EPA-600/R-93-064a
April 1993
<&EPA Research and
Development
PROCEEDINGS:
1991 S02 CONTROL SYMPOSIUM
Volume 1. Opening Session and Sessions 1-3
Uniied Stales
Environmental Prolection
Agency
Prepared for
Office of Air Quality Planning and Standards
Prepared by
Air and Energy Engineering Research
Laboratory
Research Triangle Park NC 27711
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TECHNICAL REPORT DATA
{Please read hutfmctions on the. reverse before complef
1 RC PORT NO. ?
EPy\-600/R-93-064a
3.
4. TITLE AND SUBTITLE
Proceedings: 1991 SO2 Control Symposium, Volume 1.
Opening Session and Sessions 1~3
'J. REPORT DATE
April 1993
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Miscellaneous
8. PERFORMING ORGANIZATION REPORT NO.
TR-101054 (1)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
See Block 12
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
NA (Inhouse)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Proceedings; 1991
14. SPONSORING AGENCY CODE
EPA/600/13
15. supplementary notes AEERL project officer is Brian K. Gullett, Mail Drop 4, 919/541-
1534. Cosponsored by EPRI and DOE. Vol. 2 is Sessions 4-5A, Vol. 3 is Sessions
5B-6, Vol. 4 is Session 7, and Vol. 5 is Session 8.
16. abstract proceecjings document the 1991 S02 Control Symposium, held December
3-6, 1991, in Washington, DC, and jointly sponsored by the Electric Power Research
Institute (EPRI), the U.S. Environmental Protection Agency (EPA), and the U.S. De-
partment of Energy (DOE). The symposium focused attention on recent improve-
ments in conventional S02 control technologies, emerging processes, and strategies
for complying with the Clean Air Act Amendments (CAAA) of 1990. It provided an in-
ternational forum for the exchange of technical and regulatory information on S02
control technology. More than 800 representatives of 20 countries from government,
academia, flue gas desulfurization (FGD) process suppliers, equipment manufac- '
turers, engineering firms, and utilities attended. In all, 50 U. S. utilities and 10
utilities in other countries were represented. In 11 technical sessions, speakers
presented 111 technical papers on development, operation, and commercialization of
wet and dry FGD, clean coal technologies, and combined sulfur oxide/nitrogen oxide
(SOx/NOx) processes.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. descriptors
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Sulfur Dioxide
Nitrogen Oxides
Flue Gases
Desulfurization
Coal
Pollution Control
Stationary Sources
13 B
07B
21B
07A.07D
2 ID
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
465
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73) 3B~75
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EPA-600/R~ 93-064 a
April 1993
Proceedings: 1991S02 Control Symposium
Volume 1. Opening Session and Sessions 1-3
For Sponsors:
Electric Power Research Institute U.S. Department of Energy U S. Environmental Protection Agency
B. Toole O'Neil
3412 Hillvicw Avenue
Palo Alto, CA 94304
Charles J. Drummond
Pittsburgh Energy
Technology Center
P.O. Box 10940
Pittsburgh, PA 15236
Brian K, Gullett
Air and Energy Engineering
Research Laboratory
Research Triangle Park, NC 27711
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ABSTRACT
These are the Proceedings of the 1991 SO2 Control Symposium held December 3-6,
1991, in Washington, D.C. The symposium, jointly sponsored by the Electric Power
Research Institute (EPRI), the U.S. Environmental Protection Agency (EPA), and the
U.S. Department of Energy (DOE), focused attention on recent improvements in
conventional sulfur dioxide (SO2) control technologies, emerging processes, and
strategies for complying with the Clean Air Act Amendments of 1990. This is the
first SO2 Control Symposium co-sponsored by EPRI, EPA and DOE. Its purpose was
to provide a forum for the exchange of technical and regulatory information on SO2
control technology.
Over 850 representatives of 20 countries from government, academia, flue gas
desulfurization (FGD) process suppliers, equipment manufacturers, engineering
firms, and utilities attended. In all, 50 U.S. utilities and 10 utilities in other
countries were represented. A diverse group of speakers presented 112 technical
papers on development, operation, and commercialization of wet and dry FGD,
Clean Coal Technologies, and combined sulfur dioxide/nitrogen oxides (SO2/NOX)
processes. Since the 1990 SO2 Control Symposium, the Clean Air Act Amendments
have been passed. Clean Air Act Compliance issues were discussed in a panel
discussion on emission allowance trading and a session on compliance strategies for
coal-fired boilers.
ii
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CONTENTS
PREFACE xi
AGENDA xii
VOLUME 1
Opening Session
EPRI Perspective OS-1
EPA Perspective OS-5
DOE Perspective OS-9
Guest Speakers,
Shelley Fidler - Assistant, Policy Subcommittee on
Energy and Power, U.S. Congress OS-11
J ack S. Siegel - Deputy Assistant Secretary, Office of Coal
Technology, U.S. Department of Energy OS-19
Michael Shapiro - Deputy Assistant Administrator, Office
of Air and Radiation, U.S. Environmental Protection Agency OS-29
Session 1 - Clean Air Act Compliance Issues/Panel 1-1
Session 2 - Clean Air Act Compliance Strategies
Scrubbers: A Popular Phase 1 Compliance Strategy 2-1
Scrub Vs. Trade: Enemies or Allies? 2-21
Evaluating Compliance Options 2-39
Clean Air Technology (CAT) Workstation 2-49
Economic Evaluations of 28 FGD Processes 2-73
Strategies for Meeting Sulfur Abatement Targets in the
UK Electricity Supply Industry 2-93
iii
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Compliance Strategy for Future Capacity Additions: The Role of
Organic Acid Additives
A Briefing Paper for the Status of the Flue Gas Desulfurization
System at Indianapolis Power & Light Company
Petersburg Station Units 1 and 2
Evaluation of SO2 Control Compliance Strategies at Virginia Power
Session 3A - Wet FGD Process Improvements
Overview on the Use of Additives in Wet FGD Systems
Results of High SO2 Removal Efficiency Tests at EPRI's High
Sulfur Test Center
Results of Formate Ion Additive Tests at EPRI's High Sulfur
Test Center
FGDPRISM, EPRI's FGD Process Model-Recent Applications
Additive-Enhanced Desulfurization for FGD Scrubbers
Techniques for Evaluating Alternative Reagent Supplies
Factors Involved in the Selection of Limestone Reagents for Use in
Wet FGD Systems
Magnesium-Enhanced Lime FGD Reaction Tank Design Tests
at EPRI's HSTC
Session 3B - Furnace Sorbent Injection
Computer Simulations of Reacting Particle-Laden Jet Mixing
Applied to SO2 Control by Dry Sorbent Injection
Studies of the Initial Stage of the High Temperature
Ca0-S02 Reaction
Status of the Tangentially Fired LIMB Demonstration Program
at Yorktown Unit No. 2: An Update
Results from LIMB Extension Testing at the Ohio Edison
Edgewater Station
iv
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VOLUME 2
Session 4A - Wet FGD Design Improvements
Reliability Considerations in the Design of Gypsum Producing
Flue Gas Desulfurisation Plants in the UK
Sparing Analysis for FGD Systems
Increasing Draft Capability for Retrofit Flue Gas Desulfurization
Systems
Development of Advanced Retrofit FGD Designs
Acid Rain FGD System Retrofits
Guidelines for FGD Materials Selection and Corrosion Protection
Economic Comparison of Materials of Construction of Wet FGD
Absorbers and Internals
The Intelligence & Economics of FRP in F.G.D. Systems
Session 4B - Dry FGD Technologies
LIFAC Demonstration at Poplar River
1.7 MW Pilot Results for the Duct Injection FGD Process Using
Hydrated Lime Upstream of an ESP
Scaleup Tests and Supporting Research for the Development
of Duct Injection Technology
A Pilot Demonstration of the Moving Bed Limestone Emission
Control (LEC) Process
Pilot Plant Support for ADVACATE/MDI Commercialization
Suitability of Available Fly Ashes in ADVACATE Sorbents
Mechanistic Study of Desulfurization by Absorbent Prepared
from Coal Fly Ash
Results of Spray Dryer /Pulse-Jet Fabric Filter Pilot Unit Tests
at EPRI High Sulfur Test Center
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Results of Medium- and High-Sulfur Coal Tests on the TVA
10-MW SD/ESP Pilot Plant 4B-151
Evolution of the B&W Durajet™ Atomizer 4B-173
Characterization of the Linear VGA Nozzle for Flue
Gas Humidification 4B-189
High SO2 Removal Dry FGD Systems 4B-205
Session 5A - Wet Full Scale FGD Operations
FGD System Retrofit for Dalhousie Station Units 1 & 2
Zimmer FGD System: Design, Construction, Start-Up
and Operation
Results of an Investigation to Improve the Performance and
Reliability of HL&P's Limestone Electric Generating Station
FGD System
Full-Scale Demonstration of EDTA and Sulfur Addition to
Control Sulfite Oxidation
Optimizing the Operations in the Flue Gas Desulfurization Plants
of the Lignite Power Plant Neurath, Unit D and E and Improved
Control Concepts for Third Generation Advanced FGD Design
Organic Acid Buffer Testing at Michigan South Central Power
Agency's Endicott Station
Stack Gas Cleaning Optimization Via German Retrofit Wet
FGD Operating Experience
Operation of a Compact FGD Plant Using CT-121 Process
VOLUME 3
Session 5B - Combined SOx/NOx Technologies
Simultaneous SOx/NOx Removal Employing Absorbent Prepared
from Fly Ash 5B-1
Furnace Slurry Injection for Simultaneous SO2/NOX Removal 5B-21
Combined SO2/NOX Abatement by Sodium Bicarbonate
Dry Injection 5B-41
5A-1
5A-17
5A-37
5A-59
5A-81
5A-101
5A-127
5A-143
vi
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SC>2 and NOx Control by Combined Dry Injection of Hydrated
Lime and Sodium Bicarbonate
Engineering Evaluation of Combined NOx/SC>2 Controls for
Utility Application
Advanced Flue Gas Treatment Using Activated Char Process
Combined with FBC
Combined SO2/NOX Control using Ferrous *EDT A and a
Secondary Additive in a Lime-Based Aqueous Scrubber System
Recent Developments in the Parsons FGC Process for Simultaneous
Removal of SOx and NOx
Session 6A - Wet FGD Operating Issues
Pilot-Scale Evaluation of Sorbent Injection to Remove SO3 and HC1
Control of Acid Mist Emissions from FGD Systems
Managing Air Toxics: Status of EPRI PISCES Project
Results of Mist Eliminator System Testing in an Air-Water
Pilot Facility
CEMS Vendor and Utility Survey Databases
Determination of Continuous Emissions Monitoring
Requirements at Electric Energy, Inc.
Improving Performance of Flushless Mechanical Seals in Wet FGD
Plants through Field and Laboratory Testing
Sulcis FGD Demonstration Plant Limestone-Gypsum Process:
Performance, Materials, Waste Water Treatment
Session 6B - Clean Coal Demonstrations
Recovery Scrubber - Cement Application Operating Results
The NOXSO Clean Coal Technology Demonstration Project
vii
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Economic Comparison of Coolside Sorbent Injection and Wet
Limestone FGD Processes 6B-33
Ohio Edison Clean Coal Projects Circa: 1991 6B-55
Sanitech's 2.5-MWe Magnesia Dry-Scrubbing Demonstration
Project 6B-79
Application of DOW Chemical's Regenerable Flue Gas
Desulfurization Technology to Coal-Fired Power Plants 6B-93
Pilot Testing of the Cansolv® System FGD Process 6B-105
Dry Desulphurization Technologies Involving Humidification
for Enhanced SO2 Removal 6B-119
VOLUME 4
Session 7 - Poster Papers
Summary of Guidelines for the Use of FRP in Utility FGD
Systems 7-1
Development and Evaluation of High-Surface-Area Hydrated
Lime for SO2 Control 7-13
Effect of Spray Nozzle Design and Measurement Techniques on
Reported Drop Size Data 7-29
High SO2 Removals with a New Duct Injection Process 7-51
Combined SOx/NOx Control Via Soxal™, A Regenerative Sodium
Based Scrubbing System 7-61
The Healy Clean Coal Project Air Quality Control System 7-77
Lime/Lime Stone Scrubbing Producing Usable By-Products 7-93
Modeling of Furnace Sorbent Injection Processes 7-105
Dry FGD Process Using Calcium Sorbents 7-127
Clean Coal Technology Optimization Model 7-145
SNRB Catalytic Baghouse Process Development and Demonstration 7-157
Reaction of Moist Calcium Silicate Reagents with Sulfur Dioxide
in Humidified Flue Gas 7-181
viii
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Commercial Application of Dry FGD using High Surface Area
Hydrated Lime
Initial Operating Experience of the SNOX Process
Progress Report of the NIPSCO - Pure Air - DOE Clean Coal II
Project
Development of a Post Combustion Dry SO2 Control Reactor
for Small Scale Combustion Systems
Scrubber Reagent Additives for Oxidation Inhibited Scrubbing
Recovery of Sulfur from Calcium Sulfite and Sulfate
Scrubber Sludges
Magnesite and Dolomite FGD Technologies
SO2 and Particulate Emissions Reduction in a Pulverized Coal
Utility Boiler through Natural Gas Cofiring
Design, Installation, and Operation of the First Wet FGD for a
Lignite-Fired Boiler in Europe at 330 MW P/S Voitsberg 3 in Austria
VOLUME 5
Session 8A - Commercial FGD Designs
Mitsui-BF Dry Desulfurization and Denitrification Process
Using Activated Coke
High Efficiency, Dry Flue Gas SOx, and Combined SOx/NOx
Removal Experience with Lurgi Circulating Fluid Bed
Dry Scrubber - A New, Economical Retrofit Option for U.S.
Utilities for Acid Rain Remediation
Incorporating Full-Scale Experience into Advanced Limestone
Wet FGD Designs
Design and Operation of Single Train Spray Tower FGD Systems
Selecting the FGD Process and Six Years of Operating Experience
in Unit 5 of the Altbach-Deizisau Neckarwerke Power Station
Development and Operating Experience of FGD-Technique at the
Voelklingen Power Station
Advantages of the CT-121 Process as a Throwaway FGD System
ix
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Session 8B - By-Product Utilization
German Experience of FGD By-Product Disposal and Utilization 8B-1
The Elimination of Pollutants from FGD Wastewaters 8B-25
The Influence of FGD Variables.on FGD Performance and
By-Product Gypsum Properties 8B-47
Quality of FGD Gypsum 8B-69
Chemical Analysis and Flowability of ByProduct Gypsums 8B-91
Evaluation of Disposal Methods for Oxidized FGD Sludge 8B-113
Commercial Aggregate Production from FGD Waste 8B-127
x
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PREFACE
The 1991 SO2 Control Symposium was held December 3-6, 1991, in Washington,
D.C. The symposium, jointly sponsored by the Electric Power Research Institute
(EPRI), the U.S. Environmental Protection Agency (EPA), and the U.S. Department
of Energy (DOE), focused attention on recent improvements in conventional sulfur
dioxide (SO2) control technologies, emerging processes, and strategies for complying
with the Clean Air Act Amendments of 1990.
The proceedings from this Symposium have been compiled in five volumes,
containing 111 presented papers covering 14 technical sessions:
Session
Subject Area
1
Opening Remarks by EPRI,EPA and DOE Guest Speakers
1
Emission Allowance Panel Discussion
2
Clean Air Act Compliance Strategies
3A
Wet FGD Process Improvements
3B
Furnace Sorbent Injection
4A
Wet FGD Design Improvements
4B
Dry FGD Technologies
5A
Wet FGD Full Scale Operations
5B
Combined SOx/NOx Technologies
6A
Wet FGD Operating Issues
6B
Clean Coal Demonstratioins/Emerging Technologies
7
Poster Session - papers on all aspects of SO2 control
8A
Commercial FGD Designs
8B
FGD By-Product Utilization
These proceedings also contain opening remarks by the co-sponsors and comments
by the three guest speakers. The guest speakers were Shelley Fidler - Assistant,
Policy subcommittee on Energy and Power, U. S. Congress,
Jack . . S. Siegel - Deputy Assistant Secretary , Office of Coal Technology, U.S.
Department of Energy, and Michael Shapiro - Deputy Assistant Adminstrator,
Office of Air and Radiation, U. S. Environmental Protection Agency.
The assistance of Steve Hoffman, independent, in preparing the
manuscript is gratefully acknowledged.
The following persons organized this symposium:
• Barbara Toole O'Neil - Co-Chair, Electric Power Research Institute
• Charles Drummond - Co-Chair, U.S. Department of Energy
• Brian K. Gullett - Co-Chair, U.S. Environmental Protection Agency
• Pam Turner and Ellen Lanum - Symposium Coordinators, Electric Power
Research Institute
xi
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AGENDA
1991SO2 CONTROL SYMPOSIUM
Opening Session
Session Chain M. Maxwell - EPA
1-1
1-2
EPRI Perspective - S.M. Dalton
EPA Perspective - M. Maxwell
DOE Perspective - P. Bailey (no written manuscript)
Guest Speakers
Shelley Fidler - Assistant, Policy subcommittee on energy and
Power, U. S. Congress
Jack S. Siegel - Deputy Assistant Secretary , Office of Coal
Technology, U.S. Department of Energy
Michael Shapiro - Deputy Assistant Adminstrator, Office of Air
and Radiation, U. S. Environmental Protection Agency
Comments by:
Alice LeBlanc - Environmental Defense Fund
Karl Moor, Esq., Balch & Bingham
John Palmisano AER*X
Craig A. Glazer - Chair, Ohio Public Utilities Commission
Session 1 - Clean Air Act Compliance Issues/Panel
Session Moderator: S. Jenkins, Tampa Electric Co.
xii
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Session 2 -Clean Air Act Compliance Strategies
Session Chair: Paul T. Radcliffe - EPRI
2-1 Scrubbers: A Popular Phase 1 Compliance Strategy, P.E. Bissell,
Consolidation Coal Co.
2-2 Scrub Vs. Trade: Enemies or Allies? J. Piatt, EPRI
2-3 Evaluating Compliance Options, J.H. Wile, National Economic
Research Association, Inc.
2-4 Clean Air Technology Workstation, D. Sopocy, Sargent & Lundy
2-5 Economic Evaluations of 27 FGD Processes, R.J. Keeth, United
Engineers & Constructors
2-6 Strategies for Meeting Sulfur Abatement Targets in the UK Electricity
Supply Industry, W.S. Kyte, PowerGen
2-7 Compliance Strategies for Future Capacity Additions: The Role of
Organic Acid Additives, C.V. Weilert, Burns & McDonnell Engineerir
Co.
2-8 IPL Petersburg 1 & 2 CAAA Retrofit FGDs, C.P. Wedig, Stone &
Webster Engineering Corp.
2-9 Evaluation of SO2 Control Compliance Strategies at Virginia Power,
J.V. Presley, Virginia Power
Session 3A Wet FGD Process Improvements
Session Chair. David R. Owens - EPRI
3A-1 Overview on the Use of Additives in Wet FGD Systems, R.E. Moser,
EPRI
3A-2 Results of High SO2 Removal Efficiency Tests at EPRI's HSTC, G.
Stevens, Radian
3A-3 Results of Formate Additive Tests at EPRI's HSTC, M. Stohs, Radian
Corp.
3A-4 FGDPRISM, EPRI'S FGD Process Model-Recent Applications, J.G;
Noblett, Radian Corp.
3A-5 Additive Enhanced Desulfurization for FGD Scrubbers, G. Juip,
Northern States Power
3A-6 Techniques for Evaluating Alternative Reagent Supplies, C.V. Weilert
Burns & McDonnell Engineering Co.
3A-7 Factors Involved in the Selection of Limestones for Use in Wet FGD
Systems, J.B. Jarvis, Radian Corp.
3A-8 Magnesium-Enhanced Lime Reaction Tank Design Tests at EPRI's
HSTC, J. Wilhelm, Codan Associates
xiii
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Session 3B - Furnace Sorbent Injection
Session Chain Brian Gullett - EPA
3B-1 Computer Simulation of Reacting Particle-Laden Jet Mixing Applied to
SO2 Control by Dry Sorbent Injection, P.J. Smith, The University of
Utah
3B-2 Studies of the Initial Stage of the High Temperature CaO-SC>2 Reaction,
I. Bjerle, University of Lund
3B-3 Status of the Tangentially Fired LIMB Demonstration Program at
Yorktown Unit No. 2: An Update, J.P. Clark, ABB Combustion
Engineering Systems
3B-4 Results from LIMB Extension Testing at the Ohio Edison Edgewater
Station, T. Goots, Babcock & Wilcox
Session 4A - Wet FGD Design Improvements
Session Chain Richard E. Tischer - DOE
4A-1 Reliability Considerations in the Design of Gypsum Producing Flue Gas
Desulfurization Plants in UK, I. Gower, John Brown Engineers &
Constructors Ltd.
4A-2 Sparing Analysis for FGD Systems, M. A. Twombly, ARINC Research
Corp.
4A-3 Increasing Draft Capability for Retrofit Flue Gas Desulfurization
Systems, R.D. Petersen, Burns & McDonnell Engineering Co.
4A-4 Development of Advanced Retrofit FGD Designs, C.E. Dene, EPRI
4A-5 Acid Rain FGD Systems Retrofits, A.J. doVale, Wheelabrator Air
Pollution Control
4A-6 Guidelines for FGD Materials Selection and Corrosion Protection, H.S.
Rosenberg, Batelle
4A-7 Economic Comparison of Materials of Construction of Wet FGD
Absorbers & Internals, W. Nischt, Babcock & Wilcox
4A-8 The Intelligence & Economics of F.R.P. in F.G.D. Systems, E.J. Boucher,
RPS/ABCO
xiv
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Session 4B - Dry FGD Technologies
Session Chain Michael Maxwell /Brian Gullett/Norman Kaplan - EPA
4B-1 Poplar River LIFAC Demonstration,T. Enwald, Tampella Power Ltd.
4B-2 1.7 MW Pilot Results for Duct Injection FGD Process Using Hydrated
Lime Upstream of an ESP, M. Maibodi, Radian Corp.
4B-3 Scaleup Tests and Supporting Research for the Development of Duct
Injection Technology, M.G. Klett, Gilbert/Commonwealth Inc.
4B-4 A Pilot Demonstration of the Moving Bed Limestone Emission
Control Process (LEC), M.E. Prudich, Ohio University
4B-5 Pilot Plant Support for MDI/ADVACATE Commercialization, C.
Sedman, U.S. EPA
4B-6 Suitability of Available Fly Ashes in ADVACATE Sorbents, C. Singer,
U.S. EPA
4B-7 Mechanistic Study of Desulfurization by Absorbent Prepared from Coal
Fly Ash, H. Hattori, Hokkaido University
4B-8 Results of Spray Dryer/Pulse-Jet Fabric Filter Pilot Unit Tests at EPRI
HSTC, G. Blythe, Radian Corp.
4B-9 Results of Medium & High-Sulfur Coal Tests on the TV A 10-MW
Spray Dryer/ESP Pilot, T. Burnett, TVA
4B-10 Evolution of the B&W Durajet™ Atomizer, S. Feeney, Babcock &
Wilcox
4B-11 Characterization of the Linear VGA Nozzle for Flue Gas
Humidification, J.R. Butz, ADA Technologies, Inc.
4B-12 High SO2 Removal Dry FGD Systems, B. Brown, Joy Technologies, Inc.
Session 5A - Wet Full Scale FGD Operations
Session Chain Robert L. Glover - EPRI
FGD System Retrofit for Dalhousie Station Units 1 & 2, F.W. Campbell,
Burns & McDonnell Engineering Co.
Zimmer FGD System, W. Brockman, Cincinnati Gas & Electric
Results of on Investigation to Improve the Performance and Reliabiity
of HL&P's Limestone Electric Generating Station FGD System, M.
Bailey, Houston Lighting & Power
Full-Scale Demonstration of EDTA and Sulfur Addition to Control
Sulfite Oxidation, G. Blythe, Radian
xv
5A-1
5A-2
5A-3
5A-4
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5A-5 Optimizing the Operations in the Flue Gas Desulfurization Plants of
the Lignite Power Plant Neurath Unit D and E and Improved Control
Concepts for Third Generation Advanced FGD Design, H. Scherer,
Noell, Inc.
5A-6 Organic Acid BufferTesting at Michigan South Central Power Agency's
Endicott Station, B. J. Jankura, Babcock & Wilcox
5A-7 Stack Gas Cleaning Optimization Via German Retrofit Wet FGD
Operating Experience, H. Weiler, Ellison Consultants
5A-8 Operation of a Compact FGD Plant Using CT-121 Process, Y. Ogawa,
Chiyoda Corp.
Session 5B - Combined SOx/NOx Technologies
Session Chain Mildred E. Perry - DOE
5B-1 Simultaneous SOx/NOx Removal Employing Absorbent Prepared
from Fly Ash, H. Tsuchiai, The Hokkaido Electric Power Co.
5B-2 Furnace Slurry Injection for Simultaneous SO2/NOX Removal, B.K.
Gullett, U.S. EPA
5B-3 Combined SO2/NOX Abatement by Sodium Bicarbonate Dry Injection,
J. Verlaeten, Solvay Technologies, Inc. (124)
5B-4 SO2 and NOx Control by Combined Dry Injection of Hydrated Lime
and Sodium Bicarbonate, D. Helfritch, R-C Environmental Services &
Technologies
5B-5 Engineering Evaluation of Combined N0x/S02 Controls for Utility
Application, J.E. Cichanowicz, EPRI
5B-6 Advanced Flue Gas Treatment Using Activated Char Process
Combined with FBC, H. Murayama, Electric Power Development Co.
5B-7 SO2/NOX Control using Ferrous EDTA and a Secondary Additive in a
Combined Lime-Based Aqueous Scrubber System, M.H. Mendelsohn,
Argonne National Laboratory
5B-8 Parsons FGC Process Simultaneous Removal of SOx and NOx, K.V.
Kwong, The Ralph M. Parsons Co.
xvi
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Session 6A - Wet FGD Operating Issues
Session Chain Gary M. Andes - EPRI
6A-1 Pilot-Scale Evaluation of Sorbent Injection to Remove SO3 and HC1, J.
Peterson, Radian Corp.
6A-2 Control of Acid Mist Emissions from FGD Systems, R.S. Dahlin,
Southern Research Institute
6A-3 Managing Air Toxics: Status of EPRI PISCES Project, W. Chow, EPRI
6A-4 Results of Mist Elimination System Testing in an Air-Water Pilot
Facility, A.F. Jones, Radian Corp.
6A-5 CEM Vendor and Utility Survey Databases, J.L. Shoemaker,
Engineering Science, Inc.
6A-6 Determination of Continuous Emissions Monitoring Requirements at
Electric Energy Inc., V. V. Bland, Stone & Webster Engineering Corp.
6A-7 Improving Performance of Flushless Mechanical Seals in Wet FGD
Plants through Field and Laboratory Testing, F.E. Manning, BW/IP
International Inc.
6A-8 Sulcis FGD Demonstration Plant Limestone-Gypsum Process:
Performance, Materials, Waste Water Treatment, E. Marchesi, Enel
Construction Department
Session 6B - Clean Coal Demonstrations
Session Chain Joseph P. Strakey - DOE
6B-1 Recovery Scrubber Cement Application Operating Results, G.L.
Morrison, Passamaquoddy Technology
6B-2 The NOXSO Clean Coal Technology Demonstration Project, L.G. Neal,
NOXSO Corp.
6B-3 Economic Comparison of Coolside Sorbent Injection and Wet
Limestone FGD Processes, D.C. McCoy, Consolidation Coal Co.
6B-4 Ohio Edison's Clean Coal Projects: Circa 1991, R. Bolli, Ohio Edison
Emerging Technologies
6B-5 A Status Report on Sanitech's 2-MWe Magnesia Dry Scrubbing
Demonstration, S.G. Nelson, Sanitech Inc.
6B-6 Application of DOW Chemical's Regenerable Flue Gas Desulfurization
Technology to Coal Fired Power Plants, L.H. Kirby, Dow Chemical
6B-7 Pilot Testing of the Cansolv System FGD Process, L.E. Hakka Union
Carbide Canada LTD.
6B-8 Dry Desulfurization Technology Involving Humidification for
Enhanced SO2 Removal, D.P. Singh, Procedair Industries Inc.
xvii
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Session 7 - Poster Papers
Session Chair Charles Sedman - EPA
7-1 Summary of Guidelines for the Use of FRP in Utility FGD Systems, W.
Renoud, Fiberglass Structural Engineering, Inc.
7-2 Development and Evaluation of High Surface Area Hydrated Lime for
SO2 Control, M. Rostam-Abadi, The Illinois State Geological Survey
7-3 Effect of Spray Nozzle Design and measurement Techniques on
Reported Drop Size Data, W. Bartell, Spraying Systems Co.
7-4 High SO2 Removals with a New Duct Injection Process, S.G. Nelson, Jr.
Sanitech, Inc.
7-5 Combined SOx/NOx Control Via Soxal™, A Regenerative Sodium
Based Scrubbing System , C.H. Byszewski, Aquatech Systems
7-6 The Healy Clean Coal Project Air Quality Control System, V.V. Bland,
Stone & Webster Engineering Corp.
7-7 Lime/Lime Stone Scrubbing Producing Useable By-Products, D. P.
Singh, Procedair Industries Inc.
7-8 Modeling of Furnace Sorbent Injection Processes, A.S. Damle, Research
Triangle Institute
7-9 Dry FGD Process Using Calcium Absorbents, N. Nosaka, Babcock-
Hitachi K.K.
7-10 Clean Coal Technology Optimization Model, B.A. Laseke, International
Technology Corp.
7-11 SNRB Catalytic Baghouse Process Development & Demonstration, K.E.
Redinger, Babcock & Wilcox
7-12 Reaction of Moist Calcium Silicate Reagents with Sulfur Dioxide in
Humidified Flue Gas, W. Jozewicz, Acurex
7-13 Commercial Application of Dry FGD using High Surface Area Hydrated
Lime, F. Schwarzkopf, Florian Schwarzkopf PE.
7-14 Initial Operatiing Experience of the SNOX Process, D.J. Collins, ABB
Environmental System
7-15 Progress Report of the NIPSCO - Pure Air - DOE Clean Coal II Project, S.
Satrom, Pure Air
7-16 Development of a Post Combustion Dry SO2 Control Reactor for Small
Scale Combustion Systems, J.C. Balsavich, Tecogen Inc.
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7-17 Scrubber Reagent Additives for Oxidation Inhibited Scrubbing, J.
Thompson, Process Calx, Inc.
7_18 Recovery of Sulfur from Calcium Sulfite and Sulfate Scrubber Sludges,
J. Thompson, Process Calx, Inc.
7-19 Magnesite & Dolomite FGD Technologies, D. Najmr, Ore Research
Institute
7-20 SOx and Particulate Emissions Reduction in a Pulverized Coal Utility
Boiler through natural Gas Cofiring, K.J. Clark Aptech Engineering
Services
7-21 Design, Installation, and Operation of the First Wet FGD for a lignite
Fired Boiler in Europe at 330 MW P/S Voitsberg 3 in ,Austria, H.
Kropfitsch, Voitsberg
Session 8A - Commercial FGD Designs
Session Chain Robert E. Moser - EPRI
8A-1 Mitsui-BF Dry Desulfurization and Utility Compliance Strategies, K.
Tsuji, Mitsui Mining Company Ltd.
8A-2 High Efficiency Dry Flue Gas SOx and Combined SOx/NOx Removal
Experience with Lurgi Circulating Fluid Bed Dry Scrubber; A New
Economical Retrofit Option for Utilities for Acid Rain Remediation, J.
G. Toher, Environmental Elements Corp.
8A-3 Incorporating Full-Scale Experience into Advanced Limestone Wet
FGD Designs, P.C. Rader, ABB Environmental Systems
8A-4 Design and Operation of Single Train Spray Tower FGD Systems, A.
Saleem, GE Environmental Systems
8A-5 Selecting the FGD Process and Six Years of Operating Experience in
Unit 5 FGD of the Altbach-Deizisau Neckawerke Power Station, R.
Maule, Noell Inc.
8A-6 Development and Operating Experience of FGD Technique at the
Volkingen Power Station, H. Petzel, SHU-Technik
8A-7 Advantages of the CT-121 Process as a Throwaway FGD System, M.J.
Krasnopoler, Bechtel Corp.
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Session 8B - By-Product Utilization
Session Chair: Charles E. Schmidt - DOE
8B-1 German Experience of FGD By-Product Disposal and Utilization, J.
Demmich, Noell Inc.
8B-2 The Elimination of Pollutants from FGD Wastewaters, M.K.
Mierzejewski, Infilco Degremont Inc.
8B-3 The Influence of FGD Variables on FGD Performance and By-Product
Gypsum Properties,F. Theodore, Consolidation Coal Co.
8B-4 Quality of FGD Gypsum, F.W. van der Brugghen, N.V. Kema
8B-5 Chemical Analysis and Flowability of By-Product Gypsums, L.Kilpeck,
Centerior
8B-6 Evaluation of Disposal Methods Stabilized FGD & Oxidized FGD
Sludge & Fly Ash, W. Yu, Conversion Systems, Inc.
8B-7 Commercial Aggregate Production from FGD Waste, C.L. Smith,
Conversion Systems, Inc.
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1991 EPRI/EPA/DOE SO2 CONTROL SYMPOSIUM
OPENING REMARKS BY
STUART M. DALTON
SENIOR PROGRAM MANAGER, SO2 CONTROL
THE ELECTRIC POWER RESEARCH INSTITUTE
December 3,1991, Washington, D.C.
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EPRI Perspective - Stuart Dalton
1991 S02 CONTROL
SYMPOSIUM
I EPRI Perspective !
I "After the CI—n Air Act" |
Stuart Dalton
Senior Program Manager
S02 Control
EPRI
S02 CONTROL MARKET
EPRI expecta 12-15 OW of scrubbing
In phaae 1
Extensive coal switching In both
phases
40-50 GW scrubbing total by phaaa 2
Scattarad "non-CAA " FGD aucti aa
new pulverized coal flrad capacity,
and special retrofits such aa Navajo
| station.
COMPETITION
• A vary compatltlva markat in fuats,
and In FGD 1
• Scop* of supply varies from BOOM I
| (build own, oparata and maintain), to i
turnkey, to "typical mid-70's" to
scrubbar Island only
• Many technologies and suppliers are I
being eliminated without the chance I
to bid
FGD SUPPLIERS
• Over a dozen suppliers are active in
I the US - several phase 1 awarda
¦ • Technology and suppllara are
international
• Some suppliera are offering special
financial incentives to utilities
FGD TECHNOLOGY
• Wat limeatone, wet lime FGD
dominate the markat
• Limeatone forced oxidation
systems with "simplified"
designs are the leading aetectlon
• Additives used to Increase
performance to > 95% removal
• Few apare modules
• US utilities are not adopting "dry"
systema In phase 1
THE FUTURE
• Few "novel" systems • still mostly
lime and limestone wet
Dry will likely be a niche market
Toxics control a concern • dictated by
the regulations
December 3,1991
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EPRI Perspective - Stuart Dalton
EMISSION ALLOWANCES
Utilities are reluctant to buy or sell
until the rules are clearer and market
is favorable
No trades yet, but many planning to
trade it appropriate
¦ Phaae 1 • 100-400 S/ton S02 likely
(1991 dollars) - lower than expected
Phaae 2 - 400-800 S/ton S02 likely
' Legal issues unclear
Prudency reviews will come after the
fact
EPRI'S ROLE
Our mission is to provide technologies and
information to reduce the cost of
environmental risk management
S02 control teatlng at our High Sulfur Test
Center, FGD chemistry, materials of
construction, reliability, CEM, new proceaa
testing / demonstration
' Planning, designing and Implementing
state-of-the-art FGD using EPRI tools and
information • with EPRI members
December 3,1991
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1991 EPRI/EPA/DOE S02 CONTROL SYMPOSIUM
OPENING REMARKS BY
MICHAEL A. MAXWELL
CHIEF, GAS CLEANING TECHNOLOGY BRANCH
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC
These Sulfur Dioxide (SO2) Control Symposia have a long history, dating back to early
1970. The current symposium is the thirteenth in the series which spans more than two
decades of SO2 control technology research, development, and application. International in
character from the very beginning, these symposia have been a premier forum for the
transfer of technology among SO2 control process developers, designers, and users
worldwide. In fact, the combined past symposia proceedings could well serve as an excellent
source of the technological history of sulfur oxides (SOx) control in the utility industry.
In reviewing my copies of earlier symposium proceedings, I observed some interesting
contrasts between the March 1970 symposium and the present one. That symposium
preceded the 1970 Clean Air Act passage by about 8 months yet was attended by only 45
people and consisted of just 30 papers, all dealing with lime or limestone wet scrubbing. In
comparison, this conference (which follows the 1990 Clean Air Act Amendments (CAAA) by
about a year) is expected to approach an attendance of 1000 and will cover a broad range of
SO2 technology topics in the 110 papers to be presented.
I have also observed that the atmosphere in recent symposia has generally been one involving
a cooperative sense of sharing, both of experience and new ideas. This is quite a contrast to
the polarized position taken by many participants which typified some of the early symposia
which followed the National Hearings on SO2 Control Technology in 1973. There will
always, of course, be differing viewpoints expressed but I've sensed a more open minded and
congenial environment as of late.
The timing of this symposium could hardly be better from the point of view of providing a
forum for discussing the implications of the CAAA for SO2 control technology. After over
a decade of debate and delays, the CAAA were finally passed last year. Provisions covering
acid deposition and air toxics raise a number of issues of importance to all of us here today.
We are hopefully better positioned to meet the challenge of the CAAA than we were in
dealing with the 1970 Clean Air Act. Only time will tell.
I'm certain that most if not all of you are somewhat familiar with these provisions but let me
briefly summarize some of the Acid Rain Title's key points.
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Title IV provides for a market-based system of SC>2 allowances in reducing annual emissions
10 million tons by the year 2000. Phase I, effective January of 1995, requires 110
designated utility units to reduce emissions to 2.5 pounds SO2 per million Btu. Phase II,
effective January of 2000, requires all utility units to further reduce emissions to 1.2 pounds
SO2 per million Btu. Utility SO2 emissions are capped at 8.9 million tons annually after the
year 2000. Incentives are also provided to encourage use of 90% SO2 control technologies
by permitting users to postpone Phase I compliance by 2 years, thus becoming eligible for
bonus allowances.
In E. L. (Bill) Plyler's opening remarks at the 1990 Symposium, he posed some interesting
questions regarding the future for SOx control technology in light of the new legislation. I
think some of those warrant restatement today. One prominent question on many minds is:
what will be the relative roles of control technology versus clean coal as a means of
compliance? And also, to what extent will the incentives be successful in encouraging the
technology approach?
Another one is: how will the schedules and reduction levels impact the market for moderate
level retrofit technologies relative to conventional scrubbing? And finally: what role will
longer term emerging technologies such as repowering likely play?
Answers to these and other questions are beginning to evolve and will be discussed during
the next 4 days, but many uncertainties still remain. For example, it is apparent that a
number of utilities have chosen compliance strategies relying on low-sulfur coal or fuel
switching in Phase I and are deferring a decision on technology options until the tougher
Phase II is in effect.
The decline in low-sulfur coal prices has been an obvious factor coupled with other
considerations such as uncertainties associated with implementing the SO2 allowance
program. A panel discussion following this session will cover the latest developments of the
emission allowance topic.
I'd like to offer a few final comments about EPA's historical role in dealing with the SO2
control area. EPA is, obviously, first and foremost a regulatory agency. However, sound
regulatory decisions dealing with pollutants such as SO2 require an understanding of what
currently constitutes the most cost effective and efficient control options. Our Laboratory is
an integral part of EPA's Office of Research and Development and has for many years
provided technical support to the standard setting process including the utility and industrial
boiler New Source Performance Standards.
Much of the current generation of lime and limestone scrubbing technology including organic
acid enhancement has its foundation in research sponsored by our Laboratory and conducted
at TVA's Shawnee Station and our Research Triangle Park facility during the 1970's and
early 1980's. Others have refined and built on these results in the past decade but the
fundamental understanding of the variable and process chemistry which allows performance
OS-6
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reliable operation was established under EPA sponsorship in conjunction with TVA, EPRI,
and others. Because of the increasing international interest in the acid rain problem, our
focus since the mid 1980's has centered around identifying promising low cost retrofit
technologies for SO2 and NOx control on existing boilers.
Even though our research budgets in this area have declined in recent years, we are still
actively involved in the development and demonstration of several retrofit technologies
including the LIMB and ADVACATE processes, about which you will hear more later this
week. Demonstration of the LIMB process should be complete in 1993 following completion
of the Yorktown T-fired boiler project.
With a 60-70% SO2 control capability, LIMB will likely compete as a niche technology in
the acid rain market. However, the ADVACATE process has the potential to provide
greater than 90% SO2 control at half the costs of conventional wet lime or limestone
scrubbing systems. Field testing of this simple duct injection process at the 10 megawatt
scale will begin in the Spring of 1992 at TVA's Shawnee Station under the sponsorship of
TVA, EPA, EPRI, and ABB Flakt.
As our own research activities in this area begin to wind down in the next few years, we will
continue to follow the activities of others with interest, advising the Agency of new
developments as they occur.
In the meantime, our Laboratory is initiating major research programs in areas such as air
toxics and global warming mitigation. However, symposia such as this will continue to play
a major role in our technology transfer efforts in the future.
This paper has been reviewed in accordance with the U.S. Environmental
Protection Agency's peer and administrative review policies and approved for
presentation and publication.
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\
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DOE Perspective
P. Bailey
(No Written Manuscript)
os-s
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1991 EPRI/EPA/DOE S02 CONTROL SYMPOSIUM
EVOLUTION OF THE CLEAN AIR ACT AMENDMENTS OF 1990:
BEHIND THE SCENES
Shelley Fidler
Assistant, Policy Subcommittee on Energy and Power
U.S. Congress
December 3, 1991, Washington D.C.
Steve Jenkins: Shelley Fidler is a staff member on the
Policy Subcommittee on Energy and Power (Congressman Sharp [D,
Indiana]), which has jurisdiction over electricity, conservation
and alternative fuels, oil and natural gas, synthetic fuels,
coal, as well as environmental and nuclear issues. During her
tenure, Shelley has participated in congressional legislation on
automobile fuel economy standards, the Clean Air Act Amendments
of 1990 (CAAA), the Natural Gas Policy Act, Public Utility
Regulatory Policies Act, and the Synthetic Fuels Corporation.
Her current subcommittee responsibilities include environmental
issues, oversight of implementation of the CAAA, the Resource
Conservation Recovery Act, issues relating to the Arctic National
Wildlife Refuge, issues contained in the recently proposed
National Energy Strategy, transmission access, and the Public
Utility Holding Company Act.
Fidler: On Capital Hill, when we consider one policy issue,
we think of it in terms of many other issues. Hence, we look at
the issue of clean air in the context of demand-side management,
integrated resource planning, prudency issues in state regulatory
commissions, the U.S. nuclear program, PUCA reform (which our
subcommittee is now considering), carbon taxes, and greenhouse
warming.
Preceding page blank
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OZONE MOTIVATION
The issue that motivated passage of the CAAA was ozone
nonattainment, not acid rain. The Congress, when it enacted the
first Clean Air Act, set deadlines for ozone attainment, and
cities continually missed those deadlines. A six-month extension
to ozone nonattainment deadlines was passed. The need to develop
a legislative solution to these deadlines within the six-month
period motivated the entire CAAA.
In addition, in the area of acid rain, while there were
activists for many years who were advocating action, the science
was uncertain. Regardless of this uncertainty, Congress decided
on policy grounds to address the issue of acid rain. In
addition, there were recalcitrant utilities who were not largely
affected by the first Clean Air Act. They had existing power
plants, felt protected, and doubted that controls would be
required in the near term on their existing utility plants.
While these acid rain-related issues were present, the ozone
issue was the driving force for Congress to act.
The acid rain proposal eventually adopted resembled the
original proposal drafted by EPA and the Bush Administration.
This is noteworthy because Congress rarely enacts legislation as
proposed; there are simply too many different forces that act to
change a proposal. This proposal was successful in part because
ozone, rather than acid rain, was the major "battle ground."
So the Senate basically used the Bush formulation in writing
the acid rain bill. This was also true in the House, except some
interesting changes were made, one of which was the cap on clean
state utilities. This cap resulted in what is known as the
ratchet, which allows some utilities to overcontrol.
When the House went to conference with the Senate, the
majority of the members in the conference preferred the Senate
OS-12
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proposal on acid rain. They liked the Senate proposal, but they
liked the House allowances—what we used to call "special fixes."
And so we managed to use the Senate proposal and fund all the
House special fixes, which included generating units under
construction and provided free allowances to some of the most
affected states.
IMPLEMENTATION
Congress is not involved in the implementation of any of the
laws that it passes. I have been attending the Acid Rain
Advisory Committee (ARAC) meetings and talking with EPA staff
since their implementation process started, and I think that
their process is quite impressive. I have never seen as open an
implementation process. I have never heard people in the
industry say that they had more ability to make their case,
provide information, and receive feedback than I have in this
process. This is quite significant. Rather than an adversarial
process, EPA is using the expertise of the industry to gain a
better understanding and to make the law work better. From a
midwestern perspective, from the minute the law was passed, we
felt that the best thing we could do for our ratepayers and our
region was to make sure that this law worked properly. If the
allowance trading program works well, then costs are going to be
reduced. If the allowance trading program works poorly, problems
will result. So we have been boosters of the EPA process.
Congressman Sharp, the Energy Staff, and other members of
Congress who are following these matters are impressed. There is
a dispute-resolution option that is different from simply
responding to published regulations or taking people to court.
As a practical matter, EPA could not have chosen a different
approach to implementation because the law is so massive. The
number of decisions they have to make on very tight deadlines is
mind-boggling. EPA had to add many staff members to write a new
law. Those in the industry need to make sure that these staff
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members have the information they need to implement the CAAA
properly. Rather than ignoring the process, I strongly suggest
that you make suggestions to EPA. Congress has little ability to
influence regulations—each member has no more power than any
other individual.
There is no legislative history on this law. Normally,
after the House and Senate pass a piece of legislation and they
go to conference, they write a rather lengthy committee report,
in which they try to explain to a certain extent some of the
language that might be considered vague by EPA or try to help
direct the Agency in answering certain questions. This assumes
that we can anticipate the questions before they are asked. The
committee report for this massive piece of legislation was very
general and only a few pages long mainly because of time
pressure. Like many important pieces of law, the CAAA were
passed on the "eleventh hour" of the "eleventh day," just before
Congress adjournment, and there simply was not time to write a
massive committee report. In addition, there was such
controversy over so many titles that we probably could not have
found agreement. So, we have a small official committee report,
the massive Senate committee report in the Congressional Record,
and the interpretations of many congressman in the House record.
The committee itself did not agree on all these different
opinions, which will cause difficulties when the law is
implemented.
THE TELEPHONE POLL
At the first or second meeting of the ARAC in one of the
subcommittees, the issue of how the emission allowances would be
distributed if they were oversubscribed was first discussed.
Some made the case that a lottery would be a good way to
distribute these allowances, and others argued that pro rata
distribution would be more desirable. The ensuing debate covered
such issues as the intent of the law, uncertainty in utility
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planning, and concern over lawsuits.
EPA decided to resolve the debate by inventing a telephone
call-in system, in which you let people know you are in line for
Phase I bonus allowances and that you would get them if you won.
It is basically a lottery, and those who wanted pro rata lost.
There are two opportunities to address this issue. First, the
regulations are being proposed now—the decision can be changed.
If people do not like the idea of a telephone phone-in, they
should state their case during the comment period and try to
convince EPA. In the second option, the industry can solve the
problem: Everybody who wants to apply for bonus allowances
agrees that regardless of who wins the telephone phone-in, all
allowances will be evenly distributed. This arrangement
essentially pro rates these bonus allowances. Some utilities are
involved in some type of plan of this type—an effort I strongly
support.
FUTURE ISSUES
We will barely begin this S02 program when we must try to
determine the impact of many issues on the clean air toxics
program. We will pass PUCA legislation this year, creating more
competition in the bulk power markets. We will pass energy
legislation with transmission acts that will make some changes in
the industry. Later, there will be debates over greenhouse
warming. Every year, we have debates over carbon taxes, and that
will continue. I hope that the utility industry will support the
kind of strategy that the Energy and Power Subcommittee employed
in the greenhouse warming section of its energy proposal. We
also feel strongly that there is a great opportunity for control
technologies in terms of export. Our coal section of the Energy
Bill would encourage export of Clean Coal Technologies—a global
warming response as well. If we can convince some developing
countries to use our technologies, we will benefit economically
and from a greenhouse warming perspective. I encourage you to
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examine HR776, which is the House Energy and Power Subcommittee
Energy Bill. It will be taken up next year in the full Energy
and Commerce Committee, and we will pass an Energy Bill before
the Congress adjourns, before the elections next year.
Questioner: Would you address a little further the
influence of the international community on these regulations?
Fidler: In terms of the acid rain regulations, I do not
believe that there is a lot of thought being given to
international issues. In terms of the greenhouse issue and other
basic coal issues including export, the subcommittee considers
what is happening in the rest of the world. Along with the Bush
Administration, we are very concerned that the United States not
move quickly into unilateral actions on C02. On the other hand,
we feel strongly that we need to be talking in the international
community and developing a reasonable agreement that will move
toward reduction in greenhouse gases to the extent that the
science can support it. As with NAPAP, we never expect science
to provide black or white answers. That information helps us
move directionally.
Questioner: What do you have to say about the taxability of
allowances?
Fidler: The allowance pooling group is also going to
address the tax question on allowances. In all the time that I
spent working on this issue, we did not discuss the taxability of
allowances for one important reason. The committee that had
jurisdiction in the House, the House Energy and Commerce
Committee, does not have tax jurisdiction. This is also true in
the Senate. It is a problem because we also, for example, did
not address mass transit in the transportation sections of the
CAAA because this was not in our jurisdiction. One problem in
Congress is that unless a special ad hoc committee is formed, you
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cannot address crossjurisdictional issues very easily. Such a
committee has been formed only once since I was on the staff
during the Carter energy program. As a result, some important
issues must be addressed later. There are some who suggest that
Congress try to address it. EPA cannot address it—they are in
the same situation. However, the taxability of allowances
requires follow-up.
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1991 EPRI/EPA/DOE S02 CONTROL SYMPOSIUM
THE PAST, PRESENT, AND FUTURE OF CLEAN COAL TECHNOLOGY
Jack Siegel
Office of Fossil Energy
U.S. Department of Energy
December 4, 1991, Washington D.C.
Ian Torrens: Jack Siegel is Deputy Assistant Secretary for
Coal Technology in the Department of Energy's (DOE) Office of
Fossil Energy. Jack's long and distinguished career at DOE
extends back to the 1970s. He is responsible for managing the $5
billion DOE Clean Coal Technology Demonstration Program (CCT) as
well as DOE's research and development on a wide variety of coal-
based technologies. DOE's CCT program is an excellent example of
government/industry cooperation towards the shared national goals
of energy security and environmental quality. Jack chairs the
International Energy Agency's working party on fossil fuels,
leading an innovative and energetic international research and
development (R&D) program in this area. His office is
responsible for the technology transfer desulfurization project
in Krakow, Poland, jointly funded with the Agency for
International Development.
Siegel: Because many see only the negative sides of coal,
the coal industry has much educating to do—about what it is and
how important a role it can play. Few in the U.S. recognize that
57% of domestic electricity produced is derived from coal. They
believe that it comes from electricity, but not from coal. I
will provide an historical perspective on the program DOE has
constructed over the years, summarize the status of the program
today, and discuss its future directions.
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PAST DOE COAL ACTIVITIES
DOE has been involved in SOz control R&D for over 20 years.
Beginning in the early 1980s, the program focused on the combined
control of sulfur dioxide (S02) and nitrogen oxides (N0X). The
established goals included 90% removal of both S02 and N0X at a
cost that was about 20% less than scrubber and selective
catalytic reduction (SCR) technology. Our program has always
pursued technologies that produce marketable by-products, rather
than throwaway wastes. The targets of our program, 90% S02 and
NOx removal, were based on the fact that the Clean Air Act had
recently been passed in 1977, which required up to 90% S02
control. At that time, 90% S02 removal was reasonable. In the
early 1980s, few proven S02 control technologies were on the
market, and more research was necessary.
We thought that the 1980s would be the decade for N0X. We
expected tight N0X control requirements and wanted to have
technology ready for those requirements. Our initial efforts
focused on technologies like Ebara E-Beam, UOP/Pittsburgh Energy
Technology Center moving-bed copper oxide, the MK-Ferguson NOXSO
process, and others. In the ensuing years, research on these
processes resulted in some successes and some failures. In some
cases, the processes worked technically, but appeared to be
economically prohibitive. In other cases, the technologies could
not meet our program controls. However, several of these
processes remain potentially attractive and are continuing their
long path to the commercial marketplace.
In 1985, with the growing movement to control acid rain
precursors, our program was broadened to include low-cost
technology. At that time, we defined "low cost" as less than
$500 per ton of S02 removed from existing coal-fired power
plants. The work quickly began focusing on duct injection
technology, with the ultimate goal of providing a design guide in
the 1992-93 time frame. Such a guide would help utilities easily
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extrapolate the results of our R&D to their individual power
plants. Three duct injection technologies were tested at about
5-12 megawatts. General Electric in-duct lime, slurry spray
drying, Dravo's hydrated lime work, and Bechtel's confined zone
dispersion projects were researched during this period. Each of
these concepts achieved acceptable levels of S02 control, but
they experienced technical problems, such as wall wetting and
deposition.
THE PRESENT DOE PROGRAM
This dictated the need for further research and led to the
present S02 program, consisting of three projects for duct
injection. One project addresses the fundamental investigation
of electrostatic precipitators (ESP). This project resulted in a
three-dimensional process model to describe the ability of ESPs
to collect alkaline wastes. The second project scales up duct
injection technologies to characterize system performance and to
validate models. The third project is duct injection prototype
development. This project involves collecting and analyzing data
generated by other duct injection projects and using this
information to develop a process handbook. This handbook will
serve as the design guide for duct injection technology. It will
be ready in the next year or two, in time for utilities to use to
design technologies for acid rain compliance.
Several duct injection concepts have advanced from the
proof-of-concept to demonstration scale under our CCT
Demonstration Program. These include the confined zone
dispersion (CZD) process that Bechtel is undertaking, the gas
reburning and sorbent injection process at Illinois Power by
Energy and Environmental Research Corporation, LIFAC-North
America's project at Richmond Power and Light in Indiana, and
Babcock & Wilcox's lime project (similar to duct injection).
Public Service Company of Colorado has a project at their Arapaho
Station in Denver, Colorado, and Union Carbide has their Cansolv
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process.
In addition to the duct injection development activities for
S02 control, DOE is supporting EPRI work at their High Sulfur
Test Center. One major activity at this facility is study of the
effect of additives on the S02 removal efficiency of wet
scrubbers. The goal is to demonstrate measures to improve these
efficiencies in existing scrubbers. Also in cooperation with
EPRI, we will conduct full-scale tests to increase the S02
capture efficiency of wet scrubbers through the use of additives.
We will conduct tests at five to eight power plants, with a goal
of increasing existing S02 equipment removal efficiency to 97%.
There are many other concepts for the control of S02 that
have been developed over the last 20 years, many of which have
advanced without significant government support. Some of these
promising concepts are now part of our CCT Program and could add
to the suite of options that are available in the 1990s. These
projects include Bechtel's Chiyoda scrubber, Pure Air's advanced
flue gas desulfurization technology, ABB Combustion Engineering's
WSA-SNOx technology, Babcock & Wilcox's SOx NOx Rox Box, Airpol's
gas suspension absorption process, and the SHU wet flue gas
desulfurization process.
In addition, we have several CCT projects on controlling S02
from sources of emissions other than power plants, such as coke
ovens, cement plants, paper industries, and hog boilers.
Bethlehem Steel, the Passamaquoddy Technology, and Thermochem are
examples of companies that are working under our CCT program.
THE CHALLENGE
The use of coal in the U.S. has increased dramatically over
the last 20 years. At the same time, S02 emissions have
decreased substantially. The national energy strategy recognizes
that coal is critical to meeting U.S. and world energy needs well
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into the future. The strategy points out that 1 billion tons of
coal was produced in the U.S. in 1990, 900 million of which was
consumed domestically. It projects that U.S. coal use will
increase by about 50% by the year 2010 and double by the year
2030, even if there is significant conservation, opening of new
oil and natural gas fields in the U.S. and off shore of the U.S.,
continuation of nuclear power, and a fourfold increase in
renewables. If nuclear power plants do not continue to operate
or if renewables are not economically feasible, coal will make up
the difference. Although some coal will be used to produce
synthetic fuels and for industrial applications, coal will
predominantly be used for power generation in the future, as it
is today.
Coal represents 70% of the world's fossil energy resources.
It is expected to play a larger role in meeting energy needs in
many countries, especially the developing ones, in the future.
However, in both the U.S. and other countries, coal's use is
contingent on meeting economic and environmental demands. The
latter is coal's Achilles heal. With the passage of the Clean
Air Act Amendments of 1990 (CAAA), the ground rules for energy
production generally and coal use specifically have changed
dramatically. Other legislation that will affect coal use
include the requirements that EPA will promulgate for the control
of toxic air pollutants, and the further control of NOx—the
pollutant of the 1990s. The Resource Conservation Recovery Act,
which is due for reauthorization next year (1992) , regulates the
disposal of waste. This act, the CAAA, and other legislation
will affect the use of fuels or fuel options in the future.
Solid waste disposal requirements will become more stringent.
In addition, there is a growing effort throughout the
country, by the states in particular, to regulate environmental
externalities. Many states are using this environmental
externality penalty as a way of regulating carbon dioxide (C02)
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emissions. So whether or not the Administration is supportive of
any control actions on C02, it is already being controlled in
many cases at the state level.
FUTURE WORK
These requirements result in new and threatening challenges
to coal. Taking all this information into consideration, we have
developed a plan to respond to the challenge. We have refocused
our research program on the flue gas cleanup area to develop
competitively priced processes that will improve S02 removal to
about 99%, improve N0X control levels to about 95%, and
incorporate air toxic control. While we control N0X, S02, and
toxics to these high levels, we want to ensure that we minimize
wastes or at least develop technologies that result in waste that
can be used.
Consistent with this new direction, during fiscal year 1991
a PRDA was issued by DOE's Pittsburgh Energy Technology Center
(PETC) to solicit new concepts for advanced separation
technology. This technology is based on the physical separation
of S02 and N0X from the flue gas. Four contracts were awarded.
In spring 1992, the PETC will issue a PRDA for extremely
high efficient processes capable of removing 98-99% of S02 and
NOx. A recent solicitation was issued for two proposals on low
emission boiler systems. The proposals are currently being
evaluated. One of their expected features is to incorporate high
performance scrubbers with advanced combustors to reduce
emissions by about one quarter of New Source Performance
Standards for high-performance, green-field pulverized coal plant
systems in the 21st century. Several concepts are expected to be
selected by February 1992. In addition, a solicitation has been
issued to gather information on toxic air pollution from the
advanced coal facilities. If problems are identified, our
hardware control program will be initiated. Utilities will not
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only purchase S02, N0X, toxics, and particulate matter equipment
piece meal, they will also purchase the most economical system to
meet all of the requirements at one time if all of the
requirements are defined at a sufficiently early stage.
New processes for producing power more economically,
cleanly, and efficiently are rapidly advancing to the commercial
marketplace. These processes, such as integrated gasification
combined-cycle, pressurized fluidized-bed combustion, circulating
fluidized-bed combustion, and advances in that technology (e.g.,
fuel cells and magnetohydrodynamics), will represent real
competition to add-on pollution control techniques in the near
future. In setting the goals for our pollution control programs,
these processes are being used as the benchmark.
A SHIFT IN FOCUS
Like the R&D program, the CCT Program is changing focus.
Rounds I through III were mainly targeted to the control of
existing coal-fired boilers. "Retrofit" and "repowering" were
the key words for Rounds I through III. In Round IV, however, a
new term for the CCT Program, "thermal efficiency," was used. It
reflected our view that for coal to compete beyond the year 2000,
it had to be responsive to the realities of public demand for
environmental protection. As a result, several integrated
gasification combined-cycle projects were selected, along with
some super-clean (98-99% removal) pollution control technologies.
In Round V, a $600 million Federal program, Congress has
instructed us to focus on super-clean, super-efficient
technology. To date, we have conducted two public meetings to
discuss the focus of the program. Although we have received
varied views so far, a major focus must be the super-efficient,
super-clean power systems of the future. Other projects will be
eligible, and we will be drafting that part in the next several
months. By law, we are required to issue the solicitation for
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Round V by July 6, 1992. We hope to have a draft of the
solicitation available for release and have another public
meeting to solicit additional views before we publish a final
version.
INTERNATIONAL OPPORTUNITIES
As a result of a presidential trip to Poland about 18 months
ago, the President was interested in some sort of environmental
initiative there. One project that he identified, funded by the
U.S. government, would demonstrate an advanced U.S. technology to
control pollution from the power plant in Krakow. Funding for
this project was given to the Agency for International
Development, and they passed it on to DOE to solicit proposals.
We worked with the Polish government in developing the evaluation
criteria for this proposal. The solicitation was limited to U.S.
companies, U.S. technology (Airpol) was selected in the
competitive solicitation, and in August 1990 they were selected
to build that boiler. Installation of this dual alkali scrubber
is planned to begin in July 1992. The cost to the U.S.
government is $7.7 million, the Poles are providing resources
(i.e., labor, training, and so forth), and we will be conducting
some training as well.
The Poles determined that the project would meet their needs
perfectly. Hence, as a result of cooperation between the U.S.
and the Poles, the Poles decided to expand the size of the plant
to be controlled under this program, at their expense. The Poles
will control a plant twice the size that was originally planned,
with the same cost to the U.S. government. The U.S. will benefit
because it is U.S. technology.
Hopefully, more opportunities like this will arise.
Advanced coal technology is needed throughout the world.
Although the needs are different in Eastern Europe than in the
Pacific Rim or Latin America, there are large-scale opportunities
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everywhere.
Our coal program does not end with technology. We need to
provide information to the public, users, regulators, and
everyone who needs information on these advanced technologies.
We have a large outreach and education program to do this.
In closing, S02 control has made great strides over the last
20 years. A variety of options are available now, and more
options will be available in the near future from which to choose
to meet energy and environmental needs. We need to start
considering the future because coal will not survive using
today's technologies. We must address the environmental demands
that exist now and those that will be even more stringent in the
future. Through research, we will develop the technologies that
will pave the way for coal's future.
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1991 EPRI/EPA/DOE S02 CONTROL SYMPOSIUM
IMPLEMENTING THE CLEAN AIR ACT AMENDMENTS OF 1990
Michael Shapiro
Office of Air and Radiation
U.S. Environmental Protection Agency
December 5, 1991, Washington D.C.
Brian Gullett: Michael Shapiro is the Deputy Assistant
Administrator of the Office of Air and Radiation at EPA. His
responsibilities include implementation of the Clean Air Act
Amendments of 1990 (CAAA) as well as EPA programs addressing
stratospheric ozone, indoor air, pollution, and radiation. From
1980 to 1989, Mike has held a number of positions within the
Office of Pesticides and Toxic Substances. As Director of the
Economics and Technology Division, he was responsible for all
economic, engineering, and chemistry support for implementation
of the Toxic Substances Control Act, and for directing
implementation of the toxics release inventory under the
Emergency Planning and Community Right to Know Act.
Shapiro: This conference symbolizes much of what EPA has
been trying to achieve in our implementation of the CAAA, and in
particular in the acid rain program. We are trying to create a
regulatory environment in which those with the technical ability
to solve the problem are given the maximum flexibility to develop
approaches that cost-effectively and creatively meet individual
facilities' needs. This approach is easier to implement in
certain parts of the CAAA than others, but it is one of the key
aspects of the CAAA and one of the ways that it represents the
next generation of environmental regulation.
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THE CHALLENGE OF IMPLEMENTATION
The CAAA itself, passed a little more than a year ago, is
one of the most ambitious pieces of environmental legislation
ever passed in the U.S., and for that matter, in the world. It
provides a comprehensive 20-year program for addressing almost
the complete array of air pollution problems in the U.S.,
including stratospheric ozone depletion, acid rain, ambient air
quality problems in urban areas, and the problems of air toxics
for specific facilities and area sources. The CAAA creates both
an ambitious schedule and an aggressive agenda for solving those
problems. It is challenging EPA and the entire community of
professionals in the air quality area to develop regulations and
strategies much more quickly, aggressively, and creatively than
in the past.
In the case of EPA, we calculated that we need to develop
about five times as many regulations per year as we have been
developing in the air program over the last decade. To do this,
we conceived an implementation strategy and schedule, published
last January, which includes what we believe is important and
when we were going to accomplish the major milestones of the
CAAA.
We used two important principles in our implementation. The
first was the principle of consultation; we consciously chose to
change the way in which we develop rules and regulations. We
decided that the processes that we had used in the past, which
emphasized heavy initial work by EPA followed by a
confrontational sequence with the regulated communities, could
not yield outcomes as quickly or as efficiently as needed. So we
designed processes that stressed up-front consultation and
dialogue, not only with the industrial community, but with the
environmental community and key state and local agencies that had
to implement our actions. The hope was to build a consensus
around each major rule. Secondly, we decided to design an
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implementation program that achieved the environmental objectives
of the CAAA, but that also exercised the maximum possible
creativity at determining ways of achieving these objectives.
These methods had to be consistent with the notions of economic
efficiency and energy conservation.
Over the last year, we have issued over 64 major actions,
including 44 proposed or final rules. We have proposed or
finalized rules that when fully in force and effective, will
account for over two-thirds of the 56 billion pounds of air
pollutants that we project the CAAA will remove from the national
emissions inventory by the year 2005. We certainly have not met
all of our deadlines, and we have had problems along the way, but
I think we have been able to forge alliances with industry,
environmental groups, and state and local regulators to solve
problems together.
Our consensus-based approach to rulemaking has had a number
of notable successes. One is the recent agreement on
reformulated gasoline, which will cost-effectively improve the
mobile source area of emissions and therefore address both carbon
monoxide and ozone problems. This agreement illustrates how we
can put our heads together and develop a solution to a problem
that is not only better for the environment, but that maximizes
the flexibility for industry to comply and thereby reduces the
cost of compliance.
Issuance of the proposed rules for implementing the acid
rain program is among our most important accomplishments over the
last year. These rules were signed by the EPA Administrator on
October 29th, 1991 and appeared in the Federal Register
yesterday. They represent one of the critical programs in the
entire CAAA. They are environmentally aggressive, calling for
ultimately about a 50% reduction in the emission of S02. For the
first time, they place a cap on the total emissions of a
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particular pollutant, in this case S02, from a major industry
sector, the utility industry. They also will be the first major
test of the market-based approach of allowance trading that has
been advocated for many years by economists.
The success of the acid rain program will be a benchmark
against which future regulatory approaches and legislative
initiatives will be compared. Not only will we be addressing a
major air quality problem, we will be charting new ground in the
pattern of future regulations for air pollution control and other
media programs at the Agency. Much thought is going into
revisions to the Clean Water Act, and some of these ideas reflect
the experience of using market-based approaches in the CAAA.
NEW APPROACH TO IMPLEMENTATION
The task of implementing the CAAA legislative requirements
fell to the Agency. We have assembled a group within our Office
of Atmosphere and Indoor Air Programs that was charged with this
as their sole responsibility. They have developed a carefully
structured approach to implementing the regulations, focusing on
the following three primary goals:
• To achieve the central environmental aim of the program
(i.e., the 10 million-ton reduction in S02 by the year 2000)
• To enable the market-based allowance system to provide the
least costly overall emission reductions
• To use the program as much as possible to encourage
pollution prevention approaches and energy efficiency in the
implementation.
Meeting these goals required assembling a program in a
different way from the way in which EPA has traditionally
implemented its regulatory responsibilities. Here, the primary
focus was on identifying how we could let the market do most of
the work. We also needed to establish rules so that we could
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ensure equity, efficiency, and accountability in the market
system. EPA typically focuses most of its resources on
identifying the best technology for reducing S02 emissions.
Instead, we said to the market "That's your job." Our job is to
focus on ensuring that the monitoring systems that we put in the
rule will provide us with the accountability and correctness that
we need. Our job is to develop a system for using these
allowances and trading them that provides companies the maximum
flexibility to make the best decisions from their own individual
perspectives. Utilities might choose treatment, purchase low-
sulfur coal, retire one facility and generate more energy at
another, or develop an energy conservation program. Individual
utilities can make the best economic decisions for them, leading
to a solution that will deliver the emissions reductions at the
least overall expense to society.
To do this, we used a lot of outside help. This is best
illustrated in the process used to develop the core rules for the
acid rain program. We convened the Acid Rain Advisory Committee
(ARAC), which comprised over 40 members from the utility
industry, the environmental community, state utility regulators,
state environmental regulators, Federal officials, and individual
utility companies, to establish a set of regulations that
achieved our objectives. This process enabled us to assemble a
comprehensive rule package. We achieved a remarkable degree of
consensus and agreement over the basic concepts in the
regulations.
THE CORE REGULATIONS
The package that was signed by the EPA Administrator at the
end of October and published yesterday consists of a unified
package of four rules. These so-called "core regulations" should
be considered collectively, because they interrelate. The four
key regulations are
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• The allowance trading system
• The permitting program, which is the vehicle by which
individual utilities establish how they will comply in an
enforceable manner with the program
• The requirements for continuous emissions monitoring, which
is the fundamental basic technology for establishing
accountability in the system
• The excess emissions rule, which defines what happens to an
individual facility if they violate the law by emitting more
than they are allowed.
Allowance Trading System
The allowance system is the heart of the program. An
emission allowance in the acid rain program is an allowance to
emit one ton of S02. If you are covered by the program, you need
one ton of allowance for every ton of emissions that your
facility releases. An annual accounting system has been
established so that at the end of each year, a utility has to be
able to demonstrate through its monitoring records and allowance
holdings that they have achieved at least the minimum balance
between the emissions and the allowances available to the
facility. The initial amount of allowances that are allocated to
each facility will be established by EPA based usually on
explicit guidance in the statute itself. There may be some
decisions that individual utilities can make that will affect to
some degree the amount of allowances. But once they have their
initial allocation of allowances, a utility can do anything they
want with those allowances. They can use them to cover actual
emissions at a particular facility, they can overcontrol the
facility and sell excess allowances to someone else, overcontrol
and use allowances elsewhere in the utility system, or
overcontrol and hold allowances for some subsequent year.
Any excess allowances at the end of one year can be carried
over to the next year. A series of bank accounts that EPA will
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maintain for each allowance holder will be used for allowance
tracking. This allowance account will indicate the current
number of allowances available to the utility in every year, and
will also be used to record any transactions that the utility
undertakes. At the end of the year, when EPA receives reports
from the utilities, we can verify that there are allowances to
cover all of the actual emissions from the facility.
Permitting
The permit establishes the basis for compliance with the
acid rain program. The program is designed to be flexible. We
have structured the permit system to provide national consistency
in the types of information that must be provided and the kinds
of detail that a facility must provide. In addition, we want to
ensure that the program provides us the basic information that
EPA needs to effectively manage the program and to ultimately
transfer the permit program to the state agencies who will be
responsible for its implementation in the latter part of the
decade and beyond.
The permit itself will be associated with a compliance plan
requirement. This means that a utility must indicate to EPA its
manner of complying with the requirement. The compliance plan
can be as simple as a statement that the utility will have
sufficient allowances to cover their emissions.
Some utilities may choose to take advantage of some special
features of the program, which allow them to obtain extra
allowances if they perform certain tasks. In the first phase of
the program, which covers the 110 major emitters that will be
regulated as of 1995, there is an option available to at least a
certain number of facilities who elect to use 90% or greater
removal technology in scrubbing their emissions. There are
similar provisions for utilities that use new technology in the
second phase; this phase affects the bulk of the remaining
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utility facilities in this country and takes effect in the year
2000. There are a number of other special features that are
available, depending on the state, the utility, and so forth,
that are addressed in the compliance plan and that help EPA
decide the allowance allocation. Once the permit is approved by
EPA, it becomes the binding agreement between the utility and EPA
that subjects the utility to enforceable requirements.
Monitoring
Related to the permit is the mechanism by which we monitor
the emissions at the facility. Continuous emission monitoring is
the key vehicle. We conducted an extensive set of discussions on
how rigorous a monitoring program would be needed to implement
the acid rain program. In the end, we decided that a very
rigorous monitoring program with high levels of accuracy,
reliability, and quality assurance was needed to create public
confidence that this market-based system was functioning
properly. Such a program was also needed to safeguard the
currency that we were creating. The emission monitoring
requirements are the "gold standard" for the allowance currency
that we are creating in this trading program. By ensuring that
the emission reporting is accurate, reliable, and unbiased, we
will ensure that there will be credibility, that this program is
delivering the promised environmental results. The continuous
emission monitoring regulations go well beyond what EPA has
traditionally required in terms of the degree of precision in the
monitoring technology itself, the quality assurance program, and
the certification process. There are also built-in incentives to
maximize reliability. When monitoring data are unavailable, the
facility is penalized through the use of worst case assumptions
to fill in the missing data gaps. We have designed the program
in this way to create the maximum economic pressure to install
and maintain a highly reliable monitoring system.
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Excess Emissions
The fourth key regulation addresses what happens when
something goes wrong. At the end of the year, each utility must
demonstrate that it has at least enough allowances to cover the
total amount of emissions. According to the proposal, there will
be a 30-day reconciliation period in January during which the
utility can "clear their books." This provides extra time for a
utility, for example, to buy allowances to cover any shortfalls
in their accounts. This was designed to accommodate utilities
that may face unexpected peak demand in December (e.g., a cold
spell). After this period, if an excess of emissions over
allowances that are held in the utility's account remains, the
utility must pay a penalty of $2000 for every excess ton of
emissions over the allowance amount. They will be further
penalized by removing excess allowances from their subsequent
year accounts. In essence, the utility will be paying for those
emissions two or three times. Our initial expectations were that
the actual cost of an allowance in the marketplace will be about
$400 to $500/ton. This indicates the degree of penalty and
incentive that is built into the system.
There are other components, such as a small amount of
allowances that EPA is obligated by law to auction and another
batch to sell. We are in the process of issuing the final
regulations concerning that process. There is also an optional
provision in process that will allow nonutilities that want to
reduce their S02 emissions to enter the marketplace and sell
their emissions. But basically the package that we proposed is
the core of the program. We are open for comments, and we will
be finalizing the program in the spring.
In summary, we are delighted with the cooperation that we
have received from all the parties interested in these
regulations. These regulations will not only put in place a
solid acid rain program, but will also set the benchmark for the
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next generation of environmental regulation in this country.
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Session 1
Clean Air Act Compliance Issues/Panel
Panelists:
Alice LeBlanc, Environmental Defense Fund
Craig Glazer, Chair, Ohio Public Utilities Commission
John Palmisano, AER*X
Karl Moor, Balch & Bingham
Moderator: Steve Jenkins, Tampa Electric Company
INTRODUCTION
Jenkins: This morning, four panelists will discuss the
birth of the free market allowance trading system, how it was
formed, when it was formed, how it was sold, how allowance
trading has worked, how it is expected to work, and how utilities
are planning based on allowance trading. We will also hear from
a utility commissioner who will make some of the final decisions
on cost recovery. So we will have various perspectives today on
allowance trading. Many of you are here to learn more about how
to comply with the Clean Air Act Amendments of 1990. Allowance
trading is the cornerstone of the entire Title 4, the acid
deposition title of the amendments, in which S02 emission
allowances are a tradeable right. Following the four
presentations, we will entertain questions to the four
participants from the audience.
ALICE LEBLANC
Jenkins: Our first speaker this morning is Alice LeBlanc
from the Environmental Defense Fund (EDF). An economist at EDF,
Alice analyses policy options for controlling atmospheric
pollution, including acid rain, and in the future, global climate
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change. She worked with Dan Dudeck, who many of us know as the
father of allowance trading or the market-based system, to put
together allowance trading for the Clean Air Act Amendments of
1990. Alice also serves as a member of EPA's acid rain advisory
committee. She will discuss the allowance trading system and
market-based trading.
LeBlanc: In my remarks today, I'm going to explain the
basic provisions of Title 4, the part of the 1990 Clean Air Act
that limits utility emissions of sulfur dioxide and nitrogen
oxide. I will also outline some of the important state
regulatory issues and the market opportunities for utilities that
will emerge from the innovative emissions trading part of the
Act.
More than two years ago, President Bush altered the
political terrain surrounding clean air legislation by announcing
administration proposals to address acid rain, nonattainment, and
toxics. In June 1989, he credited the EDF with applying creative
solutions to long standing problems—for not only breaking the
mold, but for helping to build a new one. The acid rain
provisions that have survived the congressional process mandate
strong environmental goals that will help mitigate the
destruction of lakes and forests by acid rain. In addition, they
introduce a market-based policy of emissions trading to solve the
problem in a cost-effective way, to stimulate innovation in the
electric utility industry, and to serve as a critically important
precedent for other atmospheric pollution problems.
The new legislation imposes limits on sulfur dioxide
emissions in two phases. In 1995, 118 plants with emissions
rates greater than 2.5 pounds of S02 per MMBTU will be subject to
reductions. In the year 2000, almost all plants will be brought
into the system, and those emitting at a greater than 1.2 pound
rate will be required to reduce emissions. The legislation
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establishes a permanent cap on utility S02 emissions by the year
2000 of 8.9 million tons, roughly a 50% reduction from 1980
levels. Utilities that overcontrol, that is emit less than is
required, may sell their excess allowances to others that would
prefer to buy allowances rather than control. Banking of
allowances is allowed. A utility can overcontrol today and save
for its own future growth, or to sell to other utilities. New
entrants must purchase allowances from existing sources.
"Banking" means that any overcontrol today can be used later to
provide allowances for new entrants after the cap is in place.
EPA determines the allowances each plant receives according
to a formula based on past utilization. Allowances are
denominated in tons of S02. Targeted utilities are not all
alike. They vary by age, location, and type of system. Cost-
effective control options also vary and include installing
scrubbers, switching to low-sulfur coal or other fuels, improving
supply-side efficiencies, adopting conservation programs, buying
power, combining plants or substituting plants for compliance
purposes, or adopting advanced technologies such as clean coal
technologies. The result is a wide range of cost differences,
and these cost differences lead to trading. For example, a plant
may install a scrubber and reduce emissions by 90%. It may sell
excess credits to another older plant, for which installing a
scrubber is more costly. That plant may meet its target using a
combination of blending with lower-sulfur coal, conservation
programs, and buying permits.
Emissions are determined by continuous emissions monitoring
systems—smokestack devices required in all targeted plants.
Monitoring reports are tallied annually, with variation in
monthly discharges allowed. Every year, the accounts are
balanced, much like a check book. If a utility holds allowances
for more tons than it has emitted, it retains the additional
allowances. If it does not have adequate allowances, it must buy
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some allowances. Stiff penalties are assigned to any plant that
emits more than the amount of allowances it has acquired. The
penalty is $2000 per ton plus compensating emissions the
following year.
Within the eastern United States, emission allowances are
expected to flow from the states that have the largest required
reductions—the Midwest and parts of the Northeast. Scrubbing
will be cost effective in these areas and will result in the sale
of excess allowances to states for which scrubbing is not a cost
effective strategy, or to states that require extra allowances
for growth.
Regulations developed by EPA are essential to the
functioning of the market. The goal of EPA trading regulations
should be to reduce transaction cost and regulatory hassle. They
must ensure that compliance will be achieved and that flexibility
is allowed for utilities in making their compliance decisions.
EPA created an acid rain advisory committee consisting of
interested parties, including utilities, environmentalists, and
state regulators, and held a series of meetings to solicit advice
in writing the regulations. Based on the draft proposed
regulations, it appears that the allowance tracking and trading
rules will conform to the criteria of simplicity and flexibility.
The Chicago Board of Trade announced that it would act as the
central exchange for utilities who wish to trade and will
institute an all-electronic trading system. In addition, it is
applying to create a futures market for S02 allowances.
Today, the role of public utility commissions (PUCs) is very /
important. Their attitude should be in keeping with the
legislation—to encourage trading. High growth states have the
most to gain from a trading system. Rather that focusing on
hoarding allowances, they should actively participate in the
market as buyers.
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Important PUC regulatory issues that could help or hinder
trading include a prudency review of allowance trading. PUCs
will need to determine when the purchase or sale of allowances is
a prudent compliance strategy, that is, when it is the least cost
compliance option. Guidelines for prudent purchase or sale of
allowances need to be established so that utilities can trade
with some degree of assurance. Given the fundamental
uncertainties in the cost of compliance over time, it is useful
to have a risk management strategy. The Chicago Board of Trade
futures market should provide a means to manage these risks.
Another consideration is the review of banking of
allowances. Allowances can be banked by individual utilities for
compliance purposes, that is, as a cushion for unexpected changes
in emissions. Utilities might also decide to form banking pools
as an insurance policy. Each utility in the group would deposit
a smaller number of allowances in the pool than it would if it
were saving for compliance purposes on its own. Utilities might
also bank for investment purposes, that is, to sell allowances in
the future at a higher price. Rules need to be established to
determine the prudency of these types of banking arrangements.
Another question to be resolved is how to divide the
proceeds from the sale of excess allowances between ratepayers
and shareholders. Allowing some of the profits from the sale of
excess allowances to accrue to shareholders would provide an
incentive to the utility that can do so cost effectively to
overcontrol and sell excess allowances.
Finally, some accounting procedures may also effect a
utility's willingness to buy allowances. For example, if
allowances are purchased for compliance, the cost could be rate-
based, as would the capital cost of installing a scrubber, or
considered to be an operating expense. Allowing utilities to
earn a return on the purchase price of allowances could provide
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an incentive for this compliance method.
Allowance trading introduces a new dimension in utility
planning. Strategies that do not include trading will be more
costly. The utility will still strive to minimize cost, but the
net cost equation now includes the buying of permits at a market-
determined value and the sale of permits as a revenue source.
Step one is a consideration of the full range of in-house
control options. The wide range of possible control measures
enables utilities to select measures that are also beneficial in
terms of C02 reduction. In-house marginal cost should be
compared to the value of permits. Options, the futures market,
and actual transactions should provide market signals on price.
In addition, forecasts have been and will continue to be made of
allowance values. Unless a utility's in-house marginal control
costs are the same as the market value of permits, there should
be a financial advantage to either overcontrol and sell,
overcontrol and bank, or undercontrol and buy.
The supply cost of S02 reductions will undoubtedly change
over time as new control technologies are developed and as plant
efficiencies increase in response to the incentives in the
legislation. This results in a shift to the right in the current
supply curve and a resulting decrease in the marginal cost of
sulfur dioxide reductions at a given level of overall reductions.
The dynamic behavioral responses created by the market should
help to offset increased demand as new plants enter the market.
The time is here to implement the new acid rain legislation.
The time is here to work together to make the innovative and
cost-effective new policy tool of emissions trading work for the
benefit of the environment, the economy, and the utilities'
bottom line.
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CRAIG GLAZER
Jenkins: If you have not sat down and read the 795 pages of
the proposed regulations, now is a good time. Some controversial
parts remain. This is one of the reasons that the acid rain
advisor committee is meeting again—addressing many of the
implementation issues. Phase 1 affected utilities have many
decisions to make in the next few weeks. Examining the proposed
regulations as they will formally appear in the Federal Register
will be important.
Our next speaker is Craig Glazer, the Chairman of the Public
Utility Commission of Ohio. Craig will be discussing a utility
regulator's point of view of allowance trading. His work with
utility companies began as the Chief Utility Rate Council for the
City of Cleveland. Working there for the mayor and the
administration of the city, he represented residents and city
agencies before the Public Utility Commission of Ohio. Later in
private law practice, he represented industrial companies seeking
special rates and services from utilities of different types—
telecommunications, gas, water, and electric. On February 20 of
this year [1991], the Governor of Ohio appointed Craig the
Chairman of the Public Utility Commission of Ohio. Two of the
big issues that he has to address on that commission include
developing a comprehensive energy plan for the State of Ohio and
working with Ohio utilities, primarily American Electric Power
(AEP), to implement the requirements of the Clean Air Act
Amendments of 1990. He has the tough job of balancing Ohio
resources, Ohio coal miners, utility ratepayers, and cost.
Glazer: Ohio has the most to lose but also the most to gain
in terms of Clean Air Act compliance. I believe we are ahead of
others on these issues. Although I've only been in office since
April 11 [1991], this has been an issue on which I have spent a
great deal of time, and one on which the commissions have to work
with utilities.
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In Ohio, we must cut emissions substantially to comply with
the Act. Twenty-one of AEP's coal-fired units are Phase 1
affected—six owned by Columbus Southern Power, two owned by
Indiana and Michigan, and 13 owned by the Ohio Power Company,
based in Canton, Ohio. Collectively, they emit 1.2 million tons
of S02 per year, and they must be reduced by 54% in Phase 1.
Then, all of AEP's units are Phase 2 affected.
This is the negative side. On the positive side, Ohio has
one of the most active Clean Coal Technology programs in the
country. The people of Ohio voted a major bond issue to support
Clean Coal Technology, and we have some exciting technologies.
These include the Tidd Plant; the Burger Plant operated by Ohio
Edison, which is looking at SOx-NOx-ROX removal; the Toronto
Plant; and others. Now, we need the time and the leeway to make
these technologies commercial.
Ohio is a coal mining state. Although actually a small
industry in Ohio (about 5000 coal miners), it is concentrated in
southeastern Ohio and the Appalachian region—an area without
many other resources. So it is a major industry to one part of
the state. But on the other hand, Ohio is also a heavy
manufacturing state—making it a classic microcosm of the
country. We have many jobs still associated with steel and
glass, as well as heavy industries that are extremely electricity
intensive.
We also have diverse utilities. In addition to AEP, we have
the Monongahela Power Company, which serves only about 28,000
customers in Ohio and has already submitted an extensive clean
air compliance plan. In the northern part of the state, Toledo
Edison has one of the highest electricity rates in the nation but
has zero compliance costs, at least in Phase 1.
In Ohio, it is important that we take the lead on these
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issues, because we have the most to lose if we do not. I use
four guiding principles to do this. One principle is the need to
be proactive in promoting an active market in allowance trading.
Regulators have a role to play in this, and an active market is
in all of our interests. The second principle is the need to
take steps on a systemwide basis. Without looking at a
systemwide plan, calculating the value of emissions allowances
produced by overcompliance is impossible. In this case, you
simply implement a fuel switch scenario, believing that it is the
least cost scenario without looking at the value of
overcompliance. My third guiding principle is the need to
involve other states in this process; it must be a regional
process. Ohio cannot go one direction, Indiana another
direction, and West Virginia a third direction. Utilities and
regulatory commissions in the regions need to start talking to
each other. The fourth guiding principle is the need to examine
all the alternatives, including active emissions trading, demand-
side management (DSM), gas co-firing, etc.
Ohio followed this integrated resource planning process.
AEP had a pending rate case when they made their announcement
concerning the Gavin plant in January 1991. We immediately asked
our staff to analyze their plan. It related solely to Gavin and
the question of whether to fuel switch or scrub at that plant.
That plant is undoubtedly the linchpin of the entire strategy for
AEP. I'm sure that for many of your companies, there is also one
plant that is the linchpin. The staff reported in April of this
year that this analysis is not possible on a plant-by-plant
basis. You need to examine the value of overcompliance at a
particular plant to hold down the cost of compliance at other
facilities within the system. As a result, the Commission
ordered AEP in April to develop a systemwide compliance plan. On
May 31, AEP filed a systemwide plan.
This process requires the following steps: First, you
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determine the range of feasible options for your generating
units—scrubbing, switching, gas co-firing, retirement, no
action, buying allowances, DSM, etc. Simply write down all the
various options that could be available, then perform a plant-
specific analysis of each option. Then, rank the options by cost
effectiveness, expressed as dollars per ton of S02 removed.
Basically, calculate an incremental cost of compliance over a
base case, which assumes that no compliance is required.
Determine the cost of treating the next ton of S02 emitted from a
plant. To do this, you must examine all of the costs, including
the direct cost, the construction cost of the scrubber, the
incremental fuel cost, any costs associated with derating, and
emissions credit allowances. The key is to rank all of the
options and look at delaying or reducing strategies at other
plants. Then, select options from the ranking orders to meet S02
requirements, run a production model to make sure that you are in
compliance with the Act, and finally collect and calculate the
revenue requirements for each option. It is not an easy task,
and many assumptions are involved. Although we had some concerns
with the model that was submitted, the concept of ranking options
in terms of incremental cost of compliance was worthwhile.
In September of this year, we analyzed all of the risks and
issued an order indicating that it was too early for AEP to
eliminate either option—fuel switching or scrubbing at Gavin.
First, we asked them to examine the scrubber cost in incremental
revenue requirements over the life of the scrubber. The
difference between fuel switching and scrubbing was in some cases
at least less than 5%.
We also weighed the risks of various options. For fuel
switching, some numbers showed that the fuel switching market was
soft and showed some remarkably low coal prices. However, we
were concerned about a company like AEP becoming captive to low-
sulfur coal markets and transportation. The question was whether
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we should base our entire strategy on fuel switching. We were
also especially concerned about the outlook for Phase 2. What
would happen to the coal market for other utilities in Ohio and
elsewhere if large entities like AEP buy all the coal that is
available and then need to purchase coal on the market at a
critical time in Phase 2? Also, Ohio had invested millions of
dollars in Clean Coal Technology—technology that we see as the
future. We did not want to significantly damage development of
that technology.
On the other hand, there were uncertainties associated with
scrubbing. The primary one is the telephone queue system for
allocating bonus allowances being promoted by the EPA. This
issue is increasing the uncertainty associated with scrubbing.
We have spoken out on it many times, and I understand EPA is at
least considering the question of whether a telephone queue will
be implemented. They understand that "hackers" can break into
the system and change the final outcome. But we also directed
AEP to determine what can be done to reduce risks. I'm pleased
to see that Edison Electric Institute (EEI) as well as our
utilities have been examining the possibilities of some agreement
outside of the official EPA rules to share allowances between the
winners and losers. We want utilities to act reasonably, but I
view the process underway at EEI as an insurance policy. As
regulators, we do not deny insurance premiums on the basis that
there were no claims that year. Undertaking an insurance policy
is prudent, especially given the uncertainties of the market.
So, we have been supportive of those efforts underway at EEI.
Regarding the allowance market, we examined the value of
overcompliance by measuring the marginal cost of eliminating or
postponing actions and activities at other plants. On the
subject of alternative ways to obtain allowances, all of us seem
to be fixed on the scrub and switch option, but the law does
provide much flexibility. Although we have not taken a position
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in this area, it is something for all of us to consider.
Allowances could be transferred for cash in return for an equity
interest in an independent power producer (IPP) option, as part
of a coal transaction. High-sulfur coal producers could enter
the allowance market so that you could buy their coal, and they
will provide you the allowances you need to burn it as part of
the transaction. Allowances could be brokered as part of payment
for purchased power. They could be part of an incentive and risk
sharing mechanism; a scrubber manufacturer or designer could
manufacture, design, and operate the scrubber and provide some
allowances. These are options that we fail to consider at times.
In addressing this issue, we need to think big, we have to think
long term, and we have to think of what kind of alternative and
creative options are available. We regulators are certainly
interested in hearing those options.
Regarding a multistate system, I recommend that regulators
negotiate together and focus on key issues. We have undertaken
this process in the AEP region in the form of meetings between
the Commissioners of Ohio, West Virginia, Michigan, Kentucky,
etc. The fundamental issue is whether you overcomply and use all
of the allowances within a system or whether you sell them on the
open market. You can then compensate each of the affiliated
companies in some way. This raises the larger issue of whether
banking becomes hoarding of allowances. In Ohio, we are on
record as to the importance of liquidity in the market. While we
want people to take prudent measures, we have to examine some
incentives to ensure that there is an active trading market.
Trading will make allowances valuable.
The last issue I want to discuss is legislation. When I
first took this job, I immediately became embroiled in
legislation on a battle underway at our general assembly on fuel
switching at Gavin. Fortunately, we did not end up with a
situation such as occurred in Illinois, where scrubbers were
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mandated at a particular location. By involving many people, we
balanced the playing field. Ohio is a "cancelled-plants" state,
which means that costs of cancelled plants cannot be recovered in
Ohio. However, we have made an exception to this rule for
changes in regulation associated with Clean Air Act compliance.
We set up a system of voluntary preapproval of a utility's
compliance plan, not of construction prudency (inappropriate for
commissioners). Only one utility so far, Ohio's smallest
electric utility, has taken advantage of this option. We also
adopted tax credits and various other options.
The bottom line is that we all need to work together, we
need to think through this process. The more dialogue you have
with your regulators, the more focused they will be. This is the
way to the future and may avoid some of the nervousness with
regard to prudency disallowances.
JOHN PALMISANO
Jenkins: Our next speaker on the panel is John Palmisano.
President of AER*X Inc., John manages offices in Washington D.C.
and Los Angeles. He's active in all phases of air permitting,
including developing air inventories, regulatory programs, new
source reviews, buying and selling air emission credits,
developing bubbles, and revising state implementation plans. He
is also Vice President of the Institute for Environmental
Auditing and editor of the Environmental Auditor. He will cover
how this trading has worked in the past and how he expects it to
work in the future.
Palmisano: I'm going to cover air credit trading—past,
present, and future. The idea of air credit trading began 30 or
40 years ago with a paper a Canadian economist wrote. These
concepts became memorialized in 1976 in what was called the
Offset Interpretive Ruling and then became incorporated into the
Clean Air Act Amendments of 1977. Since then, there have been
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over 2000 offset transactions. This number is probably closer to
3500 offset transactions, several hundred of which were arms-
length transactions between two distinct parties, most within the
same entity (e.g., Exxon in Houston trades with another Exxon
facility in Houston). In 1979, the Bubble Policy was developed.
In 1980, the concepts of offsetting and bubbling and banking that
were then developed became the subjects of discussions in the
EPA. In about 1986, they were incorporated into the Emissions
Trading Policy Statement. All these developments are building
blocks and steps toward allowance trading, what I believe will be
greenhouse gas trading, and what we have under Title 3 of the
Clean Air Act—air toxic trading.
It will be important for you to understand and proactively
shape compliance decisions using these tools. Because any new
source or major modification anywhere on the East Coast will have
to address offsets or netting. If it is a combustion source, it
will have to address acid deposition. In addition, you will need
to contemplate greenhouse gas legislation, either fee tax or
marketable permit program. So if you do not understand the 900
pages of the draft regulation and the 2000 pages of forthcoming
regulations, you are will not be able to develop least-cost
compliance alternatives for your clients or your organizations.
For transactions in which we have been involved since 1985,
prices have increased. The Los Angeles area, called the South
Coast Air Quality Management District (SCAQMD), is the largest
air pollution control district in the country. Since 1985, there
have been over 100 offsetting transactions in the SCAQMD for
compliance with Title 1 provisions—ozone nonattainment concerns.
The variance about these prices has collapsed over time, as would
be expected in any kind of market. An embryonic market will have
a wild variance, because it is predicated on conceptions, rumor,
gossip, and some fact. As more transactions occur, more networks
of people are established, and more newsletters are developed,
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the variance decreases. Today, various people can provide you
L.A. offset prices. This will also occur with S02 allowances and
greenhouse gases in the future.
In the L.A. offset market, prices have been increasing by
30% per year. The most recent price was $2500 per pound per day
for ozone in L.A. The highest price for ozone in L.A. has been
$3500 per pound per day. Most permits in California, and I think
around the country, will be written in pounds per day. The units
of price for S02 allowances will be in dollars per ton per year.
In the documents that EPA supplied last year, projected S02
allowance prices were high and were not useful for decision-
making purposes. Prices will not be $400 in 1995, '96, '91, '98,
and '99, and $800 starting in 2 000. Also, fuel prices have been
flatter, and the supply curves for coal are much flatter. The
marginal cost for power river coal is pretty low.
Of course, no data are yet available for S02 allowance
prices. In the absence of actual data, there are three ways to
forecast allowance prices: conducting surveys, running the
computer simulation model we have developed, and using classical
microeconomic and financial techniques.
We have conducted surveys almost every quarter (four or five
to date). We learned the following from the surveys: Eighteen
months ago, about 20 people in the electric utility industry were
knowledgeable about emission credit trading. Now, there are
hundreds of people who know something about this subject. In two
years, hundreds of people will be very knowledgeable. The
industry has progressed up a phenomenal learning curve. Networks
are developing within the industry, and people are becoming much
more realistic about the perception of allowance prices and how
the system works. According to the results of the survey, some
people believe that prices will continue to rise slowly in the
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future. I have no idea what people have on their minds when they
respond to these surveys.
In one of our surveys, we found that the organizations that
knew the least and had the greatest variance in their projection
of S02 allowance prices were public utility commission staff
members. We are concerned about this. In a study performed
about three years ago on all public utility commissions, only 3%
had ever issued an opinion regarding an air pollution control
technology or issue. It is critical that these staff members
become more familiar with these systems.
According to economic theory, in an embryonic market in
which people do not know much about prices, you would be willing
to sell something at 2-1/2 to 3 times the price you would pay to
buy the same item. Hence, an average utility would be willing to
spend $250 or $300 to buy allowances, but they would only sell at
about $800. Everyone is afraid to make a mistake. So if we buy,
we buy at a good price, and if we sell, we sell at a good price.
You would never see this kind of response in the L.A. market for
hydrocarbon credits because people know the last three or four
prices. Everyone knows the market.
Understanding how the market will behave will put you in a
good position to be proactive. You need to know what you think,
what other people in the organization think, and what other
people in the larger community are thinking. You have to know
something about market fundamentals, and you have to understand
your options.
The bottom line is that a trade-off exists between risks and
rewards. If there are no risks, there will be no rewards, and
vice-versa. That is, if individuals cannot realize benefits from
the decisions they make, nobody takes any chances. If there are
no benefits that can be realized by the organizations, there will
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be no trading. Public utility commissions and people in this
room are going to be making the key decisions in the future; EPA
is essentially uninvolved. You will have to make decisions on
the risk/reward split. If ratepayers realize all the benefits,
and stockholders absorb all the risk, we will not see hedging and
speculating of S02 allowances. If there is some reasonable
split, then risks will be taken; it is a risky proposition to buy
and trade these credits like it is risky to buy and sell any
asset of your organization.
KARL MOOR
Jenkins: Our next panel speaker is Karl Moor. Karl
practices with the utility legislative and regulatory section of
the law firm of Balch & Bingham in Washington D.C. Before
joining the firm, Karl held various posts in the U.S. Senate,
including Staff Director of a Subcommittee of the Senate Labor
and Human Resources Committee, and a Senior Legislative Assistant
and Professional Staff Member on the Senate Judiciary Committee.
He was involved in the legislative process leading to passage of
the Clean Air Act Amendments of 1990, serving mainly as the
legislative council to the Southern Electric System (Southern
Company). He is currently serving on the Federal Energy Bar
Association's special subcommittee on the regulatory implications
of the Act.
Moor: From the utility perspective, the Clean Air Act
Amendments of 1990 have created the opportunity for both risk and
reward. Unfortunately, in reviewing the current regulatory
landscape, I believe that utilities perceive more risk than
reward. This is not what utilities wanted. In fact, during the
legislative process, utilities were careful to argue both to
state and Federal regulators and to Congress for legislation to
more clearly define the role of state public service commissions
and of the Federal Energy Regulatory Commission (FERC) in
implementing the Act. The industry also recognized that recovery
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and compliance cost was going to be one of its most important
issues. Utilities need to recover the huge capital costs
associated with the Clean Air Act Amendments of 1990. Some
utilities, therefore, approached regulatory agencies and
suggested that Congress be encouraged to recognize in the
legislation an all-pervasive role for FERC. This is an
understandable motivation when you consider that utilities,
particularly multistate utilities, will need to work with more
than one commission in seeking recovery for these compliance
plans.
However, Congress rejected the notion of resolution of
regulatory issues in advance. In fact, they created what might
be called the "grand stand-off." They inserted a provision, I
believe it is section 403, that preserves both the jurisdiction
of the state public service commissions and the jurisdiction of
FERC.
This stand preserved 50 years of utility regulatory law and
forced us to convince regulators to make the decisions we desire.
However, it did not resolve the following key questions: Will
utilities benefit from the allowance system? Should they
approach their state public service commissions and seek
regulatory preapproval for their actions under the Act? Will
they simply pass the benefits of the allowance system on to the
ratepayers and to their other customers without realizing any of
the benefits for themselves? Will state regulators use the
control of allowances in a way that will ultimately harm the bulk
power markets, those markets that are subject to FERC
jurisdictional control?
There are many other questions that can be raised about the
regulatory burden with which utilities are faced. However, these
questions can be summarized in three basic categories:
accounting issues, taxation concerns over the treatment of
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allowances once they are actually in the hands of utilities, and
planning questions.
The industry is working in a number of forms with its
regulators to answer these questions. On example is the EEI Tax
Analysis and Research Subcommittee. The Federal Energy Bar
Association has a special committee examining the regulatory
implications of the Act. The EEI has a special task force
underway to explore regulatory issues. The Keystone Center in
Colorado has a dialogue underway between state regulators,
environmentalists, utilities, and others. The EEI has also
worked with NARUC to develop a joint CEO/NARUC dialogue.
On the accounting treatment, FERC has released its
accounting guidance on the treatment of allowances. While there
was a need to provide clear guidance for accounting personnel,
FERC realized that this document was not necessarily the
appropriate form in which to provide all of the answers or to
derive policy with respect to allowances. Nevertheless, this
document will provide some clues as to how at least one important
regulatory body views the allowance trading market.
With respect to the planning issues, one key point is that
there are many inputs to the calculation of the market price of
allowances. Small changes in the way the market is functioning
can change the supply of allowances. This leads us to the basic
question that the industry is facing: What do we do with the
allowances? How is it that we can recover or take advantage of
this new cost-sharing mechanism?
There are three instances in which the pricing of allowances
is particularly important. The first involves the pure allowance
market between brokers and others who are trading allowances—not
the market associated with compliance, nor that associated with
bulk power sales. Our simple view is that in the instances where
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allowances are "freed up," there should be no regulation. A free
market and market pricing should prevail. This notion has
widespread support within the administration and also I believe
within the EPA. It is certainly evident in EPA's regulations,
which take a hands-off approach toward regulation of the market,
and in the bank account system that they have established for the
transfer of allowances. The legislation is fairly clear on the
point that when allowances are available, the market should
function without undo Federal or state regulation.
The more difficult instance, particularly for multistate
utilities, is the transfer of allowances between operating
companies of a multistate utility. The legislation contains a
specific provision that exempts allowance transactions from
regulation under the holding company act. As a result,
multistate utilities will probably be able to transfer allowances
between affiliates at something approximating a market price.
However, this causes some difficulties. The overcomplying
state in the multistate utility will want full recovery for the
price of allowances. Market pricing of allowances makes sense if
you are installing control devices for which ratepayers in a
given state are paying. But the sister utility and its
regulators could take a different view. They might argue that
since it is a multistate compliance effort, and since we're
sharing the risk, benefits, and rewards of the program together,
at-cost pricing should prevail. This disagreement will need to
be resolved. At some point, FERC may examine whether it should
assume jurisdiction over multistate compliance planning and
resolve the dispute in a way that shows utilities how they can
recover costs between the operating companies of a multistate
utility.
The other uncertainty involves determining appropriate
market pricing once you transfer allowances, both within and
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outside a system. There is increasing optimism, due to the
Chicago Board of Trade decision and the EPA's early auctions,
that a measure you can use to determine market pricing will
exist. Bulk power transactions account for about 30% of the
transactions in energy in this country. One of the questions
that has been raised is whether or not utilities are going to be
able to market price their allowances that are sold in
conjunction with sales of electricity.
Various commissions have been developing approaches to
regulatory preapproval. In some instances, the approaches appear
encouraging, and in other instances, they resemble "command and
control" through an allowance system. Nonetheless, there is
optimism that the regulators will favor the creation of a market
in the free use of allowances. The value of an allowance will be
an important part of a basic understanding between utilities and
the commission as you formulate your Phase 1 and Phase 2
compliance plans. If you can agree on that base number, you'll
be much closer to establishing compliance plans for five, ten, or
fifteen years. State public service commissions can probably
find creative ways to reward utilities that make good solid
decisions about the market price of an allowance and to penalize
those utilities that cannot cope with this new market.
Like regulation of greenhouse gases and new S02 standards,
the air toxics provision could have a dramatic impact on the
allowance market. When you consider the bargain that was made,
that is, the allowance system and flexibility for greater control
of S02, the utility industry has the right to request that
Congress leave in place what was first created. The allowance
system should not be destroyed by undertaking unnecessary
controls of air toxics emissions three or four years in the
future. If the air toxics provision leads to installation of a
great deal more technology, it could destroy the system that
Congress put together in 1990.
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QUESTION AND ANSWER PERIOD
Carl Cruise, Illinois State Geological Survey: Could any of
you respond to the possible public concern over trading in these
allowances to do them harm.
Leblanc: In the context of the acid rain legislation (Title
4), which establishes the permanent cap (a 50% reduction from
1980 levels), the allowance system is not going to do harm. It
is going to help bring about reductions in a cost-effective way.
Palmisano: In addition, Title 4 does not address ambient
air quality. It is ambient air quality issues that concern you,
and that is covered in Title 1, the national ambient air quality
standards. There are already protections on ambient air quality.
Of the thousands of offset transactions, there may never have
been a transaction that has resulted in a decrease in ambient air
quality. Air toxics trading is a different issue.
Moor: However, the question raises another facet of the
regulatory quandary in which utilities find themselves. Despite
what has been said, all of which is true, there are some state
environmental regulators, not utility regulators, that have
talked about irrational uses of allowances. There has been at
least one governor who has questioned whether the allowance
system should be allowed to function if it results in a greater
amount of deposition of acid rain on particular regions of his
state. That kind of concern and the potential for interference
that it creates could impinge upon the allowance market and upon
the decisions that utilities make about the forms of control that
they will undertake.
Mildred Perry, DOE: Who besides utilities will be able to
buy S02 allowances? For example, could Canada buy all of the S02
allowances from Ohio?
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Moor: The Act will allow any person to purchase, own, and
trade bank allowances.
Palmisano: The fairness of the transaction and the fairness
of the value that is being received should be of principle
concern to regulators. If we start discussing issues like 'what
is this doing to my state,' we will over-politicize the market
and all have big problems. Fifty states will never come together
on that issue, nor will Congress.
LeBlanc: This legislation represents a huge reduction in
S02 emissions, and the market is established to facilitate a
major environmental improvement. People are seeing it in the
wrong light when they view it as a detriment to the environment.
Ed Ruben, Carnegie Mellon University: Regarding the
potential for air toxics to complicate the S02 issue in the
future, do you know if utilities in Phase 1 planning are (1)
aware that fuel switching might either increase or decrease their
inventories of toxic emissions, and (2) determining those numbers
or taking them into consideration?
Moor: I know that studies are underway to determine the
various levels of emissions. There may be some pilot programs in
which EPRI is involved, both on the control side and on the
quantification side. In terms of the impact on Phase 1
decisions, I think most utilities are considering the possibility
of air toxic controls, but are probably feeling that they have
escaped regulations under the air toxics provisions, at least for
three or four years depending on EPA actions. Given the high
cost of simply trying to meet compliance deadlines in a timely
fashion (1995), most utilities probably have not been able to
take into account potential air toxic regulations.
Bernie Koch, Consolidation Coal Company: Are utilities
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examining integrating Phase 1 and Phase 2 compliance strategies
to determine the least-cost compliance strategy over the long
term? If they are, how will that impact the emissions trading
market?
Glazer: We thought it was essential that we take a long-
term view, because the emissions trading market does not work if
you are focused only on Phase 1. You would never overcomply. In
Ohio, we added an amendment to our legislation, sponsored by the
commission, which stated that the planning horizon for clean air
compliance planning shall be Phase 1 and Phase 2 requirements.
The amendment was appropriate, and our entire Gavin decision was
based on it.
Palmisano: I personally know of at least 15 utilities who
are doing it exactly the way you suggest. They are using
production models, looking 20 years in the future, examining DSM,
supply conditions, and other factors. The only shortcoming is
that when you use an optimization technique, you do not build in
risk mitigation and stochastic events—you are driven to a
solution. But you have other serious issues to consider, such as
the greenhouse gas issue, air toxics, the variable allowance
price, and open access. A deterministic model may fall short.
You need to use more than one analytic tool.
Dennis Moftey, Environmental Ontario: Is any thought being
given to implementing a continent-wide (North America) trading
system. Are similar trading provisions being enacted in Canada
and Mexico?
Palmisano: There is a bilateral agreement between the
United States and Canada that deals with reductions of S02.
LeBlanc: There is definitely interest, at least on our
part, in seeing something like that occur. I know of one case
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where I believe a Canadian utility that buys power in the U.S.
has agreed to make some pollution control investments and to
finance those investments with the allowances that are going to
be generated. This is a first step. I hope that we can move in
that direction, especially since Canada and the U.S. buy power
from each other.
Palmisano: I would expect to see that occur more on
greenhouse gas emissions then for sulfur dioxide. While it may
be contentious whether or not S02 or acid deposition is localized
or global, I think there is much evidence that the greenhouse gas
issue is a global one. Some of the legislation that has already
been introduced in Congress has examined reductions in greenhouse
gases and emission credit trading among different countries and
continents.
LeBlanc: In the free trade agreement with Mexico, there is
definitely a need to establish some sort of joint pollution
standards and to establish trading between the two countries that
goes hand-in-hand with the free trade of goods.
Palmisano: There have been at least five studies sponsored
by various Canadian organizations that have examined trading
issues. We have been involved in several studies, and a request
for proposals (RFP) has been issued for developing a N0X trading
program primarily for ozone control between Windsor and Montreal.
Part of the RFP speaks to acid deposition trading and linkages to
the midwest.
Jack Fritz, World Bank: We're working in China on emissions
problems. China's centrally planned economy without a free
market makes things rather difficult in terms of looking at some
of these market mechanisms. What might work in Eastern Europe?
Palmisano: I am enthusiastic about market-based approaches,
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but you need many tools in your kit. They need an operating
permit program, and they need to control emissions immediately.
There are big targets of opportunity at the beginning. Market-
based approaches are good for some issues, primarily fine tuning.
Some market-based approaches clearly are going to be successful
there. In the former Soviet Union, Eastern Europe, and China, I
think it would be a mistake to predicate your entire
environmental program on market-based solutions.
ACKNOWLEDGMENT
The S02 Control Symposium sponsors wish to thank the members
of the Emission Allowance Trading Panel, as well as moderator
Steve Jenkins, for their participation.
DISCLAIMER
The opinions expressed in the Emission Allowance Trading
Panel are those of the speakers only, and not necessarily those
of the S02 Control Symposium sponsors.
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Session 2
CLEAN AIR ACT COMPLIANCE
STRATEGIES
SCRUBBERS: A POPULAR PHASE I COMPLIANCE STRATEGY
C. E. Fink, P. E. Bissell, B. J. Koch, and G. D. Rutledge
Consolidation Coal Company
4000 Brownsville Road
Library, Pennsylvania 15129
ABSTRACT
As utilities commit to compliance plans to meet the Phase I requirements of the
Clean Air Act Amendments of 1990, there are indications that scrubbing may account
for up to 50 percent of the total S02 reductions in Phase I. This paper presents
and analyzes the critical reasons that explain how and why scrubber-based compliance
strategies have developed into the least-cost option in Phase I for many utilities.
A hypothetical utility system was simulated to study the impacts of various
technological, legislative, and regulatory issues on compliance decisions and costs.
Issues evaluated using the hypothetical system include the emissions cap, Clean Air
Act and state incentives to scrub, improvements in scrubber technology and costs,
and the integration of Phase I and II compliance strategies by the phased
installation of scrubbers. In combination, these considerations increase the
attractiveness of scrubbers during the 1995-1999 Phase I period. Other consider-
ations that will ultimately influence the amount of Phase I scrubbing capacity
include the additional power generation costs associated with fuel switching, the
uncertainty of low-sulfur coal price projections, fuel supply flexibility, scrubber
market aspects, and socioeconomic considerations.
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INTRODUCTION
As utilities finalize their Phase I compliance choices, there are indications that
scrubbing may account for up to 50 percent of the total S02 reductions achieved in
Phase I. The prominent role of scrubbers in Phase I is the result of a combination
of technological, legislative, and regulatory developments over the past several
years that have led many utilities to the conclusion that scrubbing represents the
least-cost compliance strategy.
Technologically, there have been substantial improvements in the performance and
costs of scrubbers. State-of-the-art, "second-generation" scrubbers have S02
control costs that are 25 to 35 percent lower than first-generation technology.
The nature of the Clean Air Act Amendments of 1990 (CAA) with its marketable S02
allowances program, the cap on S02 emissions, and bonus S02 allowances for units
that scrub, has influenced utility decisions. State legislative incentives have
also been important.
Perhaps most importantly, state public utility commissions and state legislatures,
recognizing the potential for enormous socioeconomic costs that fuel switching
strategies can inflict on local economies, have taken unprecedented steps to assure
utilities that the capital costs of least-cost scrubbing strategies will be fully
recoverable.
In this paper, we assess the reasons behind the emergence of scrubbers as a popular
means of Phase I compliance, providing quantification of critical considerations
whenever possible. The results also suggest that scrubbers may play an even more
dominant role as utilities integrate Phase I and Phase II compliance strategies and
consider concepts such as phased scrubber installations and banking of allowances.
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UTILITY SYSTEM COMPLIANCE MODEL SIMULATIONS
STUDY METHODOLOGY
Compliance model simulations of a hypothetical utility system were made to evaluate
the impact of the following:
1. The S02 emissions cap provision of the CAA,
2. Technology choice of second-generation FGD compared with first-
generation FGD and with fuel switching alone,
3. Bonus allowances (incentives) provided under the acid rain provisions
of the Clean Air Act,
4. Incentives for scrubbing offered by some state governments, and
5. Integrating Phase I and II compliance strategies by the phased
installation of scrubbers during Phase I.
The hypothetical utility system represents a realistic combination of boiler units
and sizes, capacity factors, and coal burns. The utility system, the S02 allowance
calculations, and the simulation approach were discussed in a previous paper.1
System baseline performance and allowance calculations are shown in Table 1. Slight
modifications were made from the previous paper to reflect a system load growth of
two percent per year from 1990 through 2009. The allowance calculations were also
updated to reflect the CAA as enacted.
Key scrubber design and performance characteristics and costs by utility unit are
provided in Table 2. Two scrubber types are described—state-of-the-art forced
oxidation wet limestone (second-generation) and first-generation sulfite-based wet
limestone. Total annual scrubbing costs for the state-of-the-art forced oxidation
wet limestone type would also be representative of a modern thiosorbic lime FGD
process. The evolution, performance, and cost aspects of these wet scrubbers are
described later in the paper. The scrubber costs were generated using the Consol
S02 Abatement Cost Model.2 When put on a comparable basis, the Consol model results
agree well with the most recent EPRI FGD economic evaluations.3
Delivered coal prices are assumed to be a function of coal sulfur content as shown
graphically in Figure 1. To simplify the analysis, delivered coal prices for each
coal type (designated by sulfur content) were assumed to be the same for the various
units. Other simplifying assumptions were made as described previously1 to minimize
the complexity of the study.
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The objective of the simulation is to show why there is a trend toward more
scrubbers in Phase I with a corresponding trend to lower compliance costs, not to
depict the actual costs of a site-specific utility system.
The results, summarized in Table 3, show the compliance costs and the amount of
scrubbing associated with specific compliance strategies and incentives. The model
simulations include year-by-year calculations of the cost of compliance using
different scrubber deployment timing under the constraint of economic dispatch. The
optimum scrubber deployment by unit corresponds to the lowest annual cost.
Compliance costs include scrubber costs (amortized capital charge, fixed O&M, and
variable O&M) and additional fuel costs. In most cases, both scrubbing and fuel
switching were required to achieve system compliance. Excess allowances were banked
for use in subsequent years.
Simulations were done over a period of 1995 to 2009 so that the impact on Phase II
compliance costs could be considered. The net present value (NPV) of the annual
costs using a 6.2 percent discount rate was used to evaluate a strategy. Net
present value for Phase I alone was also determined. The total amount of megawatts
scrubbed in Phase I is expressed in MW-years and is shown in Table 3 for each case.
Table 3 shows two cases involving an all-fuel switching strategy for Phase I.
Employing scrubbers reduces Phase I compliance costs by $68 million (22 percent) if
second-generation scrubbing technology is used and 525 million (9 percent) if first-
generation scrubbers are used. Note that failure to scrub in either Phase I or
Phase II leads to a very high compliance cost of $1,371 billion over the 15-year
time frame from 1995 to 2009.
IMPACT OF S02 EMISSIONS CAP ON PHASE I COMPLIANCE DECISIONS
As illustrated in a previous analysis of the hypothetical utility system,1 the S02
emissions cap provision of clean air legislation can provide considerable incentive
for scrubbing, even during Phase I. The principal effect of an S02 emissions cap
on a utility experiencing load growth is to increase the amount of S02 that must be
removed relative to its current generation strategy. Consequently, effective S02
emission rates (on a pounds of S02 per million Btu basis) are continually ratcheted
down. For example, if the hypothetical utility system experiences a two percent
system load growth from 1990 to 2000, the effective S02 compliance emission rate
dictated by the CAA would be forced down to 2.06 lb/MM Btu in 1999 and 0.88 lb/MM
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Btu for the first year of Phase II (2000). Increasingly lower sulfur coals are
generally only available at higher and higher costs to the utility. Thus, scrubbing
becomes increasingly attractive during Phase I. The impact of the S02 emissions cap
is inherent in all the results shown in Table 3. A more in-depth analysis of the
emissions cap is covered in a previous paper.1
IMPROVEMENTS IN SCRUBBER TECHNOLOGY: PERFORMANCE, DESIGN, AND COSTS
The many advancements in wet limestone and lime scrubbing technology of the past
decade have reduced S02 control costs by 25 to 35 percent while increasing the S02
removal potential to over 95 percent.2'3,4,5,6 With chemistry and design advance-
ments, scrubber reliability of over 90 percent can be achieved with larger, unspared
absorber modules.5 An EPRI-sponsored FGD Retrofit Design Improvements Study4 showed
that FGD capital costs could be reduced by 34 percent and levelized costs by 28
percent by retrofitting a 500 MW unit with one absorber and no spare compared with
a four-module design. Also, with a state-of-the-art wet limestone or lime scrubbing
system, the energy penalty is 1 to 2 percent or less.2,5 An update3 of EPRI's 1982
new plant FGD cost estimate study by United Engineers & Constructors, Inc., found
that current capital cost estimates are about 25 percent lower than the escalated
1982 results (CS-3342). Scrubber cost reductions in the EPRI update are due to
changes in process design and coal basis, engineering, technology maturity, and
financial/accounting methodology. Changes in engineering practice and technology
maturity alone account for about a 13 percent reduction in capital costs in the
updated analysis.
The state-of-the-art or second-generation wet FGD system designed for CAA compliance
incorporates many of the following concepts .2'3'5'6'7'8'9,10
1. Larger absorber module designs. Module designs of 500 to 600 MW are
becoming the standard and one Clean Coal Technology (CCT) Round 4
proposal included a 900 MW module for the CT-121 process.7,
2. Unspared absorber modules. The Clean Air Act Amendments of 1990 do
not mandate the use of spare absorbers as was the case for 1979 NSPS
regulations.8 Under CAA, utilities can take advantage of the yearly-
average compliance requirement and the inherent system "bubble"
approach. The improved availability of the state-of-the-art scrubbers
reduces the risk associated with operation without spare absorbers.
3. Wet stack design (no reheat). Scrubber systems designed without
reheat avoid additional capital cost, corrosion problems, and unit
derate (steam consumption). This allows installation of a large,
unspared absorber into the base of a new stack. Compared to a typical
first-generation scrubber design, this concept would result in a 34
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percent reduction in capital cost and 28 percent lower levelized costs
plus significant space savings/ Allegheny Power System has contract-
ed with General Electric for three single wet Thiosorbic® lime
absorbers to be installed in the base of a new 1000-foot chimney for
the 1920 MW Harrison Station.9 Also, at least one CCT Round 4
proposal (NYSE6 Milliken Station)7 incorporates this concept.
4. Use of performance additives to achieve greater than 95 percent S0:
reduction?"3 Several second-generation wet F6D processes (including
the Saarberg-Holter (SHU) process and the Thiosorbic® Lime process)
incorporate additives within the basic process design to allow 98
percent or greater S02 reduction.2 Several CCT Round 4 projects
propose to use performance additives to achieve 96 percent or greater
S02 removal on high-sulfur coals.7
5. Salable gypsum production via forced oxidation design. All the state-
of-the-art wet limestone processes can incorporate forced oxidation to
produce a gypsum by-product which can be sold to wallboard, cement,
and other industries. Eliminating solid waste disposal can substan-
tially reduce the overall scrubbing costs.
As shown in Table 3 and Figure 2, the results of the hypothetical utility system
simulation confirm that the advancement of scrubber technology with the correspond-
ing reduction in scrubber costs reduce the compliance cost and, at least in this
utility system, increase the use of scrubbers in Phase I. The scrubber cost and
performance data used in the simulations are listed in Table 2. The use of state-
of-the-art or second-generation scrubbing technology rather than first-generation
scrubbing provides cost savings amounting to $43 MM of net present value (15
percent) in Phase I, and $242 million (23 percent) in the 1995-2009 period. The
savings are sufficient to justify a second scrubber in 1999 instead of 2000.
Compliance strategies based on the use of second-generation scrubbers were used in
the subsequent evaluation of incentives and phased scrubbing.
EFFECT OF CLEAN AIR ACT BONUS INCENTIVES
The CAA provides incentives in the form of bonus allowances available on a first-
come, first-served basis to utilities that scrub. The incentives include bonus
allowances equal to a two-year extension for compliance until January 1, 1997, and
"two for one" allowance credits for emissions reduction below 1.2 lb of S02/MM Btu
for the years 1997 through 1999. In Table 3 and Figure 3, the simulation study
shows that obtaining these bonus credits substantially reduces the cost of
compliance and can stimulate additional Phase I scrubbing. (Under EPA's proposed
telephone queuing system, utilities cannot be assured of these bonus allowances.
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This uncertainty has significantly diminished the incentive value and makes the
impact of bonus allowances difficult to quantify.)
For the hypothetical utility system, the largest savings over the 15-year period
from 1995 to 2009 occur when bonus allowances are obtained for two units (Units 1
and 2) and Unit 2 start-up is delayed two years (until 1997). Savings are $80
million (34 percent) for Phase I and $97 million (12 percent) over the 15-year time
frame. The amount of Phase I scrubbing also increases from 4,568 MW-hr to 5,814 MW-
hr. Under this scenario, no fuel switching is required during Phase I. The system
over-complies in the years 1995 and 1996 generating banked allowances that are used
in the year 2000. As a result, scrubber deployment for Units 3 and 4 can be delayed
until 2001 at substantial compliance cost savings. Delaying the start-up of Unit 1
until 1997 reduces Phase I costs slightly, but increases the overall 15-year cost.
If bonus allowances are obtained for only one unit (Unit 1), compliance cost savings
are still realized. If scrubbing begins in 1995, the Phase I savings are $78
million (33 percent). Excess allowances accumulated in 1995 and 1996 are used in
1997. If the scrubber start-up is delayed until 1997, $64 million is saved. In
either case, scrubbing only the unit qualifying for bonus allowances is the least-
cost strategy in Phase I. This analysis illustrates why most (if not all) utilities
planning to scrub in Phase I want their scrubbers in operation by 1995, even if they
receive the two-year extension.
EFFECT OF STATE GOVERNMENT INCENTIVES
Several states have offered or proposed a number of incentives to promote scrubbing
within their boundaries to preserve markets for their indigenous coal reserves.
Some of these incentives are: tax-free financing of scrubber projects, tax credits,
capital cost recovery during scrubber construction (Construction Work in Progress
or CWIP), and pre-approved prudency. Each of these incentives can promote the use
of scrubbing by reducing either the cost of compliance or the regulatory risk. The
compliance model simulation was used to evaluate the impact of tax-free financing,
tax credits, and the combination of these two incentives. Results are tabulated in
Table 3 and compared graphically in Figure 4.
To evaluate tax-free financing, the cost of debt was reduced by the equivalent of
2.25 percent (nominal). The NPV cost savings in Phase I was a modest $6 million,
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but the reduction in costs is nevertheless sufficient to warrant a second scrubber
in 1997 and increase Phase I scrubbing by 27 percent to 5,814 MW-years.
A reduction of revenue requirement equal to $1 per ton of coal was used to evaluate
the state tax credit incentive. The effect of the tax credit reduces the fuel price
for the scrubbed units and therefore influences unit dispatch. This tax incentive
reduced the NPV of the system compliance cost by $12 million during Phase I and $42
million over the 15-year time period. A scrubber for Unit 2 becomes economical in
1996, three years earlier than for the base case and Phase I scrubbing increases to
6,437 MW-hours.
Combining the $1 per ton of coal credit with tax free financing increases the NPV
savings to $20 million in Phase I and $70 million over the extended period. The
least-cost strategy becomes two scrubbers brought on-line in 1995. Phase I
scrubbing increases by 55 percent to 7,060 MW-hours under this scenario.
PHASED SCRUBBER DEPLOYMENT--INTEGRATION OF PHASES I AND II
Utilities may closely integrate their compliance strategies for Phases I and II by
the phased addition of scrubbers to provide significant benefits at little or no
additional compliance cost. The phased installation of scrubbers was evaluated with
the hypothetical utility system. In the base case, the least-cost strategy requires
three scrubbers to be started up in the years 1999-2000. In the phased addition
cases, a new scrubber is deployed every two years between 1995 and 2001. As shown
in Table 3 and depicted in Figure 5, the overall costs (1995 to 2009) are identical
to the base case on a net present value basis when excess allowances are generated
in 1999 and used in 2000. If the utility chooses not to overcomply and bank
allowances, the extra NPV cost for phased scrubbing is $15 million over the 15-year
time frame. The phased deployment approach increases the amount of scrubbing in
Phase I from 4,568 MW-years to 6,384 MW-years.
The phased scrubber deployment approach provides benefits not quantified in the
model simulation. The financial and construction requirements are spread over a
longer period of time and the corresponding rate shock is reduced. The approach
reduces the concern about the availability of replacement power while installing
scrubbers.11 Demand for qualified design, construction, and start-up personnel is
reduced. People with these skills may be in short supply as Phase II scrubber
demand increases in the late 1990s and early 2000s. Furthermore, fuel flexibility
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options during Phase I are increased. Also, the banking of allowances increases
compliance flexibility and reduced compliance risks, e.g., forced outages of low
emitting baseload plants such as nuclear or scrubbed units. If a market develops
early for the sale of emission allowances between utilities, this may also make the
phased scrubber installation approach more attractive.
Some utilities, including the owners of the 1700-MW Conemaugh Station, are
considering the phased scrubber approach with the generation of excess emission
credits.12
ADDITIONAL REASONS FOR PHASE I SCRUBBING
There are other considerations that will contribute to the attractiveness of
installing scrubbers as a Phase I compliance strategy, but are either beyond the
evaluation capability of our hypothetical utility system or too site-specific to
analyze in quantitative terms. These are discussed qualitatively below.
FUEL SWITCHING COSTS
The cost of fuel switching includes the impact of variations in coal quality on
power plant performance in addition to the obvious factors of coal price and
transportation cost.13 Many U.S. power stations were designed to burn a specific
type of coal to gain an advantage in operating efficiency at the expense of fuel
flexibility. Since most of the units affected under the CAA were designed to burn
high-sulfur bituminous coal, switching to low-sulfur coal can adversely affect unit
operation, performance, and capacity. This can lead to higher generating costs by
requiring equipment modifications or capacity derates, or both. Deluliis, et al.
show the impact of the ash quantity and quality of regional coals on performance in
a typical 500 MW pulverized coal-fired boiler.14
Switching to a high-moisture, low-Btu, subbituminous coal will lead to higher heat
rates and operating problems in the areas of slagging, fouling, coal handling,
pulverization, ash handling, fan capacity, and particulate control. In most cases,
expensive equipment modification will be required and, even then, capacity derates
are likely. The Detroit Edison experience with switching to subbituminous coal at
the St. Clair Station is well documented.15
Derates are less likely with a switch to a low-sulfur, eastern bituminous coal.
Plant revisions will be necessary in many cases to mitigate poorer electrostatic
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precipitator performance. Other areas of the plant such as the pulverizers may also
be affected. Even the boiler performance can be affected if the furnace walls,
designed to be slag-covered, are too clean.
The total cost of fuel switching will exceed fuel and transportation cost
differences by an amount needed to accommodate coal quality changes. The exact
amount is site-specific to plant design and coal properties and could not easily be
quantified in the model simulation. However, the added cost will increase the
incentive for scrubbing beyond that indicated in the simulation.
UNCERTAINTY OF LOW-SULFUR COAL PRICE PREMIUMS
There is a significant degree of uncertainty regarding the future availability,
mining costs, and delivered prices of low-sulfur coals. There is an inherent,
difficult-to-quantify risk exposure to low-sulfur coal price premiums associated
with fuel switching. Conversely, the risk involved with the supply of higher sulfur
coals for a scrubbed unit is minimal. The Public Utilities Commission of Ohio
(PUCO) emphasized this point in its review of the American Electric Power proposal
to fuel switch at the Gavin plant for its Phase I compliance strategy. PUCO
reported that "the vagaries of an ill-defined and highly uncertain market for
eastern low-sulfur coal"16 make scrubbing preferable to fuel switching.
FUEL SUPPLY FLEXIBILITY
Utilities that install scrubbers maximize their flexibility in choosing coal types
and sources. For example, a scrubber may allow the utility to switch the coal
supply to a higher sulfur coal. The net compliance cost for the affected unit could
be reduced if the fuel savings are more than the differential scrubber costs for
handling the higher sulfur coal. For a scrubber designed to remove 95 percent or
more of the S02, the increased emissions associated with switching to a higher
sulfur coal would be relatively small.
SCRUBBER AND MARKET CONSIDERATIONS
There may be significant design, construction, start-up, and market advantages to
installing scrubbers during the Phase I compliance period rather than waiting for
Phase II.1 For example, as the demand for scrubbers increases for Phase II
compliance, a shortage of qualified design and construction personnel could develop
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and consequently increase cost, delay start-up, or adversely impact scrubber
quality.
SOCIOECONOMIC ISSUES
Scrubbers represent large capital investments that utilities are very reluctant to
make without regulatory assurance that they will be allowed to earn an adequate
return. Public utility commissions and state legislators have clearly recognized
the potential for socioeconomic costs entailed with fuel switching strategies.
These costs could be enormous. Fuel switching from a local, high-sulfur coal to
lower sulfur coals will eliminate many local coal mining jobs as well as those jobs
that are indirectly supported by the coal industry. These lost jobs can have
dramatic consequences for local economies. Monongahela Power and its parent
company, the Allegheny Power System (APS), estimated the socioeconomic costs of fuel
switching for the Harrison Station include the loss of 2200 coal mining jobs and
5,500 support jobs with a total annual revenue of $150 million in the APS service
area.17
In late August 1991, Illinois passed a law mandating scrubbers with Illinois coal
at the Illinois Power Company Baldwin Station and the Commonwealth Edison Kincaid
plant. Illinois Governor Edgar said that "without this action, 10,000 jobs in the
coal industry and in related businesses would be lost, and dozens of counties would
be economically devastated.1,18 The University of Kentucky estimated that if TVA
follows a fuel-switching strategy, the state of Kentucky could lose 5,600 jobs and
$28 million in annual tax receipts.
SUMMARY AND CONCLUSIONS
Installation of scrubbers has become increasingly attractive as a potential Phase I
compliance strategy. Based on the results of a hypothetical utility system
simulation and other considerations, several conclusions can be drawn regarding this
trend:
• The S0? emissions cap provision of the CAA can provide considerable
incentive for scrubbing, even during Phase I. As a utility experienc-
es load growth, the effective SO, emission rates on a pounds of S02 per
million Btu basis are continually ratcheted down. The cost of fuel
switching increases as utilities must buy lower and lower sulfur coals
at higher and higher costs. As a result, the attractiveness of high
S02 removal scrubbers is enhanced.
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• Substantial improvements in wet scrubbing technology design, perfor-
mance, and costs make state-of-the-art scrubbers more attractive for
CAA compliance compared to the fuel switching alternative. Compared
to the first-generation design for NSPS applications, the state-of-
the-art wet limestone or lime scrubbers can be designed for CAA
compliance to achieve 95 percent SO, reduction with large, unspared
modules at substantial reductions of 25 to 35 percent in S02 control
costs. The hypothetical utility system simulation showed that
employing a state-of-the-art scrubber design resulted in more
scrubbing capacity being installed during Phase I. More importantly,
the net present value of compliance cost (1995-2009) was decreased by
23 percent.
• The CAA two-year extension criteria (bonus allowances) and state
incentives to use local high-sulfur coals will increase the driving
force to install scrubbers during Phase I and significantly decrease
the overall compliance costs.
• Integration of Phase I and II strategies by the use of phased
installation of scrubbers during Phase I may be done for minimal or no
additional overall compliance costs, especially if banking of
allowances is employed. There are many potential advantages for using
the phased scrubber approach that could not be quantified by the
hypothetical utility system simulation. These include spreading out
construction and financial requirements with the reduction of the
corresponding rate shock and increasing the fuel flexibility options
during Phase I. Also, taking advantage of allowance banking minimizes
compliance risks such as forced outages of low SO, emitting units and
allows considerable more compliance flexibility for the utility.
• There are many other considerations which will increase the trend to
install scrubbers during Phase I, but are beyond the scope of the
hypothetical utility system analysis. The unit performance impacts
(such as derates) or the capital cost requirements (such as coal
handling, pulverizer, and ESP upgrades) associated with switching to
a lower sulfur coal can be substantial and cannot be ignored in a real
world utility situation. Also, with fuel switching, there is a
greater risk exposure to low-sulfur coal price premiums than with a
fuel-flexible, compliance strategy based on scrubbing and higher
sulfur coals.
• As the socioeconomic costs of fuel switching have become more clearly
defined, legislators and regulators have initiated incentives to
promote utility use of least-cost scrubbing strategies.
REFERENCES
1. Bissell, P. E., Fink, C. E., Koch, B. J., and Chomka, P. A., "Impact of S02
Emissions Cap on Phase I Compliance Decisions." Power Gen '90 Conference,
December 1990.
2. Chomka, P. A., Fink, C. E., Koch, B. J., and Statnick, R. M., "Second-
Generation Wet FGD Technology--Choices and Retrofit Issues," EPA/EPRI 1990
S02 Control Symposium, May 1990.
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3. Keeth, R. J., Ireland, P. A., and Radcliffe, P. T., "1990 Update of FGD
Economic Evaluations," EPA/EPRI 1990 S02 Control Symposium, May 1990
4. Katzberger, S. M., Dene, C. E., and Keeth, R. J., "FGD Retrofit Design
Improvements," EPA/EPRI 1990 S02 Control Symposium, May 1990.
5. Dalton, S. M., "State of the Art of Flue Gas Desulfurization Technologies,"
EPA/EPRI S02 Control Symposium, May 1990.
6. Ashline, P. M., and K1 ingensmith, R. L., "Advanced Co-Current Wet FGD
Design for the Bailly Station," EPA/EPRI S02 Control Symposium, May 1990.
7. U.S. Department of Energy, Clean Coal Technology Round 4 Public Abstracts,
May 20, 1991.
8. Wedig, C. P., et al., "Flue Gas Desulfurization Systems Designed and
Operated to Meet the Clean Air Act Amendments of 1990," IGCI Forum'91,
September 1991.
9. Coal & Svnfuels Technology, Pasha Publications, April 1, 1991.
10. Rader, P. C., and Bakke, E., "Incorporating Full-Scale Experience into
Advanced Limestone Wet FGD Designs," IGCI Forum'91, September 1991.
11. Zmuda, J. T., "Acid Rain Compliance Planning: Compliance Issues and
Options," IGCI Forum'91, September 1991.
12. Coal Week. September 16, 1991, p. 7.
13. Kumar, K. S., Sommerlad, R. E., and Feldman, P. L., "Know All Impacts from
Switching Coals for CAA Compliance," Power. May 1991.
14. Deluliis, N. J., Fink, C. E., and Abbott, M. F., "The Impact of Ash
Quantity and Quality on Boiler Performance and Power Cost," Eighth Annual
International Pittsburgh Coal Conference, October 17, 1991.
15. Higzay, M. A., and Kenning, T. A., "Western Coal Combustion Improvements in
Converted Steam Generator," American Power Conference, April 18-20, 1983.
16. Coal & Svnfuels Technology. Pasha Publications, September 2, 1991.
17. "Mon Power Looking at Scrubbers," Times-West Virginian. July 15, 1991.
18. Clean-Coal/Svnfuels Letter. September 2, 1991.
2-13
-------
Figure 1
Delivered Coal Price
as a Function of
Coal Sulfur Content
Coal Sulfur Content, Lb S02/MMBtu
Figure 2
Technology Advancements
Compliance Costs for Hypothetical Utility System
Net Present Value (Millions of $1990)
| | Phase
1995-2009
1000-
ALL FIRST
GENERATION
PHASE I-1ST GENER'N
PHASE II-2ND GENER'N
ALL SECOND
GENERATION
2-14
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Figure 3
CAA Bonus Allowances
Compliance Costs for Hypothetical Utility System
Net Present Value (Millions of $1990)
| | Phase 1 gg 1995 - 2009 |—
1 UNIT
1 UNIT
UNIT 1 -1995
2 UNITS
UNIT 1 -1997
UNIT 1
UNIT 2-1997
NO BONUS
BASE CASE
2 UNITS
UNIT 1 -1995
UNIT 2 -1997
Figure 4
State Government Incentives
Compliance Costs for Hypothetical Utility System
Net Present Value (Millions of $1990)
1995-2009
| | Phase
TAX FREE
S1ATON OF COAL
CREDIT
FINANCING
NO
INCENTIVES
TAX FREE &
Sim)N CREDIT
2-15
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Figure 5
Phased Scrubber Additions
Compliance Costs for Hypothetical Utility System
Net Present Value (Millions of $1990)
/
1000-i
/
/
900-
/
/
800-
/
700-
600-
/
500-
/
400-
/
/
300-
/
200-
/
/
100-
/
/
o-
/
| | Phase I
1995-2009
BASE CASE
LEAST ANNUAL COST
PHASED
WITHOUT BANKING
PHASED
WITH BANKING
2-16
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Table 1
Hypothetical Utility System
Performance and Allowance Calculations
Unit
Size
MW
Baseline
Phase I
Phase II
Capacity
Factor
Generation
GWh
S02 Emissions
Affected
Allowance
tons
Affected
Allowance
tons
Ib/MMBtu
Tons
1
789
72.9
5,040
6.7
160,930
Yes
58,367
Yes
28,016
2
623
46.6
2,542
51,516
Yes
30,533
Yes
14,656
3
570
42.8
2,135
4.1
43,759
Yes
25,935
Yes
.12,449
4
447
39.8
1,560
32,343
Yes
19,169
Yes
9,201
5
299
38.7
1,013
4.1
21,608
Yes
12,807
Yes
6,147
6
238
40.4
842
17,682
Yes
10,587
Yes
5,082
7
200
20.3
356
2.3
5,041
No
Yes
2,496
8
175
20.3
312
1.6
3,087
No
Yes
2,197
9
153
74.0
991
6.7
32,542
Yes
11,803
Yes
5,665
10
125
20.3
223
2.3
3,188
No
Yes
1,578
11
107
19.8
186
1.1
1,301
No
Yes
1,655
12
75
20.1
132
1.1
1,062
No
Yes
1,351
13
58
20.7
105
4.1
3,171
No
Yes
902
14
38
20.1
67
1.6
801
No
Yes
580
15
25
20.9
46
2.3
804
No
Yes
381
Total
3,922
15,549
379,015
169,200
92,358
Table 2
Performance and Costs for
First Generation and Second Generation Scrubbers
Unit
1
2
3
4
Scrubber Type, Generation
Second First
Second First
Second First
Second First
Reagent
Limestone
Limestone
Limestone
Limestone
Byproduct (to Landfill)
Gypsum Sludge
Gypsum Sludge
Gypsum Sludge
Gypsum Sludge
S02 Removal
95% 90%
95% 90%
95% 90%
95% 90%
Unit Capacity. MW
Gross
789.0
623.0
570.0
447.0
Net, Ex FGD
751.0
594.0
543.5
426.1
Net, With FGD
737.4 730.4
585.8 579.4
535.9 530.1
420.1 415.5
Derate, %
1.8% 2.7%
1.4% 2.5%
1.4% 2.5%
1.4% 2.5%
Net Heat Rate. BTU/kWh
Ex FGD
9,524
9,470
9,474
9,483
W/FGD
9,700 9,793
9,603 9,709
9,608 9,713
9,617 9,723
Coal Sulfur, lb SCyMMBtu
6.7
4.1
4.1
4.1
Retrofit Difficulty
Medium
Medium
Medium
Medium
Number of Absorber Trains
Operating
2 3
1 3
1 2
1 2
Spare
0 1
0 1
0 1
0 1
Total
2 4
1 4
1 3
1 3
Capital Cost, $/kW
187.7 221.5
151.3 200.9
156.2 203.9
172.7 225.4
Annual Costs. ($1990)
Capital Charge, $MM/year
14.964 17.662
9.513 12.630
8.984 11.728
7.789 10.116
Fixed O&M, $MM/year
5.026 7.158
3.486 5.149
3.336 4.889
3.031 4.402
Variable O&M, Mills/kWh
1.75 2.13
1.01 1.19
1.02 1.19
1.01 1.19
2-17
-------
Table 3
Results of Compliance Model Simulations
Compliance Strategy
Net Present Value
Millions of 1990 Dollars
Scrubbing
In Phase 1
Year tor Scrubbber Installation 1
by UnK |
MW-Years
Phase 1
Phase II
Phase I
1995-2009
1st
2nd
3rd
4th |
Fuel Switch
Fuel Switch
306
1,371
0
I
Fuel Switch
FGD 1st Generation
306
1,065
0
2000
2000
2000
2000
FGD 1st Generation
FGD 1 st Generation
281
1,040
3,945
1995
2000
2000
2000
FGD 1 st Generation
FGD 2nd Generation
281
907
3,945
1995
2000
2000
2000
FGD 2nd Generation
FG0 2nd Generation
238
796
4,568
1995
1999
2000
spas
Scrubber Incentives
CAA Incentives
One Unit - 1997 Start-up
174
734
2,367
1997
2000
2000
2000
One Unit - 1995 Start-up
160
720
3,945
1995
2000
2000
2000
Two Units - 1997 Start-up
148
707
4,236
1997
1997
2000
2000
Two Units - 1995/1997 Start-ups
158
701
5,814
1995
1997
2001
2001
State Incentives
Tax Free Financing
232
773
5,814
1995
1997
2000
2000
$1Aon of Coal Credit
226
756
6,437
1995
1996
2000
2000
Tax Free & $1 Aon of Coal Credit
218
728
7,060
1995
1995
2000
2000
Phased Scrubbing
No Banking of Allowances
239
813
6,384
1995
1997
1999
2001
With Banking of Allowances
253
798
6,384
1995
1997
1999
2001
2nd Generation FGD fa both Phase t md Phase II is &e Esse Caaw for •ve&sting tn«*htiv«* and Watted Scrubbing.
2-18
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Scrub Vs. Trade: Enemies or Allies?
2-19
-------
Intentionally Blank Page
' s
2-20
-------
SCRUB VERSUS TRADE: ENEMIES OR ALLIES?
J. B. Piatt
Integrated Energy Systems Division
Electric Power Research Institute
Palo Alto, California 94303
ABSTRACT
Under the 1990 Clean Air Act Amendments (CAAA), scrubbing and emission allowance
trading will play complementary roles. This paper reviews Phase 1 announced strategiej
and presents projections of technology controls, coal switching and industry-wide S02
removal costs under different assumptions about trading. The principal uncertainties
characterizing today's planning environment are discussed — ranging from changing
expectations for fuel costs to swings in allowance prices and questions about regulation
and new operating procedures. Economic forecasting is difficult. A clearer picture of
Phase 2 strategies is emerging from EPRI's integrated analysis of fuel, technology and
allowance markets — based on collaboration between A. Van Horn and K. White
(management consultants) and T. Hewson (Energy Ventures Analysis). About half the
S02 reductions required in Phase 2 are likely to come from technology controls and half
from coal switching. With trading, the highest cost "scrubs" and "switches" can be
avoided, more upgrading of low-cost scrubbing is expected, and the role of switching
grows to a small extent. Additional benefits from trading, averaging and banking
allowances are: better sequencing of technology controls, less stringent specs for
equipment, and added flexibility/risk-sharing opportunities in contract arrangements.
^receding page blank
2-21
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INTRODUCTION
Are scrubbing and trading enemies or allies? One view is that scrubbing is a conservativi
response to reducing emissions — and that scrubbing and emissions allowance trading ar<
locked in a zero sum competition for market share. Scrubbing's gain is trading's loss.
Scrubbing is more expensive, etc. A very different view is that scrubbing is the essential
mechanism for generating allowances for sale, without which there could be little or no
trading. Scrubbing is the big workhorse of emission reductions. It caps potential
runaway prices of both low-sulfur coal and allowances. Which view is correct?
The quick answer, I believe, is that both views have some truth ~ with the evidence
favoring the "workhorse" concept — but both make oversimplifications. Scrubbing and
trading will play complementary roles under the CAAA. So too will coal switching, of
course, along with other options and variables, such as changes in the specifications for
particular qualities of coal (or blends) and in the operating removal efficiencies at existing
or future scrubbers. This wider mix of options helps buffer price movements and
complicates the task of forecasting the future "scrub-switch balance".
Rather than adopt an either-or view of scrubbing and trading, this paper takes a look at
the broader context of compliance options, market uncertainties and planning risks. It
provides a brief status report on utilities' compliance strategies and the questions that
dominate planning and analysis today. This is important, because so many elements and
perceptions are changing. Clues to the roles and relationships of scrubbing and trading
can then be seen in this broader context. The paper draws on public information about
announced or likely utility strategies, gathered by T. Hewson of Energy Ventures
Analysis; on current research for EPRI on the topic "Integrated Analysis of Fuel,
Technology and Allowance Markets" by A. Van Horn and K. White, management
consultants, and T. Hewson; on material presented at EPRI's November 1991 workshops,
"Clean Air Response: Strategic Issues and Markets"; and on surveys of team planning
approaches, tapping a diverse set of utility planners, managers and engineers, conducted
by the author.
2-22
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PHASE 1 DECISIONS
Retrofit FGD. While news about utilities' Phase 1 decisions seems dominated by
announcements of coal switching, the surprising fact is that a significant amount of
retrofit scrubbing will take place — and the emerging totals are not far from what had bee
anticipated. A firm number of at least 12 GW of scrubbing is now anticipated for Phase 1
based on announcements for over 80% of Phase 1 affected capacity (ie., 65 out of -80 GW)
Depending on the decisions for various "fence sitters", Hewson estimates the total could
climb to as much as 18 GW. A slightly higher range, 15-20 GW, was presented in EVA's
June 1991 report, Utility Coal Markets Under Acid Rain Legislation (EPRIIE-7110). Recei
analysis by Van Horn and White using EPRI's Emissions Reduction Analysis Model
yields a similar estimate of 12.6 to 15.5 GW, depending on assumptions about allowance
trading. The higher number occurs if trading in Phase 1 is limited or slow to mature. A
significant amount of scrubber upgrades, 12-18 GW, is also indicated. For upgrades, the
higher number occurs under very active trading. A comparison of several recent Phase 1
and 2 scrubber projections* follows:
Compliance Strategy Projections
Phase 1 Phase 2
EVA for EPRI 13-18 GW 45-60 GW (54 "best guess")
(EPRI IE-7110) expect # to drop
GE 17 45
Pure Air 15-20 35-50
DOE EIA 7.8 10.6 (to 12.0 in 2010)
* T. Hewson, EVA; Pwr Eng'g 8/91; EIA Ann. Outlook of El. Pwr, 1991.
The Phase 1 tally is dominated by decisions at a few large companies. The 5 largest
proposed installations account for 8,400+ GW (TVA - Cumberland station @ 2,600 MW,
pending receipt of bonus allowances; APS - Harrison @ 1,920 MW; GPU - Conemaugh @
1,700 MW; Illinois Power - Baldwin # 1, 2 -1,128 MW and Commonwealth Edison -
Kincaid @1,100 MW). The outcome of the current debate over AEP's Gavin station, as
large as Cumberland, is still unclear. It has been classified here as a switch.
Switching. The amount of coal switching that will likely take place in Phase 1 exceeds
what was expected only 6-12 months ago. Current estimates of these changes are given ii
the next table (per T. Hewson, EVA):
2-23
-------
Coal Switching Phase 1 Preliminary Estimates (million tons/year)
actual
growth to
CAAA
comparison to
1990
1995
likelv
EPRIIE-7110*
Illinois Basin
129
133
-31
(6 • 11 • 20)
Northern App
127
130
-21
(2 • 5 - 10)
Central App.
150
169
- 4 (med S)
+ 10 • 15 • 35
+ 35 (low S)
Powder R. Basin
194
221
+ 20
+ 8 • 10 • 30
* ranges: low • best guess • high; parentheses indicate losses.
Maximum leverage. With three years to go until January 1995 and many final
commitments for equipment and specific coal supplies yet to be made, utilities have beer
able to benefit from highly competitive market conditions. Coal prices have remained
soft and scrubber vendors have described business conditions as "hypercompetitive".
Long-awaited seller's markets have not emerged, and it is not clear they will. Yet at the
same time, there is a growing sense of awe and wonder, particularly for coal (and natural
gas), over how long these highly competitive conditions can be sustained.
TODAY'S PLANNING ENVIRONMENT: CHANGE AND UNCERTAINTY
For a number of reasons, today's compliance planning environment is particularly
problematic. Overall planning processes and procedures are working quite well — most
companies have set up teams, task forces and committees to develop and document theii
clean air strategies and individuals are pleased with the progress they have been making.
The major difficulties lie, not within individual companies, but outside. Uncertainty is
the most common concern — uncertainty in fuel prices (as noted above), allowance
values, state regulatory treatment, changes in technology, EPA regulations, further
environmental legislation (such as air toxics and C02), and more. This state of affairs is
summarized by one utility manager: "Major decisions must be made without adequate
information or even the ability to obtain adequate information".
Some of the areas of change and uncertainty that dominate today's planning
environment:
• Current low fuel costs. How to reconcile earlier projections of higher
costs with the attractive price quotes being obtained today?
2-24
-------
• Lower future coal price expectations. There may be greater differentiation of coal
prices in the Illinois Basin, with greater discounts for the highest-sulfur coals than
thought previously. The perennial question of what will happen to Central Appalachia:
low and very low-sulfur coal prices is also getting a second look — are prices of $30/ton o
lower possible? EPRI's Report Series on Low-Sulfur Coal Supplies provides an imports
body of information for assessing coal supply and transportation.
• Utilization of Powder River Basin coal expanding. Many companies
have found they can eliminate, reduce or accommodate the derates expected from using
non-design coals. This is an area of rapidly growing experience.
• New contract arrangements for allowances developing. Still in the
earliest stages, coal producers and equipment vendors alike are interested in using
allowances. Other organizations may also take an interest. Use of allowances can bring
added flexibility in the services offered and provide new methods for allocating risks.
• Pooling, operating, power transactions and allowance valuation
procedures unclear. There is little precedent and no "textbook" on how allowances
should or will be integrated with utility operations and transactions.
• Uncertain allocations, bonus allowances. Important questions now, these numbers
will resolve over the next 6-12 months. One thing seems clear: the ratchet to be applied
to Phase 2 allocations has been ratcheting to higher and higher levels, and is now
estimated to reach about 11% (T. L. Montgomery, EPA Acid Rain Div., at EPRI Nov.
workshop). The ratchet is the amount by which utilities' allowance allocations must be
reduced to assure that the national cap of 8.95 million tons is not exceeded. To these
allocations, bonus allowances will then be awarded (approx. 530,000 tons through 2009).
• No trading market, no history. For lack of a precedent, observers fall
into different camps. One view: "the first trade will 'open the gates' to trading"; "we wi
be amazed and pleased with the status of clean air conditions in five years". Other view:
"will companies really figure out a way to use trading, given all of the uncertainties?";
"trading as a free market phenomenon within a regulated industry is somewhat of an
oxymoron".
• Falling allowance price expectations. A number of factors may account
for this, such as (a) the lack of a fly-up in fuel or equipment prices to date, (b)
development of better information about industry-wide compliance costs, and (c) EPA's
adoption of a "light touch" in its proposed trading rules. The shift in price expectations
has been dramatic, as indicated by changes over the past six months in the Emissions
2-25
-------
Allowance Trading Index. This index is based on surveys conducted by Compliance
Strategies Review (Fieldston Publications):
Emissions Allowance Trading Index - EATX
(1991 $ per ton - median values)
Tune-Tulv Oct-Nov
Phase 1 best: 450 320
1995 high: 725 550
low: 300 200
Phase 2 best:
2000 high:
700
1000
500
400
700
300
low:
These and other surveys also show a wide difference between the price expectations of
buyers and sellers.
• Importance of internal values of allowances. As price expectations have declined,
several companies contemplating selling allowances have had to reexamine whether it is
still worth it to sell them. This answer depends on allowance price trajectories, future
system requirements, etc. Questions of how to value and manage allowances will grow
in importance and complexity. One individual asks: "What functional area of the
average utility should be responsible for this activity? Marketing, Dispatch, Power
Production, Environmental, others?" Additional uses include finance, fuels, FGD
construction/scheduling, scrubber operations, etc.
• Big swings in supply/demand of allowances. The dynamics of market forces in
allowances are hard to predict. In contrast to a scenario of gradual growth in allowance
values and trading activity, for example, is a scenario in which companies adopt
conservative compliance strategies in Phase 1, retain the additional reductions they are
able to achieve, and find in Phase 2 that everyone else did likewise. Prices collapse. The
dilelmma is that if the industry uniformly anticipates cheap allowances in Phase 2 and
minimizes investment in technology controls, it may be more difficult to keep a lid on
allowance prices. Prices skyrocket? Whatever the logic of these scenarios, the advice of
market experts is NOT to plan on the basis of point forecasts.
In conclusion, the list of changes and uncertainties that utilities must take into account ix
their planning is long. Forecasting the future balance of compliance strategies and the
interplay of market forces is difficult. Utilities must continually reexamine and update
2-26
-------
assumptions about important variables, such as fuel costs or changes in the
competitiveness of technologies. And there is no question that they must also be able to
make informed judgements about allowance values. A utility manager makes the poinl
"Our entire planning/strategy depends on what an allowance will be
worth over time. The market trajectory — it dictates whether we scrub
or switch; it dictates whether we bank, buy, or sell allowances."
EPRI RESPONSE: INTEGRATED ANALYSIS OF FUEL, TECHNOLOGY AND
ALLOWANCE MARKETS
EPRI is pursuing allowance-related research on several fronts. One activity involves
developing or adapting planning tools to new concerns, such as calculating allowance
reserve levels, evaluating emissions dispatch and other operational issues, and weighinj
the choices and tradeoffs re. continuous emissions monitoring systems. A related activil
is EPRI's Emission Trading Simulation Laboratory in which a small group of people, eac
representing a hypothetical utility, designs compliance strategies and buys/sells
allowances and power. A third activity is integrated analysis of fuel, technology and
emission allowance markets. It is aimed, on the one hand, at developing detailed
information about industry-wide compliance options, costs and possible emission
trading, and on the other, at making plausible interpretations of market dynamics.
The core of this integrated analysis is the collaboration between A. Van Horn and K.
White, management consultants, and T. Hewson of Energy Ventures Analysis (EVA).
Van Horn and White developed EPRI's Emissions Reduction Analysis Model, used
frequently during the mid-1980s to analyze various acid rain measures. EVA pioneered
utility-specific analysis of fuel and technology markets for EPRI (eg., Coal Markets and
Utilities' Compliance Decisions, EPRI P-5444, 1987 and Utility Coal Markets Under Acid
Rain Legislation, EPRI IE-7110, 1991). The initial focus of the current work has been to
update previous analyses and calculations under the new provisions and allowance
allocations of the CAAA, to incorporate the latest EPRI and utility information on
technology controls and decisions, and to reassess coal price assumptions, drawing on
information from EVA, Hill and Associates, and EPRI's Report Series on Low-Sulfur
Coal Supplies. The investigators are also examining the decision circumstances of the
oil-gas utilities, many of whom are in a position to generate allowance credits by
continuing to use natural gas.
2-27
-------
The research process has been one of incremental development. Only now is it becoming
possible to frame the potential role of emissions trading in context, because we have a
significant body of data and experience in hand to describe the competitive balance of the
"primary" compliance options. The essential information includes data on utility
systems and decision factors, alternative (high and low sulfur) coals and transportation
costs, technology controls (eg., wet scrubbing, spray drying, etc.), modifications to handle
non-design coals, coal quality premiums, average and marginal S02 removal costs, and a
host of other considerations. Preliminary results were presented at the November
workshops on strategic issues/markets and examples are included here. These findings
should be considered indicative rather than absolute — a great deal of refinement and
discussion is yet to be done.
A special emphasis is being placed on review and interpretation. Do the findings make
sense? Are they consisent with utility behavior? Are changes over time accounted for?
How do different incentives, such as profits for selling or savings from buying
allowances, affect the choices? Measures to assure that reasonable and relevant factors an
included in the overall assessment include (a) tapping a wide range of experts, such as at
the November workshops, and (b) incorporating lessons about market behavior,
institutions and contracting arrangements from other arenas. M. Yokell and A. Taylor of
RCG/Hagler, Bailly have found analogies to uranium markets to be fruitful in
anticipating potential market developments for allowances.
PRELIMINARY ANALYSIS OF PHASE 2 SCRUB, SWITCH AND TRADE DECISIONS
The eight figures attached to this section show different aspects and interrelationships of
likely Phase 2 compliance strategies.
Plotting the allowance market balance (Figure 1). This figure introduces several concepts
and terms. The curves mark the progression of costs for increasing reductions of S02,
built from data on the options and costs at each utility. The most stringent case is "unit
compliance", in which S02 limits are applied to each generating unit. Somewhat less
steep is the plot for "intra-utility trading", in which utilities optimize their strategies ova
their systems (ie., system bubble). A band or range is used because of the inevitable
uncertainty in fuel and technology costs. At the bottom is the plot for "perfect trading",
where all affected utilities are treated as one giant entity (ie., a U.S. Light and Power). The
costs shown are typically "marginal costs", meaning the costs of achieving each next
2-28
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higher level of reductions. Were "average" costs to be shown, the curves would be lowe
because of the effect of rolling in all the lower cost reductions at each level. The S02
reduction requirement is plotted as possibly shifting over time. This could occur as fossi
generation grows, on the one hand, or as units are retired, having the opposite effect.
Effects of Perfect Trading (Figure 2). This figure compares the cumulative marginal costs
for "intra-utility trading" with "perfect trading". The motivation for trading can be seen
in the high cost "tail" without perfect trading. Interestingly, most of the savings projecte
for trading are due to efficiencies in targeting reduction requirements. With perfect
trading, the industry is able to operate at an emission level almost one million tons
higher (ie., at an S02 reduction level that much lower) without exceeding the tonnage
cap. The costs of Phase 2 compliance are much higher than those in Phase 1. The small
squares are estimated costs for several announced Phase 1 scrubbers — the costs shown dc
not reflect the value of system benefits or bonus allowances that may be received.
An important caution: the numbers shown are not hard and fast. Subsequent analysis
using slightly lower coal prices results in some shifts in selected strategies and lower
marginal costs (approx. $50/ton). An added variable, not shown on these curves, are the
supplies of low or zero cost allowances available to units that were favorably treated in
the CAAA or that are emitting below their allocations for other reasons. T. J. Heuttemai
of Energy Management Associates calls these units the "newly clean" (EPRI November
workshops). These supplies will have a depressing effect on prices.
Costs of Making Additional Reductions (Figure 3). This figure plots the costs of making
additional reductions beyond those required for each individual utility system. The
largest source of allowances are those available at low or zero cost to both coal and oil-ga£
units. EVA estimates this "overhang" of allowances to be 100,000 to 450,000 tons per yeal
for oil-gas units and 400,000 - 600,000 tons per year for coal units. Their actual availability
will depend on the evolving needs of their owners, competitiveness of gas prices, etc.
The remaining columns show the supply and costs of making additional reductions,
under the assumption that the first extra 10 percent is held in reserve and that only the
next 10 percent is available for trading. Without arguing the merits of this particular
assumption, it appears that the ability to generate large quantities of additional reduction
at low costs is quite limited. This bimodal distribution raises important questions about
allowance price formation and planning risks — will prices gravitate toward the lower
end, the middle, or back and forth?
2-29
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Regional pattern of trading and FGD (Figure 4). This figure illustrates, by NERC region,
the haves and have nots in a case of perfect trading. Consistent with the "overhang", the
primary, net sellers of allowances lie west of the Mississippi, the buyers east. In this case,
over 800,000 tons per year are found to trade between NERC regions, with almost again a
much occurring within the regions. Also shown is the distribution of ~50 GW retrofit
FGD capacity, taken from the report, Utility Coal Markets Under Acid Rain Legislation
(IE-7110). The buyers of allowances are also the builders of technology controls.
Impacts of trading on compliance strategies and costs (Figures 5-8). The remaining
figures show some of the differences in compliance choices and costs for a case of "no
trading", meaning no inter-utility trading, and perfect trading. Scrubbing (really various
technology controls) and switching/blending have surprisingly close overlapping cost
ranges (Fig. 5). Under "no trading", each accounts for an equal share of the overall
reduction of 8.4 M tons S02. With perfect trading, the balance shifts slightly toward
switching/blending (54%), while the tonnage of S02 required to be removed has fallen
over 10% to 7.5 M tons (Fig. 6). As expected, the highest cost controls are reduced or
eliminated.
Figure 7 presents the same information, comparing the two cases just for technology
controls. Here it is more apparent that the reduction in the highest cost options — many
being dry injection choices — is offset, not just by the modest shift toward
switching/blending, but by an expansion of low-cost scrubbing. These are primarily
upgrades. A similar phenomenon of expansion in lower cost switching occurs in the
comparison for coal switching (Figure 8). Under perfect trading, companies with the
option to make additional reductions at low cost face no barriers in doing so.
These figures present a "bird's eye" view of scrub, switch and trade dynamics. By being
able to stand back from the myriad details, the work provides an immediate perspective
on potential market developments in fuel, technology and allowances at the same time
that it raises questions and focuses efforts to dig deeper.
Importance of fuel premiums in allowance pricing. The integrated analysis is also
yielding additional insights on compliance strategies and allowance market behavior.
One thing is becoming increasingly apparent: the premiums between eastern low
(approx. 1% sulfur) and very low-sulfur (1.2 lbs S02/MBtu) coals will likely have an
important influence on allowance prices, and vice versa. These coals will usually be
burned without controls. The mathematics of this linkage are shown in the next table.
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Emission Allowance Values vs Coal Quality Premiums*
value of EAs "parity" coal quality premium for A of:
$ / ton SQ2 1/2# SQ2/MBtu 1# SQ2/MBtu
400
800
$2.40
$4.80
$4.80
$9.60
•dollars per ton - 12,000 Btu/lb coal
EVA believes the premium between low and very low sulfur coals (ie., a A of about 0.4 #
S02) will fall in the $2.00 - 4.00 ton range in Phase 2. This is consistent with $400 - 800
allowance prices.
CONCLUSION: ENEMIES OR ALUES?
Returning to the original question, the first conclusion from EPRI's research is that
emissions trading is hardly comparable with scrubbing on the basis of size. If these
options are in competition with one another, it is a mismatch. The second conclusion is
that there are many benefits created by trading, averaging and banking allowances that
actually facilitate FGD, even though trading may cause shifts in the balance among
technology options and a small net shift (measured in tons S02 removed, not GW)
toward switching/blending. These benefits include:
• better sequencing of technology controls
• less stringent specs on FGD design
• reduced technology forcing at difficult sites — favors conventional technology
• possible market opportunities at low incremental costs -- favors upgrading
• added flexiblity in supplier arrangements.
The answer, then? Allies.
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CONTROL
COSTS
($/TON S02)
S02 REDUCTION
UNIT
COMPLIANCE
INTRA-UTILITY
TRADING
m 1
PERFECT TRADING
m ?
TONS S02 REMOVED
r
Figure 1. PLOTTING THE ALLOWANCE MARKET BALANCE
MARGINAL COSTS (1991 $/TON S02)
1200
PLUS
INTRA-UTILITY TRADING
Phase 1 Phase 2
LOW-
COST
EAs
1000 -
800 -
600 -
400 -
PERFECT TRADING
Phase 2
200 -
10
0
2
6
8
4
REDUCTIONS BELOW FUTURE BASE CASE, MTPY
Figure 2. EFFECTS OF PERFECT TRADING
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200
TONS OF S02 (1,000s)
100
overhang of low-
cost allowances
• oil/gas units
100-450,000
• coal units
400-600,000
I
_ ££
JE^L
I t
900 1050 1200
0 150 300 450 600 750
MARGINAL COSTS (1991 $/TON S02)
Note: first 10 % "banked" - next 10 % plotted here.
Figure 3. COSTS OF MAKING ADDITIONAL REDUCTIONS
% OF ACTIVITY
60
-40
-60
EAs Sold
Mississippi R.
EAs Bought
Retrofit FGD
^ 1
1
i i
T T
WSCC SPP MAIN SERC NPCC
MAPP ERCOT ECAR MAAC
NERC REGION
Figure 4. REGIONAL PATTERN OF TRADING AND FGD
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% OF PHASE 2 S02 REDUCTION
25 1
controls: 50%
$0- 200- 400- 600- 800- >1000
200 400 600 800 1000
Marginal Cost ($/ton S02)
Figure 5. MARGINAL S02 REMOVAL COSTS - NO TRADING
% OF PHASE 2 S02 REDUCTION
25
20
15
10
5
0
20
15
10
5
° $0- 200- 400- 600- 800- >1000
200 400 600 800 1000
Marginal Cost ($/ton S02)
Figure 6. MARGINAL S02 REMOVAL COSTS -- PERFECT TRADING
Hl^
technology
controls: 46%
t^j III ^ll
m u
switching/
blending: 54%
m ill ill
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% OF PHASE 2 S02 REDUCTION
No Trading
Trading
$0 - 200- 400-
200 400 600
600- 800- >1000
800 1000
Marginal Cost ($/ton S02)
Figure 7. EFFECT OF PERFECT TRADING ON TECHNOLOGY CONTROLS
% OF PHASE 2 S02 REDUCTION
No Trading
Trading
¦***<" *, ^ „
$0- 200- 400- 600- 800- >1000/
200 400 600 800 1000 ton S02
Marginal Cost ($/ton S02)
Figure 8. EFFECT OF PERFECT TRADING ON COAL SWITCHING
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3-36
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EVALUATING COMPLIANCE OPTIONS
John H. Wile
National Economic Research Associates, Inc.
123 Main Street
White Plains, New York 10601
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3-38
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EVALUATING COMPLIANCE OPTIONS
ABSTRACT
New methods have to be used to evaluate alternative methods for complying with the 1990 Clean
Air Act. There will be a premium on options that provide utilities with flexibility, particularly during
Phase L This paper discusses how the principles of financial options theory can be used to evaluate
the choice of compliance options available to utilities and to quantify the benefits from flexibility.
Among the most important compliance options are scrubbers, low sulfur coal and natural gas. They
are not, however, mutually exclusive. In fact, initially using low sulfur coal or natural gas for all or
part of Phase I and then retrofitting a scrubber offers utilities and may, in some circumstances, be
the option with the lowest expected cost.
The usual expected value methods cannot adequately capture the effects of uncertainties or the
benefits from flexibility on the choice of compliance options. Which option will be lowest cost
depends on a whole host of factors about which there is considerable uncertainty. Three of the most
important are the cost of scrubbers, the prices of low sulfur coal (and natural gas) and the prices for
emissions allowances. Applying the principles of financial options theory will take into account more
fully the effects of uncertainties and reflect the fact that some will be resolved, at least partially, in
the early stages of Phase I.
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INTRODUCTION
Electric utilities face complex decisions in selecting their options to comply with the 1990 Clean Air
Act. And deciding how to comply is made more complex because of the uncertainties surrounding
the Act and the outcomes of utility decisions. In particular, how will the Act work? Will there be
active trading of emissions allowances? What are prices for emissions allowances likely to be?
Moreover, the Act provides incentives to build scrubbers in Phase I. However, these incentives raise
additional concerns and increase uncertainty: will the demand for scrubbers outstrip the capacity to
build them during Phase I? Will excess demand lead to increases in scrubber costs?
These uncertainties place a premium on compliance strategies that offer flexibility. This paper
describes how low sulfur coal (and natural gas as well) can provide electric utilities with flexibility.
It also shows how the benefits from flexibility can be translated into monetary terms so they can be
taken into account in developing compliance strategies.
FLEXIBILITY OF LOW SULFUR COAL1
How does compliance with low sulfur coal provide utilities with flexibility? Retrofitting a scrubber
for Phase I involves a sizeable investment and commits a utility to a long-term strategy at a time
when there is a great deal of uncertainty about compliance decisions. On the other hand, a five year
contract, say, for low sulfur coal involves a smaller financial commitment over a much shorter time
frame. At the end of the contract, the utility can re-evaluate its decision. By this time, a good deal
of the uncertainty about the allowance and scrubber markets will be resolved. The EPA will have
rules in place governing the allowance market Also, state public service commissions will have
experience with allowance trading and will have developed policies regarding trading. In addition,
utilities will have experience with trading as well as information on the prices for allowances. And
there will be more information on the market for scrubbers and the ability of vendors to meet
industry needs.
1 While the discussion focuses on low sulfur coal, it applies to natural gas as well.
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An analogy is useful here in explaining how uncertainty creates the need for flexibility. Consider
how a stock option provides an investor with flexibility. If events turn out favorably, the investor
can purchase the stock at the price specified on the option. On the other hand, if events do not turn
out well, the investor is under no obligation to purchase the stock. The key here is that some of
the uncertainty will be resolved over the period of the option's life. Once some of the uncertainty is
resolved, the investor can re-evaluate whether to purchase the stock. The stock option serves the
same role for investors as low sulfur coal does for electric utilities. By purchasing the stock option,
the investor is deferring a decision about buying the stock itself and is, therefore, gaining flexibility.
It is important to recognize that the benefits of flexibility can be quantified. The same principles
used to set the price for a stock option can be applied to value the flexibility of low sulfur coal. In
fact, we have quantified the benefits of flexibility for clients regarding major investment decisions.
Let's look at a very simple example that illustrates how the flexibility benefits offered by low sulfur
coal can be quantified.
MEASURING THE BENEFITS FROM FLEXIBILITY
The essence of flexibility is that it provides utilities with the ability to defer a decision about a long-
term investment. The benefit from flexibility is the difference between (1) the expected cost of
burning low sulfur coal for, say, five years and then deciding whether to build a scrubber and (2)
the expected cost of deciding now whether to build a scrubber. We will use a simple example to
illustrate how to estimate the benefits of flexibility.
Decide Now Whether to Build a Scrubber
Let us begin by looking at the costs of complying with a scrubber and with low sulfur coal. The
total cost of complying with a scrubber is 24 mills per kilowatt-hour, which includes 17 mills for
fuel and 7 mills for the levelized capital and operating costs for the scrubber. On the other hand,
low sulfur coal costs 23.5 mills per kilowatt-hour and, therefore, has a slight cost advantage. The
assumptions are summarized in Table 1.
The 1990 Act affects the relative costs of these options through the difference in their emissions
rates. The scrubber will have a lower emissions rate-0.5 pounds of sulfur dioxide per million Btus
compared to 1.2 pounds for the low sulfur coal in our example. The important point here is that the
additional sulfur removed by the scrubber, 0.7 pounds of sulfur per million Btus or 7 pounds per
megawatt-hour, is valuable if allowances are traded and have a market value. In the example, we
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assume that there is a 40 percent probability that the market will work efficiently and trading of
allowances will be active. In this case, the price of allowances is assumed to be $450 per ton. At
this price, the additional sulfur reduction achieved by the scrubber is worth 1.58 mills per kilowatt-
hour.2 So the net cost of the scrubber would be 5.42 mills (7 minus 1.58).
On the other hand, we assume there is a 60 percent probability that the market for emissions
allowances will not work efficiently and there will be no trading. This could occur if the EPA and
public service commissions impose many restrictions and laige regulatory burdens on allowance
trading. In the example, we assume the price of allowances would be zero under those
circumstances.3 Therefore, the cost of the scrubber would still be 7 mills per kilowatt-hour.
Given these costs and the uncertainties, what should a utility do if it were to make a decision now
about whether to build a scrubber? The usual approach would be a traditional expected value
calculation. Because of the uncertainty surrounding the prices of allowances, the expected cost of
this option is 23.3 mills. The cost for low sulfur coal is 23.5 mills. Translated into present value
terms the cost of scrubbing is $283 per megawatt-hour and $285 for low sulfur coal.
Thus, if the utility were to make a decision now it would conclude that the least cost option would
be to build the scrubber. This is illustrated as Strategy 1 on the top of Table 2.
Defer the Decision to Build a Scrubber
The utility does not have to make the decision now to build a scrubber. It could, for example, sign
a five year contract to buy low sulfur coal. By the time the coal contract expired, the utility would
have accumulated several years experience with the allowance market. Also, many of the
uncertainties surrounding this market would be resolved. At that time the utility could re-examine the
decision of whether to build the scrubber. In our example, if the market for allowances were to
work efficiently and there were active trading, then the utility would find, upon re-examination, that it
would still be economic to build the scrubber. On the other hand, if regulatory impediments
hindered the market, then the utility's least-cost strategy would be low sulfur coal.
The value of the additional reduction is 7 times 450 divided by 2000, which equals 1.58 mills per
kilowatt-hour.
Strictly speaking, this is not correct. If the allowance market does not function, the emissions-
related costs will be utility specific and will depend on the company's emissions cap and its costs
of removing sulfur rather than depend on the allowance price.
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Now let's calculate the cost of this deferral strategy. First, we determine the cost for the first five
years when low sulfur coal is used. At 23.5 mills per kilowatt-hour, this translates into a present
value of $100 per megawatt-hour over the five year period. This is shown under Strategy 2 in
Table 2.
Second, we need to look ahead from our vantage point of today and calculate the expected cost for
the period after the first five years. The utility can continue to bum low sulfur coal or it can build
a scrubber. The present value of the costs of burning low sulfur coal beginning in five years is
$185 per megawatt-hour. For the scrubber option, the costs will depend on how things play out with
respect to the allowance market. If it works efficiently and there is active trading, then the price
will be $450 per ton. At this price, the scrubber option will have a present value of $177 and
would, therefore, be preferred to the low sulfur coal option with the $185 cost. On the other hand,
if transactions for allowances are overburdened with regulatory rules and constraints, then the market
will not work effectively. In this case, the present value of the scrubber option will be $189, and
the least cost option would then be low sulfur coal.
These costs are also shown under Strategy 2 in Table 2. How does the utility take advantage of the
flexibility afforded by deferring the decision to build the scrubber? Very simply, by deferring a
decision, the utility will be able to take advantage of the least-cost option whether or not the market
for allowances works effectively. If the allowance market turns out to work effectively, then the
utility will select the scrubber option because its $177 per megawatt-hour cost is lowest. On the
other hand, if the market for allowances does not function well, then the utility would select low
sulfur coal because its $185 cost is lowest In summary, by deferring the decision to build the
scrubber, the utility will be able to avoid the high-cost alternative no matter how well the allowance
market ultimately works.
Now we can determine the cost of the defer strategy. As we noted above, the cost for the first five
years is $100 per megawatt-hour. If the allowance market works well (probability 40 percent), then
the cost is $177. If the market for allowances turns out not to work (probability 60 percent), then
the cost is $185. Thus, the present value of the expected cost after the first five years is $181,4
giving the defer strategy a total expected cost of $281 (100 + 181).
4 This is 177 times 0.4 plus 185 times 0.6.
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Now we can answer the question of whether the utility should commit now (Strategy 1) to building
a scrubber or defer the decision (Strategy 2). We can see that the expected value of deferring the
decision is lowest-$281 compared to $283 per megawatt-hour if die decision were made now to build
a scrubber. This comparison is shown at the bottom of Table 2.
SUMMARY
The outcomes of utility decisions regarding strategies for complying with the 1990 Clean Air Act are
uncertain. Consequently, utilities should place a premium on options that allow them the flexibility
to take advantage of new information affecting the outcomes of their decisions. Our simple example
illustrates that strategies allowing flexibility may prove to be least cost. The example also lays out
an approach utilities can use for quantifying the benefits of flexibility.
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Table 1
SIMPLE OPTIONS PROBLEM
Key Assumptions
Discount Rate (%) 9%
Scrubber Removal Rate (%) 90%
Scrubber Costs (mills/kWh) 7
High Sulfur Coal:
Cost (mills/kWh) 17
S02 Emission Rate (lbs. SOj/MMBtu)1 0.5
Low Sulfur Coal:
Cost (mills/kWh) 23.5
S02 Emission Rate (lbs. SOj/MMBtu) 1.2
Uncertain Factor
Allowance Market Allowance Market
Works Does Not Work
Probabilities (%) 40% 60%
Prices for Tradable
Allowances ($/Ton) $450 0
1 Sulfur content of flue gas to the scrubber is 5 pounds of sulfur dioxide per million Btus.
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Table 2
SIMPLE OPTIONS PROBLEM
Strategy 1: DECIDE NOW TO BURN LOW SULFUR COAL OR BUILD SCRUBBER.
Present Value of Expected Cost:
Scrubber Option
Low Sulfur Coal
Least-Cost Decision
Choice: Build Scrubber
Expected Cost of Strategy 1
$283
285
$283
Strategy 2: DEFER DECISION BY BURNING LOW SULFUR COAL FOR 5 YEARS AND
THEN RE-EXAMINE OPTIONS.
Present Value of Expected Cost:
Burn Low Sulfur Coal
First 5 Years
$100
After 5 Years
Burn Low Sulfur Coal
Build Scrubber
Expected Cost for Strategy 21
Allowance Market
Works
(Probability-.4)
185
177
Allowance Market
Does Not Work
(Probabilitv=.6)
185
189
$281
ADVANTAGE OF DEFERRING DECISION
$283 - $281 = $2
1 100 + .4 * 177 + .6 * 185 = 281
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Clean Air Technology (CAT) Workstation
D. M. Sopocy
Sargent & Lundy
55 East Monroe St.
Chicago, Illinois 60603
Wm. DePriest
Sargent & Lundy
55 East Monroe St.
Chicago, Illinois 60603
J. B. Kalanik
Sargent & Lundy
55 East Monroe St.
Chicago, Illinois 60603
A. Maurer
Sargent & Lundy
55 East Monroe St.
Chicago, Illinois 60603
R. Rhudy
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94303
2-47
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Intentionally Blank Page
2-48
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Clean Air Technology (CAT) Workstation
D. M. Sopocy (Sargent & Lundy)
Wm. DePriest (Sargent & Luruiy)
J. B. Kalanik (Sargent & Lundy)
A. Maurer (Sargent & Lundy)
R. Rhudy (EPRI)
The passage of the Clean Air Act has created an immediate need for information and services to support
compliance efforts. A significant amount of R&D has been accomplished by EPRI over the past fifteen
years on S02 and NOx reduction technologies. The results of this R&D is embodied in numerous reports,
several computer codes, and the expertise of EPRI Project and Program Managers in this area. The
immediacy of the industry needs in addressing the requirements of the Clean Air Act are such that these
existing resources are unlikely to be fully utilized in their present form. A workstation has been developed
to consolidate and integrate the existing information for ready accessibility by EPRI member utilities,
placing them in a position to make the best informed decisions for their specific requirements. This Clean
Air Technology (CAT) Workstation has been developed under a strategic alliance between EPRI and
Sargent & Lundy.
The CAT Workstation assembles a number of related EPRI software products into a computer workstation
to aid utilities in responding to acid rain issues. Capabilities include an evaluation of site-specific
technology applicability; least cost evaluations of compliance strategy on a utility-specific basis; generation
of input for functional bid specifications; a continuous emission monitor guideline; and the ability to
evaluate proposals using the EPRI FGDPRISM™ computer program.
The usefulness of the CAT Workstation extends far beyond the initial identification and evaluation of
compliance strategies that have already been undertaken by many utilities. The optimal compliance strategy
is dependent upon many factors that are likely to change over time from those used in the initial evaluation,
including economic parameters, unit capacity factors, and the projected value of emission credits.
Consequently, each utility's compliance strategy should be re-evaluated each time the utility revises its
economic parameters, system planning, or projection of emission credit valuation. The flexibility and ease
of use of the CAT Workstation makes this regular re-evaluation of compliance strategies practicable.
OBJECTIVES
The technical objectives of the CAT Workstation are to leverage existing EPRI R&D results and informa-
tion on S02 and NOx reduction technologies to the maximum extent to aid the utility industry in complying
with the provisions of the Clean Air Act by accomplishing the following goals:
• Consolidating existing, relevant information from previous EPRI R&D in a single computer-based
source (i.e., the CAT Workstation).
• Providing a means for utility users to quickly identify the appropriate clean air technologies for their
specific requirements through a technical screening and then to evaluate these selected technologies
on an economic basis.
• Providing an effective means of technology transfer through an easy-to-use, easy-to-learn graphical
user interface to the workstation software.
Preceding page blank
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CAT WORKSTATION DESIGN
The CAT Workstation has been designed to provide an interactive, integrated set of software tools which
will educate users on selected Clean Air Act compliