units which modify or
reconstruct thus may vary from only a few to 70. For the purposes of
this analysis, it is estimated that 10 percent of the units which may
increase capacity, 7 units, would be modified or reconstructed between
1982 and 1987.9 Table 7-5 describes the projected distribution of
modified/reconstructed facilities that is used in the impact analysis.
These growth projections are used to estimate future (1982 through
1986) impacts of the regulatory alternatives on sulfur oxides emissions.
Future impacts are determined by applying the model unit emission
rates in Table 7-1 to the projected distribution of affected facilities
from Tables 7-4 and 7-5. The resulting annual impacts are presented
by regulatory alternative in Table 7-6.
7-7
-------
Table 7-4. PROJECTED NEW FCC UNIT CONSTRUCTION SCHEDULE'
Year
1982
1983
1984
1985
1986
FCC
New Unit
Fresh Feed
Capacity
(m3/sd)
2,500
8,000
2,500
8,000
2,500
8,000
2,500
8,000
2,500
8,000
Sulfur
Content
(wt %)
0.3
0.3
1*5
J.5
1.5
1.5
1.5
1.5
3,5
3.5
Uncontrolled
Flue Gas
Sulfur Oxides.
Concentration
(vppm)
400
400
1,400
1,400
1,400
U400
I44oo
1*400
2, 700
2 -,700
FCC Unit growth projections are discussed in Appendix E.
DTota1 sulfur oxides reported as SO,,*
Table 7-5. PROJECTED FCC UNIT MODlFiCATION/RECONSTRUCTiON SCHEDULE*
Year
1982
1983
1984
1985
1986
Mod i f i ed/Recons tructed
FCC Unit Fresh
Feed Capacity
(m3/sd)
8,000,.
2,500^
8,000C
8,000
2,500
8,000
8,000
Sul fur
Content
(wt. %)
1*5
1.5
1.5
1.5
1.5
1.5
3.5
Uncontrolled Flue
Gas Sulfur Oxides
-K
Concentration
{Vppm)
lk 400
1,400
1,400
1,400
1;,400
1* 400
2,700
aFCC unit growth projections are discussed in Appendix E.
Total sulfur oxides reported as S0£.
cThis modified/reconstructed FCC unit is assumed to have a carbon
monoxide boiler.
7-8
-------
Table 7-6. ANNUAL IMPACTS OF REGULATORY ALTERNATIVES ON SULFUR
OXIDES EMISSIONS FROM NEW AND MODIFIED/RECONSTRUCTED
FCC UNITS3
Regulatory
Alternative
I
(Baseline)
II
III
IV
Year
1982
1983
1984
1985
1986
1982
1983
1984
1985
1986
1982
1983
1984
1985
1986
1982
1983
1984
1985
1986
Number of
New
and Modified/
Reconstructed
Units
3
7
10
14
17
3
7 .
10
14
17
3 .
7
10
14
17
3
7
10
14
17
Annual
Sulfur Oxides
Emissions
(Mg/yr)
8, 120
23,700
37,500
53,100
78,800
3,820
8, 160
12,000
16,300
20,100
2,870
6, 130
9,000
12,300
15,100
1,920
4,100
6,020
8,200
10,100
Annual
Sulfur Oxides
Emissions
Reduction
(Mg/yr)
_
-
,
• •
mm
4,300
15,500
25,500
36,800
58,700
5,250
17,600
28,500
40,900
63,800
6,200
19,600
31,500
44,900
68,700
aTotal sulfur oxides reported as
7-9
-------
In the fifth year, total sulfur oxides emission reductions for
new and modified/reconstructed FCC units range from zero for Regulatory
Alternative I to 68,700 Mg for Regulatory Alternative IV.
7.3 OTHER ENVIRONMENTAL IMPACTS OF THE REGULATORY ALTERNATIVES
7.3.1 Water Pollution Impacts of Sodium-based Scrubbers
7.3.1.1 Quality and Quantity of Liquid Waste Discharges. The application
of sodium-based scrubbers for control of sulfur oxides results in a
wastewater discharge which must be treated and disposed. The scrubber
effluent contains catalyst fines as suspended particulate and sodium
salts (sodium sulfite, sodium suifate, sodium bisulfite) as dissolved
solids. Presently, the scrubber effluent from systems in operation on
FCC regenerators is treated to adjust pH" imbalances by alkali addition.
Oxidation a*Hd sittiing tanks are Used to reduce chemical oxygen demand
and solids ctihterit b'f the waste stream prior to discharge. '
The scrubber system controls Both particu1at£ Hh'd sulfur oxides
emissions. Except for alkali cbhiulptiorU scrubbed bperatidh and thfe
VoiUitte Of wasteWater discharged Will ^eiitain approximately constant to
maintain particulate removal efficiencies. Therefore, model unit
throughput rather than sulfur content of the flue gas or regulatory
alternative affects the volume of scrubB'er effluent to be disposed.
The quantity of wastewater discharged from sodium-based scrubbers
is about 0.07 m3/m3 fresh feed.10 The scrubber effluent, treated as
described previously! is assumed to contain 5 weight percent dissolved
solids as reported for sodium-based scrubbers in industrial boiler
applications. For FCC unit applications, the percentage of dissolved
solids in the scrubber effluent is reported by the vendor to be proportional
to the sulfur content of the flue gas. One refiner reports that the
3
treated purge stream contains 40 g/m suspended solids, and chemical
oxygen demand of 40 g/m . However, the vendor claims that the purge
treatment is designed to reduce the total dissolved solids and chemical
3 3 12
oxygen demand of the purge stream to 100 g/m and 50 g/m , respectively.
A description of wastewater discharges from the model units is developed
based on the reported refinery effluent discharges.
Discharges from the two model unit sizes are presented in Table 7-7.
For these model units, annual scrubber discharges to receiving waters
7-10
-------
Table 7-7. AQUEOUS DISCHARGES FROM FCC UNIT
SODIUM-BASED SCRUBBER SYSTEMS
FCC Fresh
Feed Capacity
(m3/sd)
2,500
8,000
Wastewater
Discharge3
(m3/yr)
62,500
200,000
Suspended
Solidsb
(Mg/yr)
2.5
8.0
Dissolved
Solids0
(Mg/yr)
3,100
10,000
Chemical
Oxygen
Demand
(Mg/yr)
2.5
8.0
aAssumes a linear relationship between discharge and flue gas flow
rates. Calculated on the basis of 0.07 m of wastewater discharge
per m3 of fresh feed, 357 days of operation per year. Reference 10.
bReference 10.
Reference 11. Dissolved solids represent approximately 5 weight
percent of the wastewater discharge. To calculate mass discharge of
dissolved solids, the density of the wastewater is assumed to be
1 Mg/m3.
7-11
-------
range from 62,500 to 200,000 m /yr, suspended solids discharges range
from 2.5 to 8.0 Mg/yr, dissolved solids discharges range from 3,100 to
10,000 Mg/yr, and chemical oxygen demand ranges from 2.5 to 8.0 Mg/yr
3
for the 2,500 and 8,000 m /sd model units, respectively.
7.3.1.2 Disposal Techniques. The five refineries with sodium-based
scrubbers in operation for FCC unit sulfur oxides control are in or
near coastal locations. The scrubber effluent is treated to reduce
chemical oxygen demand, suspended solids content, and to adjust pH as
described previously. The effluent is then discharged to large rivers
or coastal waters. The dissolved solids content of the treated scrubber
effluent is approximately 5 percent. Because of this* discharge of
the treated wastes to surface water may be restricted, especially in
inland locationsj due to refinery discharge permits. However, discharge
of scrubber effluents to surface water may still be possible. If a
sufficient Volume of wastewater from elsewhere in the refinery is
available and of low dissolved solids content, the dissolved solids
content of the scrubber wastewater may be diluted to within permit
limitations. Refinery effluent flows range from 1.2 to 6.0 m of
3 13
wastewater/m crude charge.
Alternatives to discharge of the treated wastes to surface water
include discharge to municipal wastewater treatment facilities or
evaporation ponds. These are popular alternatives for industrial
boiler applications. Other alternatives include deep well injection,
flash evaporation, or reverse osmosis. These latter alternatives are
not widely Used in boiler applications at present and, therefore,
may not gain acceptance for FCC unit applications.
7.3.1.3 Applicable Regulations. The applicable regulations
relative to scrubber wastewater discharges are dependent upon the
disposal technique being used. Discharges to receiving streams,
territorial seas, or oceans must satisfy the requirements of National
Pollution Discharge Elimination System (NPDES) and Ocean Discharge
Criteria under the Water Pollution Control Act. Discharges to publicly
owned treatment works (POTW) will have to satisfy pretreatment requirements
for the POTW's. When effluents are being disposed of by deep well
injection or evaporation pond, the requirements of the Safe Drinking
7-12
-------
Water Act, the Underground Injection Control Program, and State and
local pollution control agenices must be met. These regulations are
specific to each receiving stream, POTW, and to the groundwater use
and geology of each location in question. State water pollutant
regulations may, in some cases, be more stringent than Federal water
pollution regulations.
7.3.2 Solid Haste Impacts of Sodium-based Scrubbers
Sodium-based scrubbers applied to FCC units control emissions of
sulfur oxides and particulate matter (catalyst fines). Control of
particulate emissions from new FCC regenerators is required by an
existing NSPS. Particulate matter is removed from the flue gas by the
scrubber and collected in the scrubber wastewater treatment unit as a
sludge. Small amounts of polyelectrolyte (from 1.5 to 4.5 kg/day for
the model units) are added to the scrubber effluent during wastewater
14
treatment to enhance removal of suspended solids. • Sulfur oxides
emissions control does not result in any incremental changes in the
amount (dry weight) of solid wastes produced over that resulting from
the particulate NSPS.
7.3.3 Energy Impact of Sodium-based Scrubbers
The overall energy impact of sodium-based scrubbing systems on
FCC units is negligible. However, the scrubber system would add to
the electrical requirement of an FCC unit. Table 7-8 presents the
annual electrical requirements for scrubber systems and for FCC
units.14"17 The scrubber system increases the total electrical
consumption for FCC units using a high energy venturi by about 2 percent
and approximately 20 percent for units using a jet ejector venturi
scrubber. Modified/reconstructed FCC units which employ a carbon
monoxide combustion furnace regeneration will require a jet ejector
venturi. The jet ejectors are required to induce a draft through the
venturi as sufficient line pressure is not available through the
carbon monoxide boiler, which is unpressurized. Additional energy is
thus consumed by the pumps which spray the scrubbing liquor through
the jet ejectors as discussed in Section 4.2.2.2. The high energy
Venturis do not have this requirement.
7-13
-------
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-------
In assessing nationwide energy impacts for the sodium-based
scrubber system, it is expected that all new units and five of the
seven projected modified/reconstructed units will utilize a high
energy venturi. It is anticipated that all new units will use high
temperature regeneration and that conventional promoted regeneration
or high temperature regeneration will be used in the case of five
modified/reconstructed units. Two modified/reconstructed units are
expected to use conventional-unpromoted regeneration, and hence jet
2
ejector Venturis. These units are assumed to be one 2,500 m /sd unit
3
and one 8,000 m /sd unit charging a 1.5 weight percent sulfur feed as
noted in Table 7-5.
A comparison of the scrubbing system total energy requirement to
the FCC unit's energy requirement is presented in Table 7-9. The
scrubbing system energy requirement for units with the high energy
venturi and the jet ejector venturi is less than 1 and 2 percent of
that for the total FCC unit, respectively. From Table 7-10, nationwide
fifth-year energy requirements are approximately 24,000 TJ under
Regulatory Alternative II and 26,900 TJ for Regulatory Alternatives III
and IV.
7.3.4 Other Impacts of Sodium-based Scrubbers
7.3.4.1 Noise. An increase in noise is expected as a result of
scrubber operation. Sources of noise are pumps, agitators, and fans
associated with the scrubber and wastewater treatment systems. This
increase in noise is not significant when compared to noise levels
associated with the FCC unit and supporting equipment.
7.3.4.2 Irreversible and Irretrievable Commitment of Resources.
This analysis has assumed that implementation of each regulatory
alternative other than Regulatory Alternative I will require installation
of sodium-based scrubbers. This will necessitate the additional use
of natural resources, especially alkali. However, the commitment of
these resources is expected to be small compared to national use.
7.4 ENVIRONMENTAL IMPACTS OF OTHER CONTROL TECHNOLOGIES18
This section discusses the environmental impacts that result from
control technologies which may be used as an alternative to sodium-based
7-15
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-------
scrubbers. These control technologies include: dual alkali, Wellman-Lord,
citrate, and spray drying flue gas desulfurization and sulfur oxides
reduction catalysts.
Nationwide impacts for each alternative control technology are
determined by assuming that all projected units subject to standards
of performance utilize the control technology discussed. Table 7-11
compares the nationwide environmental impacts of these alternative
control technologies with that of sodium-based scrubbers.
7.4.1 Dual Alkali
The dual alkali F6D systems can be applied to most FCC units;
however, a vendor has indicated that in circumstances where the flue
gas sulfur oxides concentration is below 800 ppmv, a single alkali
scrubber would be employed. In these cases, there is so much nonregenerable
sulfate present that a dual alkali system is unjustifiable. In order
to assess the nationwide impacts of the dual alkali system, it is
assumed that sodium-based scrubbers would be employed for units treating
low sulfur oxides flue gas concentrations. As shown in Table 7-4,
this would affect the two projected model units with feed sulfur
contents of 0.3 weight percent. The nationwide dual alkali impacts
include sodium-based scrubbing impacts for these units.
Dual alkali F6D systems use an aqueous sodium-based alkali solution
to absorb sulfur oxides from the flue gases. A calcium-based alkali
solution is then used to regenerate the active sodium solution.
During this regeneration process, a calcium sulfite/sulfate precipitate
is formed. This precipitate is removed for disposal. Sludge containing
the calcium sulfite/sulfate solids is concentrated in a vacuum filter
to about 50 percent solids by weight and sent to a landfill for disposal
Projected fifth-year solid waste impacts are 228 Gg, 246 Gg, and
263 Gg for Alternatives II, III, and IV, respectively.
Liquid wastes from dual alkali scrubbing are negligible, and
water consumption is low in comparison to the sodium-based system.
The fifth-year nationwide water consumption reported in Table 7-11 is
754,000 m3 for each regulatory alternative. The nationwide energy
impacts of the dual alkali system are comparable to the sodium-based
system. Dual alkali scrubbing would require 94.4 TJ energy in the
19
7-18
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fifth year of the standard. Energy requirements are a function of FCC
18 19
unit size and are not dependent on the level of sulfur oxides control. '
7.4.2 Wellman-Lord
The Wellman-Lord system utilizes a regenerate sodium sulfite
bisulfite system to remove sulfur dioxide from the flue gas. A variable
throat venturi scrubber serves to remove particulate matter and, in
addition, cools and saturates the gas stream. Water consumption
figures are indicated in Table 7-11.
Spent scrubbing liquor (sodium bisulfite) from the absorption.
stage is filtered to remove suspended solids and is heated in an •
evaporator for regeneration to sodium sulfite. A purge stream removes
small quantities of sodium sulfate and sodium thiosulfate, formed
during regeneration, from the absorbing solution. Liquid wastes,
composed of the sulfate purge and the wdter purge streams, are treated
in several ways. Some facilities route the purge streams to existing
refinery wastewater treatment plants, some use the purge streams as
raw material for other processing units (i.e., sulfuric acid dilution
water), and still others ocean dump. The Water purge from a Wellman-Lord
installation will require minimal treatment* i.e., neutralization (it
is only slightly acidic) and settling/filtration for removal of suspended
solids. In many cases, simple ponding will result in deposition of
most of the suspended solids (depending on specific gravity of the
solids).20
Projected fifth-year liquid waste impacts are presented in
Table 7-11. The COD, TDS, and SS of the water purge stream Will
depend, to a certain extent, on the COD, TDS, and SS of the Water
make-up to the Wellman-Lord plant. For example, if well water (untreated)
containing 200 mg/1 TDS and 40 mg/1 COD is used as make-up to the
scrubber, the water purge will contain approximately 1,500 mg/1 TDS
and 300 mg/1 COD. In other words, there is a concentration ratio of
about 7.5:1. In addition, the water purge will contain 5.0 weight
percent maximum SS, which consist of solids removed from the FCCU gas,
plus whatever SS were present in the make-up water, concentrated
7.5 times. The sulfate purge contains approximately 72 percent water
and 28 percent sodium salts, with COD and SS levels of 42,000 mg/1 and
18 20
100 mg/1, respectively. »
7-20
-------
7.4.3 Citrate
The citrate FGD system has negligible water and liquid waste
requirements. The system does, however, produce a solid waste product,
Glauber's salt (crystalline sodium-sulfate, NaSO. ' 10 H,0). Glauber's
21
salt is produced at a rate of 67.3 kg per Mg of sulfur recovered.
Glauber's salt is produced in a filter cake with other minor constituents
including diatomaceous earth, citrate salts, sulfur and catalyst fines
22
as a stable landfill material. Table 7-11 reports the fifth-year
nationwide volume of solid waste at 5.8, 6.3, and 6.8 Gg for
18
Alternatives II, III, and IV, respectively.
The citrate system has comparably high electrical requirements.
Under Regulatory Alternative II scrubbers would consume 268 TJ, and
2*3 24
Alternatives III and IV would consume 301 TJ each. ' Electricity
is consumed by high horsepower pump and agitator loads required to
25
move and mix viscous slurries.
7.4.4 Spray Drying
The use of spray drying FGD would impose much less severe water
and wastewater requirements upon implementation of the regulatory
alternatives. Nationwide water consumption in the fifth year would
amount to 1,050,000 m3 under Alternative II and 1,177,000 m under
Alternatives III and IV.18 In addition, spray drying does not produce
OC
a significant volume of liquid wastes.
Solid wastes from the application of spray drying to FCC units is
a filter cake which builds upon the fabric filter bags. The filter
cakes consist of calcium sulfate and catalyst fines. It is assumed
that the spray drying system will achieve 90 percent control of particulate
emissions; however, it has never been demonstrated for FCC units. The
nationwide solid waste impacts given in Table 7-11 amount to 75.4 Gg,
18 27
170 Gg, and 357 Gg for Alternatives II, III, and IV, respectively. '
7.4.5 Sulfur Oxides Reduction Catalysts
As discussed in Section 4.5.2, sulfur oxides reduction catalysts
are an emerging control technology in fluid catalytic cracking.
Sulfur oxides reduction catalysts are not expected to have any incremental
impact upon solid or liquid wastes or energy consumption over baseline.
7-21
-------
7.5 ENVIRONMENTAL IMPACT OF DELAYED STANDARDS
Delay in implementation of each regulatory alternative except
Regulatory Alternative I would adversely impact air quality at the
rate shown in Table 7-6. The annual sulfur oxides emissions reduction
column represents the lost emissions reductions for each year the
standard is delayed. No adverse solid, water, or energy impacts are
expected from delaying regulatory action.
7-22
-------
7.6 REFERENCES
1. Memorandum from Bernstein, G., Pacific Environmental Services,
Inc., to Docket Number A-79-09. May 21, 1982. Results of Analysis
of NO Emissions Study. Docket Reference Number II-B-20.*
/\
2. Letter and Attachments from Larson, W.E., Chevron U.S.A., Incorporated
to Goodwin, D., U.S. Environmental Protection Agency. March 24,
1981. p. 4. Response to Section 114 letter on FCC unit alterations
and expansions. Docket Reference Number II-D-42.*
3. Letter and Attachments from Laque, W.E., Rock Island Refining
Corporation to Goodwin, D.R., U.S. Environmental Protection
Agency. March 18, 1981. p. 3. Response to Section 114 letter .
on FCC unit alterations and expansions. Docket Reference Number
II-D-40.*
4. Letter and Attachments from Adams, J.T., Jr., ARCO Petroleum
Products Company to Goodwin, D.R., U.S. Environmental Protection
Agency. April 3, 1981. p. 3. Response to Section 114 letter on
FCC unit alterations and expansions. Docket Reference Number
II-D-43.*
5. Telecon. Manda, Michael, Pacific Environmental Services, Inc.,
with Scharff, Davis, Champ!in Oil Company. May 4, 1981. Growth
in capacity of Champlin FCC units. Docket Reference Number II-E-1.*
6. Telecon. Manda, Michael, Pacific Environmental Services, Inc.,
with Cox, Lyman, Charter Oil Company. April 16, 1981. Growth in
capacity of Charter FCC units. Docket Reference Number II-E-1.*
7. Telecon. Manda, Michael, Pacific Environmental Services, Inc.,
with Segar, Tom, Koch Refining Company. April 16, 1981. Growth
in capacity of Charter FCC units. Docket Reference Number II-E-1.*
8. Telecon. Manda, Michael, Pacific Environmental Services, Inc.,
with Clodi, Charles, Mobil Oil Company. April 23, 1981. Lack of
expansion activity on FCC unit at Joliet, Illinois, refinery.
Docket Reference Number II-E-1.*
9. Memorandum. Manda, Michael, Pacific Environmental Services, Inc.
to Docket No. A-79-09. Growth Projections for FCC Units. July
17, 1981. Docket Reference Number II-B-16.*
10. Letter and Attachments from Albaugh, D., Marathon Oil Company, to
• Goodwin, D.R., U.S. Environmental Protection Agency. March 20,
1981. Response to Section 114 information request. Docket
Reference Number II-D-41.*
7-23
-------
11. Technology Assessment Report for Industrial Boiler Applications:
Flue Gas Desulfurization. U.S. Environmental Protection Agency.
Research Triangle Park, North Carolina. Publication Number
EPA-600/7-79-178i. November 1979. p. 6-13. Docket Reference
Number II-A-10.*
12. Letter and Attachments from Cunic, J.D., Exxon Research and
Engineering Company, to Goodwin, D.R., U.S. Environmental Protection
Agency. November 23, 1981. Docket Reference Number II-D-65.*
13. Jones, H.R. Pollution Control in the Petroleum Industry.
Data Corporation. Park Ridge, New Jersey. 1973. p. 144.
Docket Reference Number 11-1-8.*
Noyes
14. Letter and Attachments from Cunic, J.D., Exxon Research and
Engineering Company, to Durham, J.F., U.S. Environmental Protection
Agency. January 23, 1981. Information on sodium scrubber costs.
Docket Reference Number II-D-37.*
15. Letter and Attachments from Adams, J;T., Jr., ARCO Petroleum
Products Company, to Goodwin, D.R., U.S. Environmental Protection
Agency. April 3, 1981. Response to Section 114 information
request. Docket Reference Number II-D-43.*
16. Letter and Attachments from Larson, W.E., Chevron U.S.A., Inc.,
to Goodwin, D.R., U.S. Environmental Protection Agency. March 24,
1981. Response to Section 114 information request. Docket
Reference Number II-D-42.*
17. Letter and Attachments from Pritchard, James J., Ashland Petroleum
Company, to Goodwin^ D.R., U.S. Environmental Protection Agency.
May 27, 1981. Response to Section 114 information request.
Docket Reference Number II-D-53.*
18. Memorandum from Rhoads, T.W., Pacific Environmental Services,
Inc., to Docket A-79-09. April 27, 1982. Environmental and cost
impact analyses for the sodium-based, dual alkali, Wellman-Lord,
citrate, and spray drying FGD systems. Docket Reference
Number II-B-23.*
19. Telecon. Czuchra, P.A., FMC Corporation, with Osbourn* S.,
Pacific Environmental Services, Inc. January 13, 1982. Dual
alkali scrubber costs. Docket Reference Number II-E-5.*
20. Letter and Attachments from Pedroso, R.I., Davy McKee Corporation
to Rhoads, Thomas, Pacific Environmental Services, Inc. February 24,
1982. Docket Reference Number II-D-92.*
21. Telecon. Madenburg, D., Morrison-Knudsen, with Meardon, K.,
Pacific Environmental Services, Inc. January 7, 1982. Citrate
information. Docket Reference Number II-E-5.*
7-24
-------
22. Telecon. Nissen, B., U.S. Bureau of Mines, with Meardon, K.,
Pacific Environmental Services, Inc. February 11, 1982. Citrate
information. Docket Reference Number II-E-5.*
23. Telecon. Madenburg, D., Morrison-Knudsen, with Meardon, K.,
Pacific Environmental Services, Inc. January 6, 1982. Citrate
information. Docket Reference Number II-E-5.*
24. Telecon. Nissen, B., U.S. Bureau of Mines, with Meardon, K.,
Pacific Environmental Services, Inc. January 12, 1982. Citrate
information. Docket Reference Number II-E-5.*
25. Telecon. Madenburg, D., Morrison-Knudsen, with Rhoads, T.W.,
Pacific Environmental Services, Inc. March 4, 1982. Citrate
information. Docket Reference Number II-E-5.*
26. Letter and Attachments from Petti, V.J., Wheelabrator-Frye, Inc.,
to Rhoads, T.W., Pacific Environmental Services, Inc. February
12, 1982. Dry scrubbing capital and operating cost parameters
for catalytic cracking towers. Docket Reference Number II-D-88.*
27. Telecon. Petti, V.J., Wheelabrator-Frye, Inc., with Rhoads,
T.W., Pacific Environmental Services, Inc. March 1, 1982. Spray
drying information. Docket Reference Number II-E-5.*
28. Memorandum from Cole, H., Environmental Protection Agency, to
Fanner, J., Environmental Protection Agency. Dispersion Estimates
for SO Emissions from Fluid Catalytic Cracking Units (FCCU).
April $4, 1982. Docket Reference Number II-B-22.*
*References can be located in Docket.Number A 79-09 at the U.S.
Environmental Protection Agency's Central Docket Section,
West Tower Lobby, Gallery 1, Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
7-25
-------
-------
8.0 COST ANALYSIS
8.1 INTRODUCTION
The capital costs, annual costs, and cost effectiveness of
implementing Regulatory Alternatives II through IV are estimated for
each new and modified/reconstructed model FCC unit. These estimates
are used to determine the economic impacts of the regulatory alterna-
tives upon the petroleum refining industry. The economic impact
analysis is presented in Chapter 9.0. No control costs are associated
with Regulatory Alternative I as this is the baseline level.
As discussed in Section 6.1, this cost analysis is founded on the
application of sodium-based scrubber technology to model FCC unit flue
gas parameters. The capital and annual cost of treating and disposing
of the scrubber waste stream to surface water is included in the
scrubber system costs. A description of a sodium-based scrubbing
system is provided in Section 4.2; model unit flue gas parameters are
presented in Section 6.1. To ensure a common cost basis, Nelson Cost
Indexes are used to adjust costs to fourth quarter 1980 dollars.1
Although several vendors market sulfur oxides scrubber systems
that can be applied to FCC regenerators, the sodium-based scrubbers
presently in use on FCC regenerators at five refineries are licensed
by one vendor. The vendor provided capital and annual costs for
two model units. These model FCC units have throughput capacities of
2,500 and 8,000 m fresh feed/stream day and a flue gas sulfur oxides
concentration of 1,400 vppm. Scaling and other factors provided by
the vendor allow determination of annual scrubber costs for all other
model units.
A discussion of costs for other flue gas desulfurization systems
and sulfur oxides reduction catalysts is presented in Section 8.2.
While only the sodium-based scrubber system has been widely applied to
8-1
-------
FCC units at present, these alternative control technologies may also
be applied to FCC units upon implementation of new source performance
standards for sulfur oxides. And, in Section 8.3 the costs for an
electrostatic precipitator (ESP) are included in the discussion of
other costs. The cost for particulate emissions control is included
in the baseline costs, Regulatory Alternative I, because the existing
NSPS requires particulate control. Therefore, a credit for particulate
control, based on ESP costs, is applied to the total annual costs for
flue gas desulfurization systems which control particulates in addition
to sulfur oxides.
8.2 SODIUM-BASED FLUE GAS DESULFURIZATION COSTS
This section presents the capital and annual costs for sodium-based
scrubbing and wastewater treatment systems. As discussed in Sections 8.2.1
and 8.2.2, the cost for sodium-based scrubbing applied, to FCC units is
dependent upon the type of venturi scrubber used. A high energy
venturi scrubber would be employed by FCC units operating under high
temperature regeneration (HTR) or conventional promoted regeneration.
FCC units which operate with a. carbon. mpnoxid,e combustion furnace
would utilize a jet ejector type venturi.
8.2.1 Capital and Annual Costs for Sodium-based High Energy Venturi
Scrubbers
The high energy venturi relies upon line pressure from the regenerator
to force flue gas through the venturi without fans. High energy
Venturis are expected to be used by all new FCC units and modified/
reconstructed units unless the unit relies upon a boiler for carbon
monoxide combustion. It is estimated that five of the seven projected
modified/reconstructed units in Table 7-5 will utilize high energy
Venturis.
The capital .cost of the sodium-based scrubber system (including
wastewater treatment) is primarily a function of the regenerator flue
qas flow rate and, hence, FCC throughput. It is not dependent on the
2
inlet concentration of sulfur oxides in the flue gas. Scrubber
system capital costs for the 2,500 and 8,000 m /sd model units are
presented in Table 8-1. The total capital costs are $4.0 million and
$6.8 million, respectively.
8-2
-------
Table 8-1. . CAPITAL COST FOR SODIUM-BASED HIGH ENERGY VENTURI
SCRUBBING SYSTEM AND PURGE TREATMENT FOR MODEL UNITS3
Total Direct Costs
Indirect Costs
Total Direct and Indirect
Contingency0
Total Capital Cost
ESP Capital Cost Creditd
2,500 m3/sd
Model Unit
2.3
1.0
3.3
0.7
4.0
-0.8
8,000 m3/sd
Model Unit
4.0
• 1.7
5.7
1.1
6.8
-1.4
Costs are reported in millions of dollars, adjusted to
fourth quarter 1980, delivered to a Gulf Coast location.
See Reference 2.
Materials and labor.
°Twenty percent of total direct and indirect costs.
Table 8-19.
8-3
-------
The regulatory alternatives, shown graphically in Figure 6-1,
require sulfur oxides control efficiencies to 93 percent, depending on
feedstock quality and regulatory alternative. The annual cost of
using the sodium-based scrubber system to control sulfur oxides emissions
is dependent on the quantity of sulfur oxides removed from the flue
gas stream. For a particular regulatory alternative there is a direct
relationship between the sulfur oxides concentration at the scrubber
inlet and the utility costs.2
Only one utility cost component, alkali, varies significantly
with inlet sulfur oxides concentration and regulatory alternative.
The other utility costs are constant because of the particulate
collection requirements of the scrubbing system. To meet the particulate
NSPS, the scrubber liquid-to-gas ratio must remain constant throughout
the range of expected sulfur oxides loadings and removal efficiencies.
Since the regenerator flue gas flow rate is constant for a given model
unit throughput, scrubber liquor recirculating pumps, waste treatment
equipment, and other equipment pperate at constant conditions. Thus,
only alkali consumption changes with flue gas sulfur oxides variations.
Alkali consumptiqn is assumed tp vary proportionally with the scrubber
inlet loading2 and with the level of sulfur oxides control required
for each regulatory alternative.
The assumptions used to develop annual costs are summarized in
Table,8-2. Table 8-3 provides the bases for determining annual costs.
Maintenance, capital cost recovery, tax, insurance, and administrative
costs are calculated by applying the appropriate capital cost from
Table 8-1.
Annual costs for each model unit meeting Regulatory Alternatives II
through IV are presented in Tables 8-4 through 8-9. Two annual costs
are reported for each model unit since either caustic soda or soda ash
may be used as the alkali. Annual sulfur oxides emission reduction
and cost effectiveness are reported for each model unit and regulatory
alternative. Annual emission reductions are reported in Mg/yr, and
cost effectiveness is reported in $/Mg sulfur oxides removed. The
higher annual cost value with caustic soda is used to calculate
cost effectiveness. Because it may not be possible to scale down the
scrubber control efficiencies to meet the levels of the regulatory
8-4
-------
alternatives (as little as 25 percent in some cases), a second net
cost, emission reduction, and cost effectiveness is shown for "full
scrubbing." Full scrubbing is defined here to mean control to 50 vppm
for the low sulfur model plants, 93 percent control for the high
sulfur model plants to meet regulatory alternative IV, and 90 percent
control for all other cases. The costs have been revised to reflect
the higher degree of caustic consumption and the emission reductions
have been revised to reflect the correspondingly high reduction in SO
/\
emissions.
8-5
-------
Table 8-2. ASSUMPTIONS USED TO DEVELOP'ANNUAL COSTS
Assumptions
1. New FCC units utilize high temperature regeneration. Existing
units utilize either conventional regeneration with carbon
monoxide combustion promoters or a carbon monoxide combustion
furnace to combust carbon monoxide in a controlled manner outside
the regenerator vessel. Sodium-based scrubbers will utilize
high energy Venturis unless the unit is equipped with a carbon
monoxide boiler.
2. The cost of treating the scrubber waste stream is included in
the scrubber system annual costs. The scrubber purge treatment
unit consists of below-ground ponding for sedimentation of the
suspended solids (catalyst fines) and surface aerators in below-
ground ponds to reduce the chemical oxygen demand of the purge
stream to acceptable levels prior to discharge. Inland disposal
using evaporative ponds is discussed in Section 8.2.3. Other
systems that have no wastewater discharge are presented in
Section 8.3.
3. Caustic (or soda ash) consumption is proportional to the amount
of sulfur oxides removed for each regulatory alternative. All
other utilities remain constant.
4. FCC unit and scrubber system operate 357 days per year (approximately
98 percent availability), based on a typical FCC unit turnaround
of about 3 weeks every 3 years.
5. Solid wastes consist primarily of catalyst fines. The amount of
solid waste to be disposed is calculated assuming 90 percent
3
collection of 0.85 g particulate/Nm into the scrubber.
6. The capital recovery factor (CRF) is based on a 10 percent
interest rate and an expected service life of 15 years for the
3
scrubber and purge treatment system.
8-6
-------
Table 8-3. BASES FOR DETERMINING ANNUAL COSTS
Direct Operating Costs
Labor
Maintenance (includes materials,
manning, and overhead)
Utilities
Electricity
Water
Compressed Air
Caustic Soda (Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery Factor
$14.35/houra
1.5 percent of total capital
cost5
$0.0652/kWhc
$0.0625/m3d
$0.706/1,000 m
3d
$220/Mge ($100/Mg)T
$11.09/1,000 kgd
$8.25/kgg
$16.50/Mgc
4 percent of total capital costc
13.15 percent of total capital
costd
alncludes 40 percent overhead. Reference 3.
bSee Reference 2.
cCost from Reference 4, updated to September 1980. Reference 3.
See Reference 4.
eLiquid caustic soda, 100 percent. F.O.B. Gulf Coast. Reference 5.
fBulk soda ash, light, 99 percent. F.O.B. Wyoming. Reference 6, 7.
9Polymer 3300, an anionic polyacrilomide settling agent. Fifty pound
bags, F.O.B. Dallas, Texas. Reference 8.
8-7
-------
Table 8-4. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE - CASE
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Annual Cost, in thousands
Reg. Alt. IIC Reg. Alt. Ill
44.0
60
18.4
3.4
0.3
36.8
(22.5)
0.9
4.0
5.8
of dollars
Reg. AH. IV
44.0
60
18.4
8.4
0.3
73.6
(45.1)
0.9
4.0
5.8
Indirect Operatirig Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash) 0
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Mg SOX removed/yr) 0
Cost Effectiveness
($/Mg SOX- removed) •
160
526
860
(850)
-200
660
(650)
130
5,080
160
526
900
(870)
-200
700
(670)
260
2,690
FULL SCRUBBING6
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness
($/Hg SOX removed)
760
450
1,690
760
450
1,690
aBased on data available in Reference 2. Case 1: 2,500 m /sd model
unit, 0.3 weight percent sulfur feedstock.
bNumbers may not add to totals due to rounding. Fourth quarter 1980
dollars.
cNo controls necessary to meet this regulatory alternative.
dBased on net annual cost with caustic soda.
eBased on control to 50 vppm with caustic soda. Reference 45.
8-8
-------
Table 8-5. ANNOAL COST OF SODIUM-BASED HIGH ENERGY VENTBRI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE3 - CASE 2
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Mater
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Mg SO removed/yr)
Cost Effectiveness0
($/Mg SOX removed)
FULL SCRUBBING*1
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness
($/Mg SOX removed)
Annual
Reg. Alt.
44.0
60
18.4
8.4
0.3
381
(234)
a. 9
4.0
5.8
160
526
1,210
(1,060)
-200
1,010
(860)
1,340
760
1,100
1,670
660
Cost, in thousands
II Reg. Alt. Ill
44.0
60
18.4
8.4
0.3
418
(256)
0.9
4.0
5.8
160
526
1,240
(1,080)
-200
1,040
(880)
1,470-
710
1,100
1,670
660
of dollarsb
Reg. Alt. IV
44.0
60
• 18.4
8.4
0.3
456
(279)
0.9
4.0
5.8
160
526
1,280
(1,100)
-200
1,080
(900)
1,600
680
1,100
1,670
660
aBased on data available in Reference 2. Case 2: 2,500 m/sd model
unit, 1.5 weight percent sulfur feedstock.
bNumbers may not add to totals due to rounding. Fourth quarter
1980 dollars.
cBased on net annual cost with caustic soda.
ABased on 90 percent control with caustic soda. Reference 45.
8-9
-------
Table 8-6. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE9 - CASE 3
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrplyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness0
(S/Mg SOX removed)
FULL SCRUBBING*1
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness
($/Mg SOX removed)
Annual
Reg. Alt.
44.0
60
18.4
8.4
0.3
846
(519)
0.9
4.Q
5.8
160
526
1,670
(1,340)
-200
1,470
(1.140)
2,970
490
1,520
3,130
490
Cost, in thousands
II Reg. Alt. Ill
44.0
60
18.4
8.4
0.3
884
(542)
0.9
4.Q
5.8
160
526
1,710
(1,370)
-200
1,510
(1,170)
3,100
490
1,520
3,130
490
of dollars
Reg. Alt. IV
44.0
60
18.4
8.4
0.3
920
(564)
0.9
4.0
5.8
160
526
1,740
(1,390)
-200
1,540
(1?190)
3.23Q
480
1,540
3,230
48Q
aBased on data available in Reference 2. Case 3: 2,500 m"/sd model
unit, 3.5 weight percent sulfur feedstock.
Numbers may not add to totals due to rounding. Fourth quarter
1930 dollars.
GBased on net annual cost with caustic soda.
ABased on 90 percent control for alternatives II and III and 93 percent
control for alternative IV with caustic soda. Reference 45.
8-10
-------
Table 8-7. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE3 - CASE 4
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reductfon
(Mg SOX removed /yr)
Cost Effectiveness
($/Mg SOX removed)
FULL SCRUBBING6
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness
($/Mg S0x removed)
Annual Cost, in thousands
Reg. Alt. IIC Reg. Alt. Ill
44.0 •
102
58.7
: 25.1
0.3
118
(73)
2.6
12.0
18.6
272
894
1,550
, 0 (1,500)
-330
1,220
(1,170)
0 410
2,980
1,510
0 1,440
1,050
of dollars6
Reg. Alt. IV
44.6
102
58.7
25.1 '
0.3
236
(146)
2.6
12.0
18.6
272
894
1,670
(1,580)
-330
1,340
(1,250)
830
1,610
1,510
1,440
1,050
aBased on data available in Reference 2. Case 4: 8,000 m /sd model
unit, 0.3 weight percent sulfur feedstock.
lumbers may not add to totals due to rounding. Fourth quarter
1980 dollars.
°No controls necessary to meet this regulatory alternative.
Based on net annual cost with caustic soda.
eBased on control to 50 vppm with caustic soda. Reference 45.
8-n
-------
Table 8-8. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENT0RI
SCRUBBING FOR MODEL UNITS BY REGUtlATORY ALTERNATIVE21 - CASE 5
Direct Operating Costs
Labor
Maintenance
Utilities '
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
polyelectrolyte
Haste Disposal
Indirect Operating Costs
Tax, Insurance, and
'Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Annual Cost,
Reg. Alt. II
44.0
102
58.7
25.1
0.3
1,220
(755.)
2.6
12.Q
18.6
272
894
2,650
(2,180)
-330
2,320
(1,850)
in thousands
Reg. AH. Ill
44.0
102
58.7
25.1
0.3
1,340 •
(829)
2.6
12.0
18.6
272
894
2,770
(2,260)
-330
2,440
(1,928)
of dollars
Reg. Alt. IV
44.0
102
58.7
25.1
0.3
1,460
(902)
2.6
12.0
18.6
272
894
2,890
(2,331)
-330
2,560
(2,000)
Emission Reduction
(Mg SOX removed/yr) 4,290 4,710 5,120
Cost Effectiveness0
($/Mg SOX removed) 540 518 50°
FULL SCRUBBING*1
Net Annual Cost c,n
With Caustic Soda 2,630 2,630 2,630
Emission Reduction
(Mg SOX removed/yr) 5,350 5,350 5,350
Cost Effectiveness
($/Mg SOX removed) 490 490 490
aBased on data available in Reference 2. Case 5: 8,000 m3/sd model
unit, 1.5 weight percent sulfur feedstock.
bNumbers may not add to totals due to rounding. Fourth quarter
1980 dollars.
C8ased on net annual cost with caustic soda.
dBased on 90 percent control with caustic soda. Reference 45.
8-12
-------
Table 8-9. ANNUAL COST OF SODIUM-BASED HIGH ENERGY VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE9 - CASE 6
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness0
($/Mg SO removed)
FULL SCRUBBING*1
Met Annual Cost
With Caustic Soda
Emission Reduction
(Mg SO removed/yr)
Cost Effectiveness
($/Mg SOX removed)
Annual
Reg. Alt.
44.0
102
58.7
. 25.1
0.3
2,710
(1,675)
2.6
12.0
18.6
272
894
4,140
(3,100)
-3,30
3,810
(2,770)
9,500
400
3,950
9,990
400
Cost, in thousands
II Reg. Alt. Ill
44.0
102
58.7
25.1
0.3
2,830
(1,750)
2.6 ,
12.0
18.-6
272
894
4,260
(3,180)
-330
3,930
(2,850).
9,910
400
3,950
9,990
400
of dollars
Reg. Alt. IV
44.0
102
58.7
25.1
0.3
2,950
(1,820)
2.6
12.0
18.6
272
894
4,370
(3,250)
-330
4,04a
(2,920)
10,300
ago
4,040
10,300
390
aBased on data available in Reference 2. Case 6: 8,000 m /sd model
unit, 3.5 weight percent sulfur feedstock.
lumbers may not add to totals due to rounding. Fourth quarter 1980 dollars.
cBased on net annual cost with caustic soda.
ABased on 90 percent control for alternatives II and III and 93 percent
for alternative IV with caustic soda. Reference 45.
8-13
-------
From Tables 8-4 through 8-9, net annual costs for model units
3
range from about $1.1 million for a 2,500 m /sd unit processing 0.3 weight
percent sulfur and meeting Regulatory Alternative III to $4.0 million
3
for an 8,000 m /sd unit processing 3.5 weight percent sulfur and
meeting Regulatory Alternative IV. For these two units, annual sulfur
oxides emission reductions range from 130 to 10,300 Mg and cost
effectiveness ranges from $5,080 to $390/Mg sulfur oxides removed,
respectively.
8.2.2 Capital and Annual Costs for Sodium-based Jet Ejector
Venturi Scrubbers
Jet ejector Venturis would be utilized with sodium-based scrubbing
for FCC units equipped with a carbon monoxide combustion furnace.
Under these conditions, additional energy is required to move the
regenerator flue gas through the scrubber and out the stack. A jet
ejector-type venturi serves- this purpose.
It is estimated that two of the modified/reconstructed units
projected in Table 7-5 will employ a jet-ejector type venturi. And,
in order to assess nationwide impacts of sodium-based scrubbing, it is
assumed that these two units are characterized by one small and one
large FCC model unit, each charging a 1.5 weight percent sulfur feedstock.
The capital costs for sodium-based scrubbing with a jet-ejector
type venturi are higher than that of high energy venturi scrubbers.
The higher costs are attributed to the additional piping, pumps, and
spray nozzles that comprise the jet ejector scrubber system as discussed
in Section 4.2.2.2. From Table 8-10, the total capital costs for jet
ejector sodium-based scrubbing systems applied to 2,500 m /sd and
o
8,000 m /sd model units are $5.5 million and $9.6 million, respectively.
Annual costs for sodium-based scrubbing are also higher with jet
ejector Venturis as compared to the high energy Venturis. The higher
cost is largely due to the additional electrical requirement of jet
ejector venturi scrubbers as discussed in Section 7.3.3. Tables 8-11
3 3
and 8-12 itemize the annual costs for a 2,500 m /sd unit and 8,000 m /sd
unit based upon jet ejector venturi scrubbers. The cost effectiveness
for these units ranges from $l,120/Mg sulfur oxides removed for a
small model unit Regulatory Alternative II to $740/Mg sulfur oxides
removed for a large model unit under Regulatory Alternative III. As
in Tables 8-4 through 8-9, a separate cost and emission, reduction is
shown for a 90 percent, "full scrubbing" case.
8-14
-------
Table 8-10. CAPITAL COST FOR SODIUM-BASED JET EJECTOR VENTURI
SCRUBBING SYSTEM AND PURGE TREATMENT FOR
MODEL UNITS3
Total Direct Costsb
Indirect Costs
Total Direct and Indirect
Contingency0
Total Capital Cost
ESP Capital Cost Creditd
2,500 m3/sd
Model Unit
3.3
1.3
4.6
0.9
5.5
-0.8
8,000
Model
5.6
2.4
8.0
1.6
9.6
-1.4
m3/sd
Unit
Costs are reported in millions of dollars, adjusted to
fourth quarter 1980, delivered to a Gulf Coast location.
See Reference 2.
Materials and labor.
cTwenty percent of total direct and indirect costs.
dFrom Table 8-19.
8-15
-------
Table 8-11. ANNUAL COST OF SODIUM-BASED JET EJECTOR VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVE3 - CASE 7
Annual Cost, 1n thousands of dollars
Direct Operating Costs
Labor
Maintenance
Utilities
Electricity
Water
Compressed Air .
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Hg SOX removed/yr)
Cost Effectiveness0
(S/Hg SO removed)
FULL SCRUBS INGd
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SO removed/yr)
Cost Effectiveness
($/Mg SO removed)
Reg. Alt. II
44.0
82.5
235
8.4
0.3
381
(234)
0.9
4.0
5.8
220
723
1,700
(1,560)
-200
1,500
(1,360)
1,340
1,120
1,600
1,670
960
Reg. Alt. Ill
44.0
82.5
235
8.4
0.3
418
(256)
0.9
4.0
5.8
220
723
1,740
(1,580)
-200
1,540
(1,380)
1,470
1,050
1,600
1,670
960
Reg. Alt. IV
44.0
82.5
235
8.4
0.3
456
(279)
0.9
4.0
5.8
220
723
1,780
(1,600)
-200
1,580
(1,400)
1,600
990
1,600
1,670
960
'Based on data available in Reference 2. Case 7: 2,500 m /sd model
unit, 1.5 weight percent sulfur feedstock.
bNumbers may not add to totals due to rounding. Fourth quarter
1980 dollars.
C8ased on net annual cost with caustic soda.
dBased on 90 percent control with caustic soda. Reference 45.
8-16
-------
Table 8-12. ANNUAL COST OF SODIUM-BASED JET EJECTOR VENTURI
SCRUBBING FOR MODEL UNITS BY REGULATORY ALTERNATIVEa - CASE 8
Annual Cost, in thousands of dollars
Direct Operating Costs
Labor
Maintenance '
Utilities
Electricity
Water
Compressed Air
Caustic Soda
(Soda Ash)
Steam
Polyelectrolyte
Waste Disposal
Indirect Operating Costs
Tax, Insurance, and
Administration
Capital Recovery Cost
Total Annual Cost
With Caustic Soda
(Soda Ash)
ESP Credit
NET ANNUAL COST
With Caustic Soda
(Soda Ash)
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness0
($/Mg SOX removed)
FULL SCRUBS I NGd
Net Annual Cost
With Caustic Soda
Emission Reduction
(Mg SOX removed/yr)
Cost Effectiveness
($/Mg SOX removed)
Reg. Alt. II
44.0
144
754
25.1
• 0.3
1,220
(755)
2.6
12.0
18.6
384
1,261
3,870
(3,400)
-330
3,540
(3,070)
4,290
830
3,850
5,350
720
Reg. Alt. Ill
44.0
144
754
25.1
0.3
1,340
(829)
2.6
12.0
18.6
384
1,261
3,990
(3,480)
-330
3,660
(3,150)
4,710
780
3,850
5,350
720
Reg. Alt. IV
•44.0
144
•754
25.1
0.3
1,460
(902)
2.6
12.0
18.6
384
1,261
4,110
(3,550)
-330
3,780
(3,220)
5,120
740
3,850
5,350
720
aBased on data available in Reference 2. Case 8: 8,000 m /sd model
unit, 1.5 weight percent sulfur feedstock.
lumbers may not add to totals due to rounding. Fourth quarter
1980 dollars.
cBased on net annual cost with caustic soda.
dBased on 90 percent control with caustic soda. Reference 45.
8-17
-------
8.2.3 Water and Solid Waste Cost Impacts
The purge stream from the sodium-based scrubber is treated prior
to discharge to coastal waters. The wastewater treatment system costs
are included with the scrubber system costs in Tables 8-1 and 8-4
through 8-12. The treatment system represents approximately 25 percent
of the total direct cost reported in Tables 8-1 and 8-10, and 30 percent
of the annual cost of utilities reported in Tables 8-4 through 8-9
and 8-11 and 8-12.
The five refineries with sodium scrubbers in place for sulfur
oxides control are in or near coastal locations and discharge the
treated scrubber wastewater to large rivers or coastal waters. Refiners
in inland locations considering the sodium-based scrubber for FCC
sulfur oxides control may not be able to discharge the treated scrubber
wastestream to inland bodies of water due to water quality considerations
and discharge permits. For these inland refiners, vapor compression
distillation, multistaged flash evaporation* evaporation ponds, reverse
osmosis, or deep well injection may be viable approaches for disposal
of the scrubber effluent. Of the 102 sodium scrubber systems currently
in use on industrial boilers, about 80 use evaporation ponds and
10 use centralized water treating systems. The remainder use varied
approaches ranging from discharge to city sewers to deep well injection.
The use of sodium-based scrubbers, however, may not be feasible
for some inland FCC units. One limiting factor is the availability of
sufficient water to operate the scrubbing system. A second limiting
factor is the ability to dispose wastewater produced by this scrubber
system. Based on industrial boiler use, evaporation ponds would be
the likely method for waste disposal. However, the use of evaporation
ponds is limited to certain geographic areas of the country where
annual evaporation rates exceed the annual rainfall. An alternative
to evaporation ponds is to dilute the wastewater and discharge to
surface waters (providing the necessary water resources exist).
Due to the problems associated with sodium-based scrubbers mentioned
above, it is anticipated that some refiners will opt to employ control
technologies with less severe water and wastewater discharge requirements.
8-18
-------
These control systems are discussed in Chapter 4, and their
environmental impacts are presented in Section 7.4. Costs for these
alternative control technologies are presented in Section 8.3.11
No additional solid waste cost impacts are anticipated through
addition of sodium-based scrubbers for control of sulfur oxides.
8.2.4 Nationwide Cost Impacts '
The projected nationwide cost impacts for sodium-based scrubbing
are presented in Table 8-13 along with the costs for the other control
technologies discussed in Section 8.3. The nationwide cost impacts
assume that all FCC units subject to standards of performance will
employ the same control technology. These projections are calculated
using anticipated FCC unit construction, modification, and reconstruction
from Tables 7-4 and 7-5 and the capital and annual costs for each
model unit.
The cumulative 5-year capital costs for sodium-based scrubbing
are $72.1 million for Regulatory Alternative II and $80.7 million for
Regulatory Alternatives III and IV. Annual costs in the fifth year of
the standard, 1986, are based on scrubbing with caustic soda. Annual
costs in the fifth year of the standard are $32.1 million, $35.3 million,
and $36.7 million for Regulatory Alternatives II, III, and IV, respectively.
8.3 OTHER CONTROL TECHNOLOGY COSTS
The following sections present costs for alternative control
technologies which may be applied to FCC units to control sulfur
oxides emissions to the level of the regulatory alternatives. While
these control technologies are not presently commercially applied to
FCC regenerators, it is likely that these could be considered as
necessary for specific applications. These control technologies,
discussed in Chapter 4.0, are analyzed on similar cost bases as the
sodium-based scrubber in order to compare the costs of the different
systems. The costs are updated to fourth quarter 1981 dollars using
Nelson Cost Indexes and many assumptions used in the sodium-based
scrubber are used in the other systems. For example, all capital
costs include a 20 percent contingency, and the annual costs assume a
15-year life for determining the capital recovery costs for each
system. The same unit costs for utilities and operating labor and
materials are also used in each system.
8-19
-------
Table 8-13. COMPARISON OF FIFTH-YEAR NATIONWIDE
SCRUBBER SYSTEM COSTS
(Thousands of Fourth Quarter 1980 Dollars)
Nationwide Costs
a,b
Regulatory Alternative
II
III
IV
Five-Year Capital Cost
Sodium Based
Well man-Lord
Dual Alkali
Citrate
Spray Drying
Fifth- Year Annual Cost
Sodium Based
Sodium Based (full
scrubbing)
Well man-Lord
Dual Alkali
Citrate
Spray Drying
72,100
106,000
. 35,700
56,100
53,200
32,100
35,000
28,200
16,400
25,900
15,900
80,700
116,000
45,700
60,500.
59,700
35,300
37,300
31,200
19,100
18,100
20,100
80,700
119,000
47,200
60,500
59,700
36,700
37,500
32,900
20,100
5,430
32,600
aThe costs reported assume that all new and modified/reconstructed FCC
units will employ the scrubbing system costed.
bThe nationwide costs for each scrubber system are calculated by multiplying
the costs per model unit by the projected number of model units subject
to standards of performance under each regulatory alternative. A -
schedule of model units subject to the regulatory alternatives is
provided in Tables 7-4 and 7-5. Reference 11.
8-20
-------
An itemized cost table for each control technology is presented
•3 O
for a 2,500 m /sd and 8,000 m /sd model unit assuming a 1.5 percent
sulfur feedstock subject to Regulatory Alternative III. This scenario
corresponds to a 1,400 vppm sulfur dioxide inlet concentration and
control to 300 vppm. Table 8-13 presents a comparison of the nationwide
control costs based on the different control technologies and regulatory
alternatives. The nationwide costs report the cumulative 5-year
capital cost and the fifth year annual cost for each control technology.
The nationwide costs assume that all affected facilities employ the
same control technology. This analysis provides a basis for comparing
the system costs; however, it is unlikely that any one control system
will be relied upon for all FCC units. In addition, the sodium-based
system costs are from actual FCC regenerator application experience.
Other systems will likely incur increased costs to increase their
on-line reliability to match that of the FCC unit.
8.3.1 Dual Alkali Flue Gas Desulfurization
The costs of applying dual alkali scrubbers to FCC units are
presented in this section. Cost information was obtained from a dual
12 13
alkali vendor. The itemized capital and annual costs for the
model units are given in Table 8-14 for a 1.5 weight percent sulfur
feedstock. Because the dual alkali system employs a packed tower
absorber, the system does not afford the secondary advantage of_
particulate control as was the case for sodium-based scrubbers.
Therefore, the annual costs of an electrostatic precipitator are not
credited to the dual alkali system costs.
According to the dual alkali vendor, the dual alkali system is
not feasible for flue gas concentrations of less than 800 vppm sulfur
dioxide. Low scrubber sulfur dioxide inlet concentrations would
result in a high level of nonregenerable sulfate present in the scrubbing
liquor.15 In these applications, a single alkali system would be
applied. Hence, in order to determine nationwide cost impacts, sodium-
based scrubbing costs as discussed in Section 8.2 are used for the
projected units processing feedstocks with low sulfur content (0.3 weight
percent sulfur, corresponds to a 400 vppm inlet sulfur dioxide level).
Nationwide costs are reported in Table 8-13.
16
8-21
-------
Table 8-14. DUAL ALKALI SCRUBBING SYSTEM COSTS BASED
ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III
(Costs Reported in Thousands of Dollars)
CAPITAL COSTSb
Equipment
Construction
Engineering
Total Capital Costs0
ANNUAL COST
Direct Operating Costs
Operating Labor
Maintenance6
Utilities
Soda Ashf
Lime9
Electricity
Water1
Waste Disposal J
Indirect Operating Costs
Tax, Insurance, K
and Administration
Capital Recovery Cost
TOTAL ANNUAL COSTS
EMISSION REDUCTION (Mg S02 removed/
year
COST EFFECTIVENESS ($/Mg of
S02 removed)
2,500 m3/sd
Model Unit
827
451
226
1,504
31
23
8
80
50
1
96
60
198
.547
1,470
372
8,000 m3/sd
Model Unit
1,504
818
404
2,726
61
41
27
248
157
4
301
109
358
1,305
4,710
277
Footnotes are on the next "page.
8-22
-------
Table 8-14. DUAL ALKALI SCRUBBING SYSTEM COSTS BASED ON
1.5 WEIGHT PERCENT SULFUR FE.ED AND REGULATORY
ALTERNATIVE III (Concluded)
lNelson cost indexes were used to adjust costs to fourth quarter 1980
dollars.
References 12, 13.
°The capital costs include 20 percent contingency. Reference 14.
Operating labor cost based on $14.35 per man-hour. Operator labor
requirements are 6 man-hours/day for the small model plant; 12 man-hours
per day for the large model plant. Reference 15.
Maintenance costs are calculated as 1.5 percent of the total capital
costs. Reference 4.
Soda ash costs are based on use of 100 percent soda ash at $100/Mg.
Soda ash requirement for the small unit is 9.07 kg/hour; for the large
model unit, 31.8 kg/hour. References 6, 7, 15.
costs are based on $62/Mg lime. Lime requirement for the small
unit is 149 kg/hr; and 467 kg/hr for the large model unit. Reference 15.
Electricity costs based on $0.0652/kWh. Electricity requirements are
90 kW for the small model unit; 280 kW for the large model unit.
References 4, 15. .
^Water costs are based on $0.0625/m3. Water requirements for the small
model unit are 0.0464 m3/min, for the large model unit, 0.132 m3/min.
References 4, 15. ,
JBased on waste disposal cost of $16.50/Mg. Waste disposal requirements
for the small model unit are 5,831 Mg/year; for the large model unit,
18,271 Mg/year. References 4, 15.
1
Calculated as 4 percent of the total capital cost. Reference 4.
Cost is based on a life of 15 years and 10 percent interest. Capital
recovery cost is calculated by 0.1315 x total capital cost. The vendor
indicates a service life ranging from 15 to 25 years. References 4, 15.
8-23
-------
8.3.2 Wellman-Lord
Capital and annual costs for the Wellman-Lord flue gas desulfurization
system were provided by a vendor for the FCC unit parameters given in
Table 6-2.18~20 Both capital and annual costs for this system are
dependent upon flue gas air flow rates and the degree of sulfur oxides
removal required. As discussed in Section 4.2.6.1, the Hellman-Lord
process consists of two stages. The capital cost for the absorber
stage is dependent upon air flow and the regenerator upon sulfur
oxides removal.18 Itemized costs for the Wellman-Lord system as
applied to FCC units is presented in Table 8-15. These costs are
based on a 1.5 weight percent sulfur feedstock and control to Regulatory
Alternative III, 400 vppm S02.
The Wellman-Lord vendor indicated that the sulfur dioxide recovered
would be further processed at an existing Claus plant for sulfuric
acid or elemental sulfur. Using a mass ratio of 2:1 sulfur dioxide to
elemental sulfur, a product credit was applied to the total annual
costs based on elemental molten sulfur. Credit for particulate control
is also included in the net annual costs; however, it has not yet been
determined whether the venturi scrubber will satisfy the particulate
emissions limit because the system has not been applied to commercial
FCC units.
8.3.3 Citrate FGD System Costs
The capital and annual costs for a citrate flue gas desulfurization
system have been scaled according to the model unit parameters by
applying factors provided by a citrate vendor. The capital costs
for citrate systems are dependent upon the flue gas flow rate and the
flue gas sulfur dioxide concentration for the FCC unit application.
Operating costs for a citrate system are also dependent upon the
amount of sulfur oxides reduction. For example, the citrate system
requires both citric acid and soda ash in amounts which vary with
sulfur dioxide removal from the inlet flue gas.
The citr'ate system recovers elemental sulfur, and hence, this
recovered product is credited to the total annual costs. In addition,
the annual costs of an electrostatic precipitator are credited to the
citrate annual costs because the citrate system venturi scrubber would
provide particulate control. However, vendors caution that it remains
8-24
-------
Table 8-15. WELLMAN-LORD S02 RECOVERY SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III
(Costs Reported in Thousands of Dollars)3
TOTAL CAPITAL COSTS5'0
ANNUAL COSTSd
Direct Operating Costs
Operating Labor6
Maintenance Labor and Supplies
Utilities
Electricity3
Water11
Soda Ash1
Steanr1
Indirect Operating Costs
Tax, Insurance, ^
and Administration
Capital Recovery Cost
TOTAL ANNUAL COSTS
PRODUCT RECOVERY CREDIT1"
ESP CREDIT"
NET ANNUAL COST
EMISSION REDUCTION (Mg S02 removed
/year)
COST EFFECTIVENESS ($/Mg of
SO 2 removed)
2,500 m3/sd
Model Unit
5,000
200
175
65
3
30
203
200
658
1,534
-102
-200
1,232
1,470
838
8,000 m3/sd
Model Unit
8,200
328
287
93
10
96
651
328
1,078
2,871
-327
-330
2,214
4,710
470
Footnotes are on the next page.
8-25
-------
Table 8-15. WELLMAN-LORD S02 RECOVERY SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND
REGULATORY ALTERNATIVE III (Continued)
aNelson cost indexes were used to adjust costs to fourth quarter 1980
dollars except as noted.
Total capital costs include 20 percent contingency. References 17,
19.
GCosts supplied relate to a gas flow of 3030 scmm (8,500 m3/sd unit).
For other gas flows, costs were adjusted according to information
provided by vendor. Reference 18.
Annual costs are determined based on 357 operating days per year.
eBased on 4 percent of total capital cost. Reference 21.
^Based on 3.5 percent of total capital cost. Reference 21*
9Based on small unit electrical requirement of 115.7 kW, large unit
166 kW and electricity cost of $0.0652/kWh. References 4, 18, 20.
Water requirement is the net make-up to the scrubber. For the small
unit, this is 0.098 m3/min, for the large unit 0.314 m3/nin. Water .
cost is $0.0625/m3. References 4, 18, 20.
ash requirement for the large model unit is 0.112 Mg/hr. Requirements
for small model unit are scaled according to respective air flow rates.
Soda ash cost is $100/Mg for 100 percent soda ash. References 4, 18»
20.
^Steam requirements are a function of the quantity of sulfur dioxide
stripped from the evaporator flue gas and were supplied for the large
unit (3030 scmm). Stream requirements for the small unit (950 scmm)
may be determined as the product of the large unit steam requirements
and the ratio of the quantity of sulfur dioxide removed relative to the
large unit. Steam cost is $11.09/Mg. References 4, 18, 20.
h
Tax, insurance, and administration is based on 4 percent of total
capital cost. Reference 4.
'Based on 15-year expected service life and 10 percent interest rate.
The capital recovery cost is calculated as 0.1315 x total capital cost.
Reference 4.
8-26
-------
Table 8-15. WELLMAN-LORD S02 RECOVERY SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED
AND REGULATORY ALTERNATIVE III (Concluded)
m
Product recovery credit is based on the annual reductions in sulfur
dioxide emissions (Mg/yr) from the baseline case and a product recovery
credit of $138.80 per Mg of elemental molten sulfur. Reference 22.
annual costs for an electrostatic precipitator (ESP), are credited
because the system includes a variable throat venturi for flue gas
saturation and particulate control. ESP costs are given in Table 8-23.
Reference 17.
^Calculated from scrubber inlet S02 concentration of 1,400 vppm and
92 percent removal efficiency. Model unit air flow rates are 945 scmm
for the small model unit and 3030 scmm for the large model unit.
8-27
-------
33
unproven whether the venturi will provide adequate participate control
for compliance with the existing FCC unit regenerator NSPS. Itemized
capital and annual costs are reported in Table 8-16.
8.3.4 Spray Drying
Capital and annual costs for spray drying are given in Table 8-17
for model units on a comparable basis as the sodium-based scrubber
costs. Spray drying costs are primarily a function of regenerator
flue gas air flow rates. However, annual costs for this scrubber
system are also determined by the amount of sulfur oxides reduction
required. The costs for waste disposal, electricity, and pebble lime
vary with the level of control.30 The annual costs for an electrostatic
precipitator are credited to the spray drying costs because the system
controls particulate emissions in addition to sulfur dioxide emissions.
8.3.5 Sulfur Oxides Reduction Catalysts Costs
The use of sulfur oxides reduction catalysts as a sulfur oxides
emission control technique has thus far been confined to pilot tests
and a few commercial tests; hence, the available cost information is
limited. Two commercial scale test demonstrations of this control
technology from two 3,500 m3/sd FCC units each processing approximately
1 weight percent feed sulfur incurred a $900/Mg incremental cost for
sulfur oxides emission reduction. 5 The operating cost for the control
additive in these tests was reported to be about $l,400/day or
approximately $0.40/m3 of fresh feed; catalyst cost is $ls800/Mg as
loaded.35 Sulfur oxides reduction catalyst costs of $0.30 to $0.60/m
of fresti feed have been reported. ' Fifth-year nationwide annual
costs for the catalyst technology can be determined using anticipated
FCC unit construction and reconstruction from Tables 7-4 and 7-5 and
the catalyst cost figures from above. The fifth-year nationwide
annual costs of Regulatory Alternatives II through IV calculated this
way are $10 to $20 million, assuming the catalyst technology is applicable
to all model units for each of these alternatives. No capital costs
are anticipated for the catalyst technology. The cost of sulfur
oxides reduction catalysts per amount of sulfur oxides removed can be
calculated by dividing the fifth-year nationwide costs by the emissions
reductions in the fifth year, as reported in Table 7-6. Costs determined
this way are approximately $200 to $400/Mg sulfur oxides removed.
8-28
-------
Table 8-16. CITRATE FGD SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III
(Costs Reported in Thousands of Dollars)3
CAPITAL COSTS
Direct Costs5
Indirect Costs0
Contingency
TOTAL CAPITAL COSTS6
2,500 m3/sd
Model Unit
1,720
616
584
2,920
8,000 m3/sd
Model Unit
2,310
827
784
3,920
ANNUAL COSTS
Direct Operating Costs
Operating Labor
General Maintenance9
Operating Materials
Utilities
Electricity1
WaterJ
Steamk
Waste Disposal
Indirect Operating Costs
Tax, Insurance,
and Administration
Capital Recovery Cost"
TOTAL ANNUAL IZED COSTS
PRODUCT RECOVERY CREDIT0
ESP CREDITP
NET ANNUAL COST
EMISSION REDUCTION .
(Mg S02 removed /year)
COST EFFECTIVENESS ($/Mg of
S02 removed)
260
149
14.3
186
Negligible
349
2.4
117
384
1,460
-298
-200
962
1,470
654
260
149
45.0
415
Negligible
781
7.5
157
515
3,330
-940
-330
1,060
4,710
225
Footnotes are on the next page.
8-29
-------
Table 8-16. CITRATE FGD SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III (continued)
^telson cost indexes were used to adjust costs to fourth quarter 1980
dollars except as noted.
3Based on 2.18 x major equipment cost. Major equipment costs were
calculated based on a citrate installation which incurred a major
equipment cost of $1.3 million (January 1, 1979, dollars). Major
equipment costs for citrate FGD were adjusted using the following
equation:
Major Equipment Cost =
°'45 x
.7
.7
4.80 scmm
2500 ppm
x 1,177
Where: a = design flue gas flow rate of citrate systerri being
costed, scmm
b - flue gas
ppm
concentration of system being costed,
1.177 = escalation factor to adjust to fourth quarter 1980
dollars. References 4, 23, 24.
cBased on 0.78 x the major equipment cost. The indirect costs include
engineering costs as 14 percent of the total capital costs. Reference 4.
Based on 20 percent of total capital cost. Reference 4.
Represents 3.7 x major equipment costs. References 4, 23, 24.
Model unit labor hour requirement is 17,136 man-hours per year for
operators and 1,017 man-hours per year for supervisors. Labor cost is
$14.35 per man-hour. References 25, 26.
CBased on labor requirement of 5,200 man-hours per year, $14.35 per
man-hour, and material as 100 percent of maintenance labor. Reference 4,
25.
Operating materials include citric acid and soda ash. Small model unit
requires 5.1 Mg/yr of citric acid and 61.8 Mg/yr of soda ash. Large
model unit requires 16.3 Mg/yr of citric acid and 195 Mg/yr of soda
ash. Citric acid cost is $l,570/Mg and soda ash cost is $100/Mg.
References 6, 7, 27, 28.
8-30
-------
Table 8-16. CITRATE FGD SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III (continued)
Electricity cost is $0.0652 per kWh. Basis for electricity requirement
was calculated using the following equation:
electricity required (kWh x 106) = 8.2 x 106 4 ^QQ °'7
Where a = gas flow of citrate system being costed, scmm
References 4, 23, 28.
JBasis for water requirement for non-water cooled citrate system was
given as 151 m3 per year, for an annual expenditure of $9.50. Water
cost is $0.0625 per m3. References 4, 25.
k
Based on sulfur flow being the major determinant of steam consumption,
79,600 Mg of steam consumed per year for a citrate system recovering
8,100 Mg of sulfur per year, and assuming a relationship for relating
different amounts of sulfur recovered the same as for sulfur concentrations
in footnote b for major equipment costs; steam consumption was calculated
using the following equation:
Steam Required = 79,600 Mg
Mg
Where: a = kg of sulfur recovered for citrate system whose steam
requirement is being determined. Small model unit =
2,141 Mg; large model unit = 6,776 Mg.
References 23, 28.
1
The only major waste product is crystalline sodium sulfate, Glauber's
salt. The basis for the waste disposal requirements is the assumption
that the ratio of Glauber's salts produced to sulfur recovered is
constant, 67.4 kg Glauber's salt per Mg sulfur recovered. Therefore,
requirements are: small model unit (2,141 Mg per year recovered
sulfur) = 144.3 Mg per year waste; large model unit (6,776 Mg per
year recovered sulfur) = 456.7 Mg per year waste. Waste disposal
cost is $16.50 per Mg. References 23, 28.
m
Based on 4 percent of total capital cost. Reference 4.
nBased on an expected service life of 15 years and an interest rate of
10 percent. Capital recovery cost is calculated by 0.1315 x (total
capital cost). Reference 4.
8-31
-------
Table 8-16. CITRATE FGD SYSTEM COSTS
BASED ON 1.5 WEIGHT PERCENT SULFUR FEED AND REGULATORY
ALTERNATIVE III (concluded)
°Product recovery credit for elemental molten sulfur is based on $138.3 per
Mg. Amount of recovered product is 2,141 Mg per year for the small
model plant and 6,776 Mg per year for the large model plant.
References 22, 28.
^Costs of an electrostatic precipitator (ESP) are credited because a
typical citrate system recovering elemental sulfur utilizes a venturi
scrubber; however, vendors caution that it remains unproven whether the
citrate FGD will provide complete particulate control. ESP costs are
given in Table 8-19. Reference 29.
8-32
-------
Table 8-17. SPRAY DRYING COSTS BASED ON 1.5 WEIGHT PERCENT
SULFUR FEED AND REGULATORY ALTERNATIVE III
(Costs Reported in Thousands of Dollars)
TOTAL CAPITAL COSTS5
Direct Operating Costs
Operating Labor
Maintenance Labor0
Replacement Material
Utilities
Pebble Lime6
Electricity
Water9
Waste disposal
Indirect Operating Costs
Tax, Insurance, and Administration
Capital Recovery CostJ
TOTAL ANNUAL COSTS
ESP CREDITk
NET ANNUAL COST
EMISSION REDUCTION (Mg S02 Removed/year)
COST EFFECTIVENESS ($/Mg of S02 Removed)
2,500 m3/sd
Model Unit
1,780
29.8
29.8
35.6
110
112
1.8
68.4
71.2
234
693
-200
493
1,470
335
8,000 m3/sd
Model Unit
4,720
29.8
29.8
94.4
344
335
6.1
217
189
621
1,866
-330
1,536
4,710
326
Footnotes are on the next page.
8-33
-------
Table 8-17. SPRAY DRYING COSTS BASED ON 1.5 HEIGHT PERCENT
SULFUR FEED AND REGULATORY ALTERNATIVE III (Concluded)
aNelson cost indexes were used to adjust costs to fourth quarter 1980
dollars.
bCapital costs include contingency costs of 20 percent, although vendor
estimates may include only 5-10 percent contingency. Depending upon
specifications (i.e., standards for motors, pumps, vessel thickness,
etc.) actual total capital costs may vary by 15-20 percent.
References 30, 31.
cBased on 1 man-year per unit (2,080 hours per man-year) and labor
charge of $14.35. Reference 30.
dBased on 2 percent of total capital cost. Reference 30.
eBased on pebble lime requirements of: 2,500 m3/sd unit = 5,99 Mg/day
(6.6 ton/day), 8,000 ra^/sd unit = 18.78 Mg/year (20,7 ton/day). The
cost of pebble lime is $42.18 Mg ($46.50/toh). References 30, 32.
fBased on electricity requirements of: 2,500 m3/sd unit F 200 kW; 8,000 m3/sd
unit = 6QO kW. Annual electricity requirements of: 2,5pO m3/sd unit =
1,713,600 kWh; 8,000 m3/sd unit - 5,140,800 kWh, Electricity cost =
$0.0652/kWh. 'References 4, 30,
9Based on water requirements of: 2,500 m3/sd unit = 29,,190 m3/yr; 8,000 m3/sd
unit = 97,290, water cost = $0.0625/m3. References 4, 3Q.
hBased on waste disposal cost of $16.50/Mg. W§ste disposal requirements
are: 2,500 m3/sd unit = 4,148 Mg/yr; 8,000 m3/sd unit = 13,126 Mg/yr.
References 4, 33.
^Calculated as 4 percent of the total capital cost. Reference 4.
JCost is based on a 15-year life and 10 percent interest. -Capital
recovery cost is calculated as 0.1315 x total capital cost. Reference 4.
^The annual costs for an electrostatic precipitator are credited to the
spray drying costs because particulate emissions are controlled in
addition to S02 emissions. Reference 33.
8-34
-------
8.4 OTHER COST CONSIDERATIONS
The cost impacts have thus far been discussed exclusively with
reference to sulfur oxides. However, other factors affect the costs
to the industry in applying control technology to meet the levels of
control specified under the regulatory alternatives. Compliance with
several existing environmental, safety, and health statutes impose
other costs on the refining industry. A summary of these statutes are
listed in Table 8-18.
Although specific costs to the industry to comply with most of
the provisions, requirements, and regulations of the existing statutes
are unavailable, few refineries are expected to close solely due to
the cost of compliance with the standards. However, the total costs
may accelerate closings prompted from changing crude supplies and
37
product demand.
The costs incurred by the petroleum refining industry to comply
with all health, safety, and environmental regulations are not expected
to prevent compliance with the regulatory alternative for sulfur
oxides emissions from FCC unit regenerators. Nevertheless, they will
likely impact the choice of control techniques refiners will employ to
meet the regulatory alternatives. This is evidenced in that flue gas
desulfurization, which forms the basis of the costs for the regulatory
alternatives, simultaneously offers the refiner the benefit of particulate
emission reduction required by the existing FCC unit particulate
emission NSPS. However, should a refiner choose to utilize hydrode-
sulfurization or sulfur oxides reduction catalysts for sulfur oxides
control, additional costs would be incurred to control particulate
emissions. Table 8-19 provides capital and annualized electrostatic
precipitator costs incurred to control particulate emissions. *
8-35
-------
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-------
Table 8-19. ELECTROSTATIC PRECIPITATOR
(Fourth Quarter 1980 Dollars)
COSTS
Cost Terms
CAPITAL COSTS
Equipment Costs
Control Device
Auxiliaries0
Instruments and Controls
Taxes and Freight6
Installation Costs
Total Capital Costs
ANNUAL COSTS
Direct Costs
Operating Labor^
General Maintenance
Replacement Parts1
Utilities'3
Waste Disposal
Total Direct Costs
Indirect Costs
Overhead
Property Tax, Insurance, and
Administration
Capital Recovery Cost"
Total Indirect Costs
Total Annual ized Costs
2,500 m3/sd Unit
261,000
34,800
29,600
23,600
492,000
841,000
16,100
16,800
660
9,250
6,430
49,200
19,600
33,600
98,800
152,000
201,000
8,000 m3/sd Unit
435,000
65,200
50,000
40,000
832,000
1,422,000
16,100
16,800
1,110
29,700
20,600
84,300
19,600
56,900
167,100
244,000
328,000
Footnotes are on the next page.
8-37
-------
Table 8-19. ELECTROSTATIC PRECIPITATOR COSTS (Concluded)
Cost indexes were used to bring costs to fourth quarter 1980 dollars.
References 1, 39, 40.
Removal efficiency = 95 percent; drift velocity = 0.076 m/sec; plate
area for the 2,500 m3/sd unit = 1,000 m2, for the 8,000 m3/sd unit =
3,200 m2; air flow for the 2,500 m3/sd unit = 27 m3/sec, for the
8,000 m3/sd unit = 87 m3/sec. Reference 38.
Auxiliaries include bypass ducting: 19.7 m length, 127 cm diameter,
6.4 mm carbon steel, insulated; 2 elbows 6.4 mm carbon steel, insulated;
2 expansion joints; 2 round dampers with automatic controls; and a 23
cm x 4.5 m screw conveyor. References 4, 41, 42.
dlnstrument and controls calculated as 10 percent of control device
and auxiliary equipment cost. Reference 4.
eTaxes and freight calculated as 8 percent of control device and
auxiliary equipment cost. Reference 4.
f Includes indirect and direct installation costs and 20 percent contingency
calculated as 141 percent of purchased equipment cost. Reference 4.
^Includes operator and supervisor costs. Operating labor costs are
based on 1.25 operator man-hours per shift, 3 shifts per day, 365 days
per year and $10.25 per man-hour. Supervisor labor costs are included
by adding 15 percent to the operator costs. Reference 4.
Includes labor and material costs. Maintenance labor costs are based
on 0.75 man-hours per shift, 3 shifts per day, 365 days per year, and
$10.25 per man-hour. Material costs are equal to 100 percent of
maintenance labor costs. Reference 4.
on 0.078 percent of total capital costs. Reference 43.
JBased on 0.135 watts/m2 plate area, 8,760 hours per year, $0.0652 per
kWh, and 1,000 m2 plate area for the small ESP and 3,200 m2 plate
area for the large ESP. Reference 4.
kCost to remove waste is based on $16.50/metric ton. Cost from Reference 4,
updated to September 1980, see Reference 3.
Overhead calculated as 80 percent operating labor and maintenance
(labor only). Reference 4.
mCalculated as 4 percent of total installed capital cost. Reference 4.
"Capital recovery cost based on 20 years operating life, and 10 percent
annual interest rate. Capital recovery factor = 0.1175. Reference 4.
8-38
-------
8.5 REFERENCES
1.
Nelson Cost Indexes. Oil and Gas Journal.
1981. Docket Reference Number II-I-90.*
79(14):147. April 6,
4.
7.
Letter and Attachments from Cunic,
-------
12. Letter from Czuchra, P.A., FMC Corporation, to Bernstein, G.,
Pacific Environmental Services, Inc. July 15, 1981. Response to
request for dual alkali scrubber cost information. Docket Reference
Number II-D-58.*
13. Telecon. Czuchra, P.A., FMC Corporation, with Osbourn, S., Pacific
Environmental Services^ Incorporated. December 14, 1981. Dual
alkali scrubber costs. Docket Reference Number II-E-5.*
14. Telecon. Czuchra, P.A., FMC Corporation, with Rhoads, T.W.,
Pacific Environmental Services, Incorporated. February 23, 1982.
Dual alkali scrubber costs. Docket Reference Number II-E-5.*
15. Telecon. Czuchra, P.A., FMC Corporation, with Osbourn, S., Pacific
Environmental Services, Incorporated. January 13, 1982. Dual
alkali scrubber costs. Docket Reference Number II-E-5.*
16. Telecon. Czuchra, P.A., FMC Corporation, with Rhoads, T., Pacific
Environmental Services, Inc. August 12, 1981. Clarification of
dual alkali scrubber costs and particulate control. Docket Reference
Number II-E-5.*
17. FCC Emission Control by the Wellman-Lord and Davy Saaberg-Hoelter
FGD Processes. Submitted to the U.S. Environmental Protection
Agency by Davy McKee Corporation, March 1981. Docket Reference
Number II-A-14.*
*18. Letter and attachments from Pedroso, R.I., Davy McKee Corporation
to RhoadSi T.W., Pacific Environmental Services, Incorporated.
February 24, 1982. Docket Reference Number II-D-92.*
19. Telecon. Pedroso, R., Davy McKee Corporation, with Rhoads, T.W.,
Pacific Environmental Services, Incorporated. March 2, 1982.
Docket Reference Number II-E-5.*
20. Telecon. Pedroso, R., Davy McKee Corporation, with Osbourn, S.,
Pacific Environmental Services Incorporated. March 8, 1982.
Docket Reference Number II-E-5.*
21. Demonstration of Wellman-Lord/Allied Chemical FGD Technology:
Demonstration Test, First Year Results. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. Publication No. EPA-600/7-79-014b.
September 1979. pp. 2-1 to 2-6. Docket Reference Number II-A-25.*
22. Chemical Marketing Reporter. January 4, 1982. Price for elemental
molten sulfur. Docket Reference Number II-1-98.*
23. Telecon. Madenburg, D., Morrison-Knudsen, with Meardon, K.,
Pacific Environmental Services, Incorporated. January 6, 1982.
Citrate costs. Docket Reference Number II-E-5.*
24. Telecon. Madenburg, D., Morrison-Knudsen, with Rhoads, T.W.,
Pacific Environmental Services, Incorporated. March 4, 1982.
Citrate costs. Docket Reference Number II-E-5.*
8-40
-------
25. Telecon. Madenburg, D., Morrison-Knudsen, with Meardon, K.,
Pacific Environmental Services, Incorporated. January 7, 1982.
Citrate costs. Docket Reference Number II-E-5.*
26. Telecon. Nissen, B., U.S. Bureau of Mines, with Meardon, K.
Pacific Environmental Services, Incorporated. February 11, 1982.
Citrate costs. Docket Reference Number II-E-5.*
27. Chemical Marketing Reporter. January 4, 1982. Price for citric
acid. Docket Reference Number II-I-98.*
28. Telecon. Nissen, B., U.S. Bureau of Mines, with Meardon, K.
Pacific Environmental Services, Inc. January 12, 1982. Citrate
costs. Docket Reference Number II-E-5.*
29. Telecon. Haminishi, H., Morrison-Knudsen, with Rhoads, T.W.,
Pacific Environmental Services, Inc. March 3, 1982. Citrate
scrubber information. Docket Reference Number II-E-5.*
30. Letter and attachments from Petti, V.J., Wheelabrator-Frye, Inc.,
to Rhoads, T.W., Pacific Environmental Services, Inc. February
12, 1982. Dry scrubbing capital and operating cost parameters for
catalytic cracking towers. Docket Reference Number II-D-88.*
31. Telecon. Petti, V.J., Wheelabrator-Frye, Inc., with Rhoads, T.W.,
Pacific Environmental Services, Inc. March 3, 1982. Spray drying
costs. Docket Reference Number II-E-5.*
32. Telecon. Thigpen, E., Ashland Chemical, with Rhoads, T.W., Pacific
Environmental Services, Inc. February 22, 1982. Pebble lime
cost. Docket Reference Number II-E-6.*
33. Telecon. Petti, V.J., Wheelabrator-Frye, Inc., with Rhoads, T.W.,
Pacific Environmental Services, Inc. March 1, 1982. Spray drying
information. Docket Reference Number II-E-5.*
34. Trip Report. Standard Oil of Indiana (Amoco). Chicago, Illinois.
April 1, 1980. Sulfur Reduction Catalyst Costs. Docket Reference
Number II-B-1.*
35. Letter and attachments from Buffalow, O.T., Chevron, U.S.A.,
Incorporated, to Goodwin, D., U.S. Environmental Protection Agency.
June 29, 1981. Response to Section 114 letter on FCC unit alterations
and expansions. Docket Reference Number II-D-57.*
36. Davis, J.C. FCC Units Get Crack Catalysts. Chemical Engineering.
84(11):79. June 6, 1977. Docket Reference Number II-1-92.*
37. Economic Impact of EPA's Regulations on the Petroleum Refining
Industry. Part III - Economic Analysis. EPA-230/3-76-004. April
1976. Docket Reference Number II-A-1.*
8-41
-------
38. Air Pollution Engineering Manual. Second Edition. U.S. Environmental
Protection Agency. Research Triangle Park, North Carolina.
Publication No. AP-40. ~p. 154. May 1973. Docket Reference
Number II-I-ll.*
39. Nelson Cost Indexes. Oil and Gas Journal. 79(22):117. June 1,
1981. Docket Reference Number 11-1-91.*
40. Nelson Cost Indexes. Oil and Gas Journal. ^7J>(14):147. April 3,
1978. Docket Reference Number 11-1-38.*
41. Telecon. Bump, B., Research Cottrell-Air Pollution Division, with
Rhoads, T.W., Pacific Environmental Services, Inc. December 17,
1981. Application of electrostatic precipitators to FCC units.
Docket Reference Number II-E-5.*
42. Peters, Max S. and Klaus P. Timmerhaus. plant Design and Economics
for Chemical Engineers, 2nd Edition. McGraw-Hill Book New York.
1968. p. 110. Docket Reference Number JI-I-95.*
43. Katarl, V., L, Yveino, E. Schindler, and T.W. Devitt. PEDCo,
Cincinatti, Ohip. Evaluation of Partiqi(late Matter Control Equipment
for Copper Semlters. U.S. Environmental Protection Agency, Region IX.
publication NO. 909/78-001. Docket Reference Number Il-A-24.*
44. Memorandum from Rhoads, T.W,, Pacific Environmental Services,
Inc., to Docket A-79-09. April 27, 1982. Electrostatic precipitator
costs for fluid catalytic cracking model units. Docket Reference
Number II-B-24.*
45. Memorandum from Hustvedt, K.C., U.S. Environmental Protection
Agency, to Durham, J.F., U.S. Environmental Protection Agency.
May 24. 1982. Cost and emission reductions for full scrubbing.
Docket Reference Number II-^B-27.*
*References can be located in Docket Number A-79-09 at the U.S. Environmental
Protection Agency's Central Docket Section, West Tower Lobby,
Gallery 1, Waterside Mall, 401 M Street, S.W., Washington, D.C. 20460.
8-42
-------
9.0 ECONOMIC IMPACT
9.1 INDUSTRY CHARACTERIZATION
9.1.1 General Profile
9.1.1.1 Refinery and Catalytic Cracking Capacity. On January 1, 1980,
there were 311 petroleum refineries operating in the United States and Puerto
Rico with a total crude capacity of over 3 million m^ per steam day.l Of
those refineries 128 operated fluid catalytic cracking (FCC) units with a
combined fresh feed capacity of more than .8 million m^ per stream day.l
Like overall refinery capacity, over 50 percent of FCC capacity is located in
three states: Texas (28%), Louisiana (15%), and California (10%). Table 9-1
summarizes FCC capacity by state, company, and location.
Approximately 30 to 40 percent of the liquids processed by a petroleum
refinery pass through the FCC unit. Catalytic cracking is used by the
refiner to produce motor fuels and blending stocks from the heavier portions
of crude oil, by catalytically splitting the large hydrocarbon molecules in
heavy gas oil feedstocks into smaller molecules. Catalytic cracking is
also used to increase the yield and quality of gasoline blending stocks and
middle distillate fuels.
It should be noted that in the production and capacity tables that fol-
low, a distinction is often made between stream days (i.e., sd) and calendar
days (i.e., cd). The basic difference between the two terms is that "stream
days" refers to the maximum capacity of a refinery or unit on a given operat-
ing day, while "calendar day" production represents the average daily produc-
tion over a one-year period. Since most refineries do not operate 365 days
each year, stream day numbers are always slightly larger than those for
calendar days.
9.1.1.2 Refinery Production. In terms of total national output, the
percentage yields of various refined petroleum products have remained con-
stant over recent years, although several exceptions are noted below. The
9-1
-------
Table 9-1. REFINERIES WITH FLUID CATALYTIC
CRACKING UNITS (FCCU) 1980*
Company and Refining Location
Fresh Feed Capacity
Recycle
(m3/Sd)
ARKANSAS
Tosco Corp. - El Dorado 2,466
CALIFORNIA
Atlantic Richfield Co. - Carson 8,909
Chevron U.S.A. Inc. - El Segundo 8,273
Chevron U.S.A. Inc. - Richmond 10,023
Exxon Co. U.S.A. - Benecia 7,795
Gulf 011 Co. U.S. - Santa Fe Springs 2,148
Mobil Oil Corp. - Torrance 9,545
Powerine Oil Co. - Santa Fe Springs 1,941
Shell Oil Co. - Martinez 9,545
Shell Oil Co. - Wilmington ' 5,564
Texaco Inc. - Wilmington 4,452
Tosco Corp. - Avon 7,472
Union Oil of California - Wilmington 7,154
COLORADO
Asamera Oil Inc. - Commerce City -1,097
DELAWARE
Getty Refining and Marketing Cp. - Delaware
City 9,857
HAWAII
Chevrqn U.S.A. Inc. - Honolulu 3,498
ILLINOIS
Amoco Oil Co. - Wood River 6,359
Clark Oil & Refining-Corp. - Blue Island 4,134
Clark Oil & Refining Corp. - Hartford 4,452
Marathon Oil Co. - Robinson '. • 6,041
Mobil Oil Corp. - Joliet ' 15,103
Shell Oil Corp. - Wood River 14,944
Texaco Inc. - Lawrenceville 5,405
Texaco Inc. - Lockport 4,769
Union Oil Co. of Calif. - Lemont 9,221
INDIANA
Amoco Oil Co. - Whiting 22,258
Energy Cooperative Inc. - East Chicago 7,154
Indiana Farm Bureau Cooperative Association,
Inc., - Mount Vernon • 1,113
Rock Island Refining Corp. -'Indianapolis 2,703
KANSAS
CRA, Inc. - Cofferyville 2,941
CRA, Inc. - Phillipsburg 1,351
Getty Refining and Marketing Co. - El Dorado 4,928
National Cooperative Refinery Association -
McPherson 3,180
Pester Refining Co. T El Dorado 1,749
Phillips Petroleum Co. - Kansas City 5,326
Total Petroleum Inc. - Arkansas City 2,607
KENTUCKY
Ashland Oil Inc. - Catlettsburg 9,857
Ashland Oil Inb. - Louisville 1,510
123
1,272
1,749
48
48
795
1,113
16
2,385
318
159
159
64
795
1,590
• 795
238
127
2,703
636
2,655
9-2
-------
Table 9-1. (Continued)
Company and Refining .Location
rresn f-eed Capacity
Recycle
(m3/Sd)
LOUISIANA
Cities Service Co. - Lake Charles
Conoco - Westlake
Exxon Co. U.S.A. - Baton Rouge
Good Hope Industries Inc. - Good Hope
Gulf Oil Co. U.S. - Belle Chasse
Marathon Oil Co. - Garyville
Murphy Oil Corp. - Meraux
Placid Refining Co. - Port Allen
Shell Oil Co. - Norco
Tenneco Oil Co. - Chalmette
Texaco Inc. - Convent
MICHIGAN
Marathon Oil Co. - Detroit
Total Petroleum Inc. - Alma
MINNESOTA
Ashland Oil Inc. - St. Paul Park
Conoco - Wrenshall
Koch Refining Co. - Rosemont
MISSISSIPPI
Chevron U.S.A. Inc. - Pascagoula
MISSOURI
Amoco Oil Co. - Sugar Creek
MONTANA
Conoco - Billings
Exxon Co. U.S.A. - Billings
Farmers Union Central Exchange Inc. - Laurel
Phillips Petroleum Co. - Great Falls
NEBRASKA
CRA, .Inc. - Scottsbluff
NEW JERSEY
Exxon Co. U.S.A. - Linden
Texaco Inc. - WestviTle
NEW MEXICO
Navajo Refining Co. - Artesia
Plateau Inc. - Bloomfield
Shell Oil Co. - Gallup
NEW YORK
Ashland Oil
Inc. - Buffalo
NORTH DAKOTA
Amoco Oil Co. - Mandan
OHIO
Ashland Oil Inc. - Canton
Gulf Oil Co. U.S. - Cleves
Gulf Oil Co. U.S. - Toledo
Standard Oil Co. of Ohio - Lima
Standard Oil Co. of Ohio - Toledo
Sun Co. Inc. - Toledo
23,847
4,865
25,437
10,334
14,149
11,924
5,612
2,623
15,898
3,577
6,677
4,293
2,544
3,498
1,510
8,426
8,903
6,677
2.385
3,339
1.908
334.
382
21,463
6,359
890
874
1,145
3,498
4,134
4,134
2,862
3,148
5,994
8,744
7,949
336
2,226
159
' 159
318
207
159
318
1,908
79
1,590
477
199
79
4,769
64
79
572
827
318
318
1,240
2,623
1,192
9-3
-------
Table 9-1. (Continued)
Fresh
Company and Refining Location
OKLAHOMA
Champlin Petroleum co. - Enid
Conoco - Ponca City
Hudson Refining Co. Inc. - Cushing
Kerr McGee Corp. - Wynnewood
Oklahoma Refining Co. - Cyril
Sun Co. Inc. - Duncan
Sun Co. Inc. - Tulsa
Texaco Inc. - Tulsa
Vickers Petroleum Corp. - Ardnore
PENNSYLVANIA
BP Oil Corp. - Marcus Hook
Gulf Oil Co. U.S. - Philadelphia
Sun Co. Inc. - Marcus Hook
United Refining Co, - Warren
TEXAS (Inland)
American Petrofina Co. of Texas •* Big Spring
Chevron U.S.A. Inc. - El Paso
Diamond Shamrock Corp. - Sunray
La Gloria Oil and Gas Co. - Tyler
Phillips Petroleum Co. - Borger
Shell 011 Co. - Odessa
Texaco Inc. - Amarillp
Texaco Inc." - El Paso
Winston Refining Co. - Forth Worth
TEXAS (Gulf)
American Petrofina Co. of Texas - Port Arthur
Amoco 0^1 Co. - Texas. City
Atlantic Richfield Co. - Houston
Champlin Petroleum Co. - Corpus- Christi
Charter International Oil Co. - Houston
Coastal States Petroleum Co. - Corpus Christi
Crown Central Petroleum Corp. - Pasedena
Exxon Co. U.S.A. - Baytown
Gulf Oil Co. U.S. - Port Arthur
Marathon Oil Co. - Texas City
Mobil Oil Corp. - Beaumont
Phillips Petroleum Co. - Sweeney
Shell Oil Co. - Deer-Park
Southwestern Refining Co. Inc.-Corpus Christi
Sun Co. Inc. - Corpus Christi
Texaco Inc. - Port Arthur
Texas City Refining Inc. - Texas City
Union Oil Co. of California - Nisderland
UTAH
Amoco Oil Co. - Salt Lake City
Chevron U.S.A. Inc. - Salt Lake City
Plateau Inc.- Roosevelt
Peed Capacity
(m3/Sd)
3,100
7,154
1,192
3,180
1,113
3,975
4,769
2,862
3,418
7,631
13,450
11,924
1,908
3,657
3,498
5,16?
1,590
8,267
1,669
1,27*
1,113
556
5,405
29,253
12,401
10,970
7,313
3,021
7,949
27,027
19,078
6,041
15,739
5,882
11,129
1,908
3,975
21,463
6,359
6,041
2,862
2;862
827
• Recyc 16
(m3/Sd)
48
-
-
64
159
1,669
223
-
159
254
1,033
2.385
32
-
-
-
795
1,653
874
• -
-
238
318
5,246
795
-
•'
-
-
2,385
954
159
-
827
-
Ill
1,033
-
-
636
636
. 159
*
VIRGINIA
Amoco Oil Co. - Yorktown
WASHINGTON
Shell Oil Co. - Anacortes
Texaco Inc. - Anacortes
WISCONSIN
Murphy Oil Corp. - Superior
4,452
5,723
4,769
1,510
795
2,703
159
9-4
-------
Table 9-1. (Continued)
Company and Refining Location
rresn reeo capacity
(m3/Sd) • . /
xecyc i e
WYOMING
Amoco Oil Co. - Casper 2,067
Husky Oil Co. - Cheyenne 1,590
Husky Oil Co. - Cody 604
Sinclair 011 Corp. - Sinclair 3,339
Texaco Inc. - Casper 1,113
PUERTO RICO
Caribbean Sulf Refining Corp. - Bayamon 1,033
Commonwealth Oil Refining Co., Inc.-Panuelas 6,359
TOTAL 809.709
238
397
181
Reference 1, pp. 24-36.
9-5
-------
percentage yields of refined petroleum products 'from crude oil for the years
1969 through 1978 are summarized in Table 9-2, while Table 9-3 notes the
average daily output of the major products.
Anong the major products of U.S. refineries are gasoline and distillate
fuel o'il, accounting for about 44 and 22 percent of total refinery output
respectively. Other products of refineries are residual fuel oil, jet fuel,
and petrochemical feedstocks.
Through the 1970's residual fuel oil and petrochemical feedstocks have
accounted for increasing shares of total refinery output. These increases
can be traced to the use of residual fuel oil in industrial applications and
the growth in petrochemical markets due to the increased production of
synthetic rubber, fibers, plastics, and other materials manufactured from.
petrochemicals. The increased output of residual fuel oil and petrochemicals
have been balanced by declining output of gasoline and kerosene.
9.1.1.3 Refinery Ownership, Vertical and Horizontal Integration. A
large portion of domestic refining capacity is owned and operated fay large,
vertically integrated oil companies, both domestic and international. The
remainder is controlled by independent refiners such as Charter, Crown
Central Petroleum, Holly, Tosco, and United Refining.
Table 9-4 lists twenty companies with the greatest capacity to process
crude oil. Based" upon the capacities noted, and a total domestic capacity of
3,005,000 m3 per stream day,1 the 4- and 8-firm concentration ratios are
29 and 48 percent, respectively. Since there are currently 158 companies1
engaged in refinrng activities, these ratios are indicative of a high degree
of ownership concentration of refinery capacity.
Refinery ownership is but one aspect of the vertical integration of the
major oil companies. Such companies are integrated "backward" in that they
- own or lease crude oil production facilities, both domestic and international,
as well as the'means to transport crude by way of pipeline and tankers. On
the other hand, "forward" integration is less extensive in that most retail
outlets are operated by franchise agreements as noted below.
With regard to transportation by pipeline, the major oil companies
have been the main source of capital for the construction and operation of
9-6
-------
Table 9-2. PERCENTAGE VOLUME YIELDS OF REFINED PETROLEUM PRODUCTS
FROM CRUDE OIL IN THE U.S. I971-1978a
Product
Motor Gasol ine
Jet Fuel
Ethane
Liquefied Gases
Kerosene
Distillate Fuel Oil
Residual Fuel Oil
Petrochem. Feedstocks
Special Naphthas
Lubricants
Wax
Coke
Asphalt
Road Oil
Still Gas
Miscellaneous
Processing Gain
Total
1971
46
7
0
2
2
22
6
2
0
1
0
2
3
0
.2
.4
.2
.9
.1
.0
.6
.7
.7
.6
.2
.6
.8
.2
. 3.8
0
- 3
'100
.4
A
.0
1972
46.2
7.2
0.2
2.8
1.8
22.2
6.8
2.9
0.7
1.5
0.1
2.8
3.6
0.2
3.9
0.4
- 3.3
100.0
1973
45.6
6.8
0.2
2.8
1.7
22.5
7-7
2.9
0.7
1.5
0.2
2.9
3.6
0.2
3.9
0.4
- 3.6
100.0
1974
45
6
0
2
1
21
8
3
0
1
0
2
3
0
3
0
- 3
100
.9
.8
.1
.6
.3
.8
.7
.0
.8
.6
.2
.8
.7
.2
.9
.5
^9
.0
1975
46
7
0
2
1
21
9
2
0
1
0
2
3
0
3
0
- 3
100
.5
.0
.1
.4
.2
.3
.9
.7
.6
.2
.1
.8
.2
.1
.9
.7
J_
.0
1976
45.5
6.8
0.1
2.4
1.1
21.8
10.3
3.3
0.7
1.3
0.1
2.6
2.8
0.0
3.7
1.0
- 3.5
100.0
1977
43.4
6.6
0.1
2.3
1.2
22.4
12.0
3.6
0.6
1.2
0.1
2.5
2.9
0.1
3.6
1.0
- 3.6
100.0
1978
44.1
6.6
0.1
2.3
1.2
22.4
12.0
3.6
0.6
1.2
0.1
2.5
2.9
0.1
3.6
1.0
- 3.6
100.0
Reference 2.
9-7
-------
Table 9-3. PRODUCTION OF PETROLEUM PRODUCTS AT UNITED STATES REFINERIES
1969-19783
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Motor
Gasoline
872
909
951
1,000
1,039
1,011
1,037
1,088
1,118
1,140
Distillate
Fuel Oil
370
391
397
419
449
424
422
465
521
501
Residual
Fuel Oil
116
112
120
127
154
170
197
219
279
266
Jet Fuel
140
131
133
135
137
133
138
146
155
155
Kerosene
45
42
38
35
35
25
24
24
27
24
NGL and LRG&
54
55
57
57
60
54
49
54
56
—
Reference 2. Section VII. Tables 5, 6, 6a, 7* 7a, 14, 15, 16, 16a,
17, and 17a.
Natural Gas Liquids; LRG = Liquefied Refinery Gases.
9-8
-------
Table 9-4. REFINERY FACILITIES OF MAJOR COMPANIES2
Company
Exxon
Chevron
Amoco
Shell
Texaco
Gulf
Mobil
ARCO
Marathon
Union Oil
Sun
Sohio/BP
Ashland
Phillips
Conoco
Coastal States
Cities Service
Champ! in
Tosco
Getty
Number of
Refineries
5 : •
12 '
10
8
12 :
7 -
7
4
4
4
5
3
7
5
7
3
1
3
3
2
Crude Capacity
(1,000 m3/Cd)
251
233
197
183
168
145
142
133
93
78
77
72
73
68
58
47
46
38
• 35
35
Reference 3, p. 075.
9-9
-------
these facilities, due largely to the huge investments required. On the other
hand, tanker ownership is divided among the major oil companies and indepen-
dent operators who charter tankers to oil companies and traders.4 The pre-
sence of independent tanker operators is a result of relatively small finan-
cial requirements, compared to pipeline ownership.
While many of the low-volume refinery products are marketed directly
by the refiners themselves, the sale of gasoline on the retail level is
handled primarily by franchised dealers and independent operators. The major
refiners do, however, have a high degree of control over the distribution of
..their products with regard to market area. This is so since the major refin-
ers select .sites for the construction of service stations before the facili-
ties are leased to independent operators under franchise agreements. The
major refiners do maintain the direct operation of some service stations for
purpose of measuring the strength of the retail market. However, no more
than 5 percent of all facilities in operation are managed in this fashion.5
Many of the firms that operate refineries, notably the larger oil
companies, are diversified as well as vertically integrated. A natural
area of diversification for refiners is the manufacture of petrochemicals
and resins. Among the firms that have interests in these areas are: .Clark
Oil and Refining, Getty Oil, Occidental Petroleum, and Phillips Petroleum."
Ashland Oil's construction division operates the largest highway paving
company as well as two shipyards-. Exxon Enterprises develops and manufac-
tures various high-technology products. The Kerr-McGee Corporation is the
largest supplier of.commercial grade^uranium for electricity generation and
also manufactures" agricultural and industrial chemicals. Mobil Oil Corp. is
owned by Mobil Corp. which owns both Montgomery Ward and Co. and The Container
Corporation of America. The Charter Co., the largest of the independent
refiners, is also engaged in broadcasting, insurance, publishing, and commer-
cial printing.
g.1.1.4 Refinery Employment and Wages. Total employment at domestic
petroleum refineries has grown steadily since the mid-19601s, with minor
disruptions due to the recessions of 1970 and 1974. As Table 9-5 demon-
strates, there were 163 thousand workers employed at refineries in 1978.6
With 289 refineries operating that year,7 average employment at each refinery
is approximately 564 persons.
9-10
-------
Table 9-5. EMPLOYMENT IN PETROLEUM AND NATURAL GAS EXTRACTION
AND PETROLEUM REFINING 1969-1978a
(1,000 Workers)
Year
Petroleum and Natural Gas Extraction
Petroleum Refining
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
279.9
270.1
264.2
268.2
277.7
304.5
335.7
360.3
404.5
417.1
144.7
153.7
152.7
152.3
149.9
155.4
154.2
157.1
160.3
163.0
Reference 2. Section V. Table 2.
9-11
-------
The average hourly earnings of petroleum refinery workers have consis-
tently exceeded average wage rates for both the mining and manufacturing
industries.8 Petroleum refinery hourly earnings have also exceeded those
for other sectors of the oil industry as noted in Table 9-6.
9.1.1.5 Gasoline Pool. The largest single product produced at petro-
leum refineries is motor gasoline. This product is essentially a blend of
the products of several different refinery units including the catalytic
cracking unit. Table 9-7 provides a summary of the estimated contributions
of individual refinery streams to the gasoline pool. As noted in that Table
FCC gasoline is estimated to make the largest single contribution to total
gasoline output.
9.1.2 Market Factors
9.1.2.1 ' Demand Determinants. 1980 DOE projections conclude that, on
the national level, existing refinery capacity is capable of satisfying the
future domestic demand for refined petroleun products.10 Expansions and
modifications will, however, be undertaken in order to allow the processing
of greater proportions of high-sulfur crudes, and to permit the production of
increasing levels of high-octane unleaded gasoline. It is also possible that
shifts in'demand on the regional level may call for capacity expansions at
existing refineries.10
Evidence of sufficient refining capacity is provided by Table 9-8. In
that table estimates of percent refinery capacity utilization, along with
daily demand levels for the four major refinery products, are presented under
several assumptions regarding the world price of oil. In each case the
projected utilization rate is well below the 1978 level of 86 percent.
Reduced driving and greater vehicle efficiency have combined to reduce
the future demand for motor gasoline. As Table 9-8 indicates, it is unlikely
that gasoline demand will, within the forecast period, reach those levels
observed during 1978. This conclusion holds true regardless of specific
assumptions concerning the future of world oil prices.
, Reduced total gasoline demand does not, however, imply that existing
gasoline production facilities are currently capable of meeting future
gasoline requirements. In particular the continued phase-out of leaded
gasoline and demand for higher octane ratings will require some additions
to refinery capacity. Consequently, refiners can be expected to increase
9-12
-------
Table 9-6. AVERAGE HOURLY EARNINGS OF SELECTED INDUSTRIES3
(Average Hourly Wage)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
.Petroleum
Refining
4.23
4.49
4.82
5.25
5.54
5.96
6.90
7.75
"8.44
9.32
Petroleum and
Natural Gas Extraction
3.43
3.57
3.75
4.00
4.29
4.82 .
5.34
5.76
6.23
7.01
Total
Manufacturing
3.19
3.36
3.57
3.81
4.08
4.41
4.81
5.19
5.63
6.17
Total
Mining'
3.61
3.85
4.06
4.41
4.73
5.21
5.90
6.42
6.88
7.67
Reference 2. Section V. Table 1.
9-13
-------
Table 9-7. ESTIMATED 1981 UNITED STATES GASOLINE POOL COMPOSITION3
Stream
Amount
(1,000.000 m3/cd)
% OT
Total
Reformate
FCC Gasoline
Alky! ate
Raffinate
Butanes
Coker Gasoline
Natural Gasoline
Light Hydrbcfackate
Isomerate
Straight Run Naphtha
Total
355
408
162
17
75
15
30
22
16
86
I486
29.9
34.4
13.7
1.4
6.3
1,3
2.5
1.9
1.3
7.3
100,0
Reference 9.
9-14
-------
Table 9-8. DEMAND PROJECTIONS FOR MAJOR PETROLEUM PRODUCTS'1
Year
1978
1985
Low
Mid
High
1990
Low
Mid
High
1995
Low
Mid
High
World
Oil Price
(1979 $/m3)
97
170
201
245
170
233
277
170
258 .
352
Refinery
Capacity
(1,000 m3/cd)
'2,719
3,068
3,068
3,068
3,148
3,148
3,148
3,211
3,211
'3,211
Capacity
Utilization
(Percent)
86
70
65
64
74
66
63
76
.65
60 •
Product Demand (1
Motor
Gasoline
1,176
1,017
986
922
1,017
938
859
1,097
986
859
Distillate
Fuel Oil
572
493
461
445
541
493
461
588
493
429
,000 m-Vcd)
Residual
Fuel Oil
477
223
207
191
238
191
175
207
111
95
Jet
Fuel
175
238
175
223
270
191.
238
318
207
254
Reference 10, p. 115.
9-15
-------
catalytic cracking, catalytic reforming, and alkylation capacities in order
to maintain octane requirements.^
Distillate fuel oils are used in home heating, utility and industrial
boilers, and as diesel fuel. In all applications demand is expected to fall
with the exception of diesel fuel.10 Declining demand is essentially
due to the availability of lower cost substitutes, in particular coal fired
utility and industrial boilers and natural gas for home heating purposes.
As indicated in Table 9-8, the demand for distillate fuel oil declines in
all cases with the exception of low crude oil prices in 1995.
Residual fuel oil is used as a bunker fuel in large ships, large utility
and industrial boilers, and in the heating of some buildings. Residual fuel
oil competes with coal for use as a fuel in the applications noted above.
Table 9-8 shows that the demand for residual fuel oil falls steadily under
all price scenarios. This is so because the ability to crack residual fuel
into more valuable-lighter products ensures that its price will not fall to
that.point where it can serve as a cost-effective replacement for coat.12
The elasticity of demand is a measure of the percentage change in demand
relative to a percentage change,in price. .With regard to the elasticity of, .
demand for petroleum products, most-econometric studies conclude that
short-run demand is riot sensitive to price "changes. Estimates made by the •
Department of Energy and. summarized in Table 9-9, support this conclusion.13
Since all values in the table are less than one, the general conclusion is
that short-term demand is not particularly sensitive to price changes.
9.1.2.2. Supply Determinants. As noted in the previous section, it is
unlikely that-the supply of refined petroleum products will be restricted for
reason of inadequate domestic refining capacity. It is, however, quite pos-
sible that disruptions in the flow of imported oil could result from interna-
tional developments, in particular, political instability in the Middle East.
The major thrust of national energy policy is therefore the reduction of
dependence upon imported oil.
Attempts to reduce dependence upon imported oil have focused upon three
major areas: reduced consumption through conservation, and increased domestic
production through both the decontrol of domestic oil prices and the develop-
ment of a synthetic fuels industry. While price decontrol and synthetic fuels
development may have a significant impact in terms of import reductions, these
9-16
-------
Table 9-9. PRICE ELASTICITIES FOR MAJOR REFINERY PRODUCTS BY SECTOR3
(1985)
Sector *
Residential
Commerical
Industrial
Transportation
Product
Distillate Oil
Distillate Oil
Distillate Oil
Residual Oil
Liquid Gas
Gasoline
Distillate Oil
Residual Oil
Jet Fuel
Elasticity
-0.37
-0.41
-0.53
-0.36
-0.45
-0.29
-0.66
-0.10
-0.42
Reference 10, pp. 332-3, short-term elasticities,
9-17
-------
measures are essentially mid- to long-term solutions. Conservation, on the
other hand, has offered more immediate results. f
The effects of recent conservation efforts, including decreased gasoline
consumption, and conversion of facilities to coal and natural gas, can be
observed in Table 9-10. In particular, imports of crude oil have leveled-off
after reaching a historic high of 384 million m^ in 1977, while recent
reports^ indicate that the reduction of imports has continued into 1980.
The results of conservation efforts can also be observed in the fact that
year-end stocks of crude are currently at the highest levels recorded in
the recent past.
The phasing out of price controls on crude domestic oil and refined pet-
roleum products was completed on January 28, 1981 with the issuance of E.O.
12287, which revoked the price and allocation controls granted to the Depart-
ment of Energy under the Emergency Petroleum Allocation Act of 1973. The
progressive decontrol of domestic crude oil prices has increased exploration,
and is expected to increase stocks of already proven reserves. Recent
increases in both drilling activities and proven reserves are noted in Table
9-11.
The development of a domestic synthetic fuels industry will have little
impact upon energy supplies over the next five years since significant output
is not anticipated until the late 1980s.^
9.1.2.3 Prices. Table 9-12 indicates recent price levels for gasoline,
distillate fuel oil, and residual fuel oil. For each product, a pattern of
stable prices, followed by rapid price increases in 1974 and 1979, can be
observed. The increases in both years are attributed to the pass-through of
increases in the price of crude oil supplied by the OPEC nations.
Future refined product prices will continue to rise in response to
increases in the long-term price of both imported and domestic crude. Table
9-13 presents recent DOE projections of world oil, gasoline, distillate fuel
oil, residual fuel oil, and jet fuel prices.
9..1.2.4 Imports. Imports of both crude oil and refined products are
expected to decline through the mid-1980's. In the case of crude oil, the
fall in import levels can be attributed to sharp increases in the price of
OPEC oil, and the increased production of domestic crude prompted by its
price decontrol.
9-18
-------
Table 9-10. CRUDE OIL STATISTICS3
(1,000,000 m3/year)
Domestic
Year Production
1970 .
1971
1972
1973
1974
1975
1976
1977
1978
1979
559
549
549
534
486
465
452
457
485
474
Imports
77
98
129
188
202
238
308
384
369
376
Domestic
Consumption Exports
633
649
680
723
688
703
760
841
854
850
0.8
0.1
0.1
0.1
0.2
. 0.3
0.5
2.9
9.2
13.6
Year-End Stocks as Percent
Stocks of Consumption
44
41
39
39
42
43
45
55
60
68
6.94
6.36
5.76
5.33
6.13
6.14
5.97
6.57
7.01
8.05
^Reference 3, p. 073.
9-19
-------
Table 9-11. DOMESTIC OIL EXPLORATION AND DISCOVERIES
Year
Exploratory Wells Drilled
New Reserves Added
(1.000,000 m3)
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
7,693
7,000
8,357
7,466
8,619
9,163
9,234
9,961
10,667
10.484
l,566b
15
20
18
36
28
11
25
32
38
Reference 3, p. 072.
bIncludes Prudhoe Bay, Alaska.
9-20
-------
Table 9-12. PRICES: GASOLINE, DISTILLATE FUEL OIL, AND RESIDUAL FUEL OIL
Gasoline
(i/ liter)
Year
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
Wholesale"4
4,4
4.5
4.7
4.8
4.7
5.2
8.1
9.5
10.3
11.2
11.8 '
16.4
Retail0
8.9
9.2
9'.4
9.6
9.5
10.3
13.8
15.1
15.7
16.7
17.4
23.2
Distillate
Wholesale3
2.7
2.7
2.9
3.1
3.1
3.6
5.6
8.2
8.7
9.8
9.9
14.3
Fuel Oil
er)
Retail^
4.6
4.7
4.9
5.2
5.2
6.0
9.5
10.3
11.0
12.5
13.4
19.2
Residual Fuel Oil
(if liter)
Wholesale*
1.5
1.5
1.9
2.6
3.0
3.4
6.8
6.8
6.6
7.9
7.4
10.2
a£xcludes tax: Reference 3, p. 079.
bService station price, regular gasoline, includes tax: Reference 2,
Section VI, Table 4.
Reference 2, Section VI, Table 5.
9-21
-------
Table 9-13. PRICE PROJECTIONS3
(1979 $/m3)
Year
1978
1985
Low
Mid
High
1990
Low
Mid
High
•
1995
Low
Mid
High
World Oil
Price
97
170
201
245
170
233
277
170
258
352
Motor
Gasoline
153
240
277
320
241
309
352
240
338
432
Distillate
Fuel Oil
107
185
211
252
187
242
295
190
. . 267
365
Residual
Fuel Oil
80
175
204
243
176
232
279
178
255
352
Jet
Fuel
113
195
221
263
197
252
314
199
279
387
Reference 10, p. 115.
9-22
-------
Low sulfur (sweet) crudes are generally more desirable than high sul-
fur (sour) crudes because the"refining of the latter requires a larger
investment in desulfurization capacity such as hydrorefining and hydro-
treating units. While current crude imports are more than half sweet,
only 15 percent of OPEC's total oil reserve is sweet crude.16 Conse-
que'ntly, it is unlikely that the sweet-sour crude import balance will
remain constant. The price differential between the two will eventually
make sour crude processing a necessary investment.
With regard to refined petroleum products, the importation of most
of these products is expected'to decline as it has since the mid-1970's.
Table 9-14 shows that for the major refined products, imports peaked dur-
ing 1973-1974. In general, imports of refined products have been rela-
tively small compared with production at domestic refineries (see Table
9-4). For this reason, the potential for foreign trade disruption is min-
im tzed.
9.1,2.5 Exports. Exports of crude oil and refined petroleum pro-
ducts are a small portion of total U.S. production, and amount to less
than 8 percent of the volume imported.1? All exports are controlled
by a strict licensing policy administered by the U.S. Department of Com-
merce. Recently, crude^ oil exports have increased in response to the
Canada-United States" Crude Oil Exchange Program. The program is mutually
beneficial in that acquisition costs are minimized through improved effi-
ciency of transportation.
Table 9-15.summarizes recent trends in major refined product ex-
ports. The decline in exports through'the 1970s can be attributed to
both increased domestic demand and the expansion of foreign refining ca-
pacity.
9.1.3 Financial Profile
Despite-the recent softening in product prices, the oil industry
is generally regarded as financially strong. This optimistic outlook
is attributed to: increases in proven domestic reserves and production,
and decreases in the prices and the leveT of imported oil. •
9-23
-------
Table 9-14.
IMPORTS OF REFINED PETROLEUM PRODUCTS3
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979b
Motor
Gasoline
10
11
9
11
21
32
29
.21
34
31
27
Distillate
Fuel Oil
22
24
24
29
62
46
25
23
40
27
14
Residual
Fuel Oil
201
243
252
277
295
252
194
225
216
214
178
Jet Fuel
20
23
29
31
34
26
21
12
12
14
11
Kerosene
0.5
0.6
0.2
0.2
0.3
0.8
0.5
1.4
3.0
1.7
1.4
N6L and LRG
6
8
17
28
38
34
29
31
32
N/A
N/A
Reference 2. Section VII.
^Reference 18.
9-24
-------
Table 9-15.
EXPORTS OF REFINED PETROLEUM PRODUCTS3
(1,000 m3/cd)
Year
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Motor
Gasoline
0.3
0.2
0.2
0.2
0.6
0.3
0.3
0.5
0.3
0.2
Distil late
Fuel Oil
0.5
0.5
1.3
0.5
1.4
0.3
0.2
0.2
0.2
0.5
Residual
Fuel Oil
7.3;
8.6'
5.7
5.2
3.7
2.2 ..
2.4
1,9
1.0
2.1
Jet Fuel
0.8
1.0
0.6
0.3
0.8
0.3
0.3
0.3
0.3
0.2
Kerosene N6L and LR6'
0.2 5.6
4.3
0.2 4.1
4.9
4.3
.4.0
4.1
4.0
2.9
N/A
Reference 2. Section VII.
9-25
-------
Profit margins (i.e., net profit/sales) and return on investment (i.e.,
net profit/total investment) for both major oil companies and independent
refiners are summarized in Tables 9-16 and 9-17. The general pattern ob-
served is one of increases in both margins and returns through the five
year period noted.
It should be noted that the margins and returns presented in both tables
are for companies that refine crude oil but are not necessarily indicative of
the profitability of refining activities themselves. An indication of the
profitability of refining activities alone is provided by Table 9-18, which
summarizes the determination of industry profit margins by quarterly intervals.
9.2 ECONOMIC ANALYSIS
9.2.1 Introduction and Summary
In the following sections the economic impacts of the regulatory alter-
natives are estimated based on the costs of sodium-based flue gas desulfuriza-
tion. Economic impacts are presented in terms of the potential price,
profitability, and capital availability consequences of each regulatory
alternative.
For reasons noted in the following sections, -it is most likely that the
regulatory alternatives presented in Chapter 6 will result in slight increases
in the prices of refined petroleum products. In most cases the maximum price
increases possible are less than 0.4 percent. It is not expected that the
regulatory alternatives'would cause the postponement of planned FCC invest-
ments at existing refineries.
These conclusions are based upon observation of current market trends and
conditions along with the capital and annual cost estimates discussed in the
previous section. In the sections that follow a complete description of the
methods used to project economic impacts is presented in Section 9.2.2 while
the results of the application of those methods are noted in Section 9.2.3.
9.2.2 Economic Impact Methodology
9.2.2.1 Price Impact Methodology. The complete pass-through of the NSPS
control, costs presented in Chapter 8 will cause increases in the prices of re-
fined petroleum products. The extent of such price increases have been esti-
mated through the expression of the annualized control costs, of each model
unit and regulatory alternative, as a percentage of the annual revenues of
the refinery in which the new unit is likely to be constructed. The percen-
tages are therefore indicators of the extent to which refinery revenues, and
9-26
-------
Table 9-16. "PROFIT MARGINS9
Integrated- International
British Petroleum
Exxon* Corp.
Gulf Oil
Mobil Corp.
Royal Dutch Petroleum
Standard Oil (Calif.)
Tesoro Petroleum
Texaco, Inc.
Integrated-Domestic
Anerada Hess
Ashland Oil
Atlantic Richfield
Cities Service
Clark Oil and tRefining
Conoco, Inc.
Earth Resources •
Getty Oil
Kerr-McGee
Marathon Oil
Phillips Petroleum
Shell Oil
Standard Oil (Indiana)
Standard Oil (Ohio)
Sun Co.
Union Oil of California
Refiners
Charter -Co.
Crown Central Petroleum
Holly Corp.
Tosco Corp.
United Refining
1975
1.9
5.6
4.9
3.9
6.7
4.6
5.3
3.4
4.0
3.3
4.8
4.3
0.9
4.6
. .4.5
8.6
7.3
4.5
6.7
6.3
' 7.9
5.1
5.0
4.6
1.0
1.2
3.1
N/'A
1.8
1976
1.7
5.4
5.0
3.6
7.2
4.5
2.7
3.3
3.9
3.3
6.8
5.5
.1.3
5.8
4.6
8.5
6.9
5.6
7.2
7.6
7.7
4.7
6.6
5.0
1.5
2.4
4.0
0.9
0.8
1977
3.0
4.5
4.2
3.1
6.0
4.9
0.1
3.3
3.9
3.4
6.4
4.8
1.6
4.4
4.5
9.9
5.5
4.6
8.2
7.3
7.6
5.2
5.6
5.9
1.3
2.0
3.8
1.2
2.1
1978
3.1
4.6
4.4
3.2
5.0
4.8
2.4
3.0
3.0
4.7
6.5
2.5
1.6
4.8
2.9
9.3
5.7
4.4
" 10.2
7.4
7.2
8.7
4.9
6.4
1.2
2.8
3.5
1.6
2.1
1979
8.9
5.4
5.5
4.5
11.1
6.0
2.5
4.6
7.5
8.1
7.2
5.5
3.6
6.4
4.1
12.5
6.0
4.4
9.4
7.8
8.1
15.0
6.6
6.6
8.7
6.8
2.6
4.1
3.4
Reference 12, p. 088'.-
9-27
-------
Table 9-17. RETURN ON INVESTMENT3
Integrated- International
British Petrol euro
Exxon Corp.
Gulf Oil
Mobil Corp.
Royal Dutch Petroleum
Standard Oil (Calif.)
Tesoro Petroleum
Texaco, Inc.
Integrated-Domestic
Amerada Hess
Ashland Oil
Atlantic Richfield
Cities Service
Clark Oil and Refining
Conoco, Inc.
Earth Resources .
Getty Oil
Kerr-McGee
Marathon Oil
Phillips Petroleum
Shell Oil
Standard Oil (Indiana)
Standard Oil (Ohio)
Sun Co.
Union Oil of California
Refiners
Charter Co.
Crown Central Petroleum
Holly Corp.
Tosco Corp.
United Refining
2.0
7.8
5.6
5.6
6.8
6.3
9.0
4.8
5.5
6.3
5.2
4.5
1.7
6.7
• 12.9
8.2
10.1
6.7
8.0
7.8
8.4
3.6
5.2
6.3
2.0
2.9
9.1
N/A
5.0
2.1
7.6
6.3
5.5
8.4
6.6
4.0
4.9
5.9
6.6
7.1
6.3
- 3.0
8.0
12.8
7.5
8.9
7.8
8.5
9.4
8.5
2.6
7.8
6.3
3.2
5.3
11.1
2.6
2.1
"T977
4.3
6.5
5.4
5.1
8.0
7.1
0.2
5.0
6.0
6.7
6.8
5.7
4.5
* 6.0
10.9
8.0
6.9
6.1
9.5
8.7
8.4
2.3
6.6
7.0
3.2
5.1
10.6
2.8
5.6
4.1
6.9
5.4
5.2
6.0
7.0
5.3
4.4
4.2
8.8
6.7
3.0
4.9
6.4
7.2
7.4
6.1
5'. 5
11.1
8.3
8.0
5.0
6.8
. 7.3
3.4
6.4
9.9
4.2
6.2
"T979
11.8
9.5
8.2
8.0
13.5
10.2
9.9
8.1
11.3
20.2
8.9
7.9
10.6
9.7
8.5
11.2
7.3
7.3
11.5
8.4
9.6
13.4
10.2
8.7
29.1
16.8
8.0
14.2
11.0
aReference 12, p. 087-088.
9-28
-------
Table 9-18. PETROLEUM REFINING - INCOME DATAa
($1,000,000)
1978
1979
1980
23 4"
Sales . 41.75 43.88 46.17 48.52 50.72 54.71 63.68 73.58 79.80
Net Income
Before Tax 3.05 3.77 4.14 4.23 4.65 6.16 6.62 7.81 8.55
Net Income 2.55 3.15 3.41 3.66 3.95 5.25 5.71 6.84 8.04
% Net Income
to Salesb 6.11 7.18 7.39 7.54 7.79 9.60 8.97 9.30 10.08
Reference 12, p. 082.
^Profit margin.
9-29
-------
thus the prices of refined petroleum products, would need to increase if the
profit margin on sales of refining activities is to remain unaffected.
The annualized cost estimates used to project price increases are
presented in Tables 8-4 through 8-9, and Tables 8-11 and 8-12. In those
tables separate cost estimates are made for various model units, sulfur
contents' of feedstocks, regulatory alternatives and the use of caustic soda
/
vs. soda ash. Refinery revenue estimates have been made through the method
described below.
The addition of FCC capacity enables a refinery to increase the
value of its product mix, producing more of the higher priced com-
'ponents. Therefore an. important element in both the price and profit- .
ability analyses is the estimation of increased revenues made possible by the
added FCC capacity. Refinery revenues before and after the FCC addition have
been estimated according to a three-step process:
o Estimate refined product yields before and after FCC addition,
o Estimate refined product prices with price decontrol, and
'o Estimate refinery revenues before and after FCC addition.
Each of the steps noted above are discussed in greater detail following the
identification of six. assumptions used to allow the estimation of refinery
revenues. Sources of data are also noted: for the assumptions listed below.-
First, it is assumed that the smaller model unit (2,500 m3/sd) is
added to a small refinery (8,000 m3/sd)20, while the larger model unit
(8,000 m3/sd) is constructed at a large refinery (40,000 m3/sd).20
Second, the product yields for a typical refinery, oriented'toward gaso-
line production are: gasol-ine (51.1%), distillate (26.0%), residual (13.9%),
and kerosene (9.0%)2, while the ratio of'FCC capacity to crude distillation
capacity for such a refinery is 40 percent.21
Third, it is assumed that the addition of FCC capacity will increase
the refinery FCC to crude distillation ratio so that the average ratio before
and after the addition is 40 percent. Therefore, the small refinery will have
increased -FCC capacity 32 percent (i.e. 2,500/8,000) from 24 to 56 percent,
while the large refinery will show a 20 percent increase (i.e. 8,000/40,000)
from 30 to 50 percent.
Fourth, the 'product yields for FCC output are: gasoline (68.0%), dis-
tillate (21.0%), and residual (11.OX).21
9-30
-------
Fifth, it is assumed that additional FCC capacity will operate at full
capacity and that the total crude distillation capacity of the refinery
remains unchanged.
Sixth, the price decontrol of domestic crude and refined petroleum
products will add $25.20/m3 to the average price of crude and this
i.ncreas'e will be passed-on to the price of refined products.22
The first step in the revenue estimation process is the determination
of refinery product yields before and after the addition of FCC capacity.
This has been accomplished through the assumption that 2,500 m3/sd of the
non-kerosene output of the smaller refinery will take the form of the FCC
product yields noted in the fourth assumption, while the remainder of output
will continue in the form of the typical refinery yields presented in the
second assumption. Likewise, the larger refinery will have 8,000 m3/sd of
its non-kerosene output take the form of the FCC product yields. Non-kero-
sene output is of"concern since the output of kerosene should not be signi-
ficantly altered by a change in FCC capacity. The results of this procedure
are presented in Table 9-19.
The decontrol of domestic crude oil and refined petroleum products
was completed on January 28, 1981 with the issuance of E.O. 12287. However,
all costs and revenues reported in this analysis are expressed in terms of
1980 (IV) dollars. So that the effect of decontrol upon product prices, and
thus refinery revenues may be accurately reflected, the November 1980 prices23
of refinery products have been adjusted to include the pass-through of $25.2/m3
as noted in.the sixth assumption.22 Product prices used in this analysis
are: gasoline ($262.3/m3), distillate oil ($238.4/m3), residual oil
($164.2/m3), and kerosene ($243.4/m3).
Finally, total annual refinery revenues have been estimated based upon
crude capacity utilization of 64 percent24 and 357 operating days each
year. The determination of annual revenues, for both refineries before and
after the addition of FCC capacity, is sunmarized in Tables 9-20 through 9-23.
For purpose of price increase estimation, refinery revenues after the instal-
lation of additional FCC capacity are of concern. However, in the profit-
ability analysis described in the following section, the increase in revenues
made possible by the additional FCC capacity is of interest.
9.2.2.2. Profitability Impact Methodology. In order to estimate the
consequences of the full absorption of NSPS control costs, an Internal Rate
9-31
-------
Table 9-19.
REFINERY PRODUCT YIELDS
(percent)
Product
Gasoline
Distillate
Residual
Kerosene
Total
Sma
24%
48.4
27.7
14.9
9.0
100.0
11 Refinery
40%
51.1
26.0
13.9
9.0
100.0
56%*
53.8
24.3
12.9
9.0
100.0
Large Refinery
30%
49.4
27.1
14.5
_9.0
100.0
40%
51.1
. 26.0
13.9
9.0
100.0
50%a
52.8
24.9
13.3
_9.0
100.0
aPercent of crude throughput processed by FCC.
9-32
-------
Table 9-20. REFINERY ANNUAL REVENUE; SMALL REFINERY (8,000 m3/sd);
64 PERCENT CAPACITY UTILIZATION: BEFORE FCC ADDITION
Product
Gasoline
Distillate
Residual
Kerosene
Total
Output3
(m3/Sd)
5,120
5,120
5,120
5,120
Product
Yield5
(percent)
48.4
27.7
14.9
9.0
Product Product
Volume Price0
(m3/sd) ($/m3)
2,478 262.3
1,418 238.4
763 164.2
461 243.4
Revenue/ sd
x sd/year
Annual Revenue
Product
Revenue
($ 1980 IV)
649,979
338,051
125,285
112,207
1,225,522
357
$437,511,354
a8,000 m3/sd x 0.64.
bTable 9-19.
cReference 23, wholesale prices, November 1980.
9-33
-------
Table 9-21. REFINERY ANNUAL REVENUE; SMALL REFINERY (8,000 m3/sd);
64 PERCENT CAPACITY UTILIZATION: AFTER FCC ADDITION
"•""-I -— '"' " '
Product
Gasoline
Distillate
Residual
Kerosene
Total
Outputa
(m3/Sd)
5,120
5,120
5,120
5,120
— ... ••! " ' '__ -
Product
Yield5
(percent)
53.8
24.3
12.9
9.0
Product Product
Volune Price0
(m3/sd) ($/m3)
2,755 262.3
1,244 238.4
660 164.2
461 243.4
Revenue/ sd
x sd/year
Annual Revenue
Product
Revenue
($ 1980 IV)
722,637
296,570
108,372
112,207
1,239,786
357
$442,603,602
a8,000 m3/sd x 0.64.
• *
*>Table 9-19.
CReference 23, wholesale prices, November 1980.
9-34
-------
Table 9-22. REFINERY ANNUAL REVENUE; LARGE REFINERY (40,000 m3/sd);
64 PERCENT CAPACITY UTILIZATION: BEFORE FCC ADDITION
=======
Product
Gasoline
Distillate
Residual
Kerosene
~~ Total
Output2
(n»3/Sd)
25,600
25,600
25,600
25,600
Product
Yieldb
(percent)
49.4
27.1
14.5
9.0
Product Product
Volune Price0
(m3/s |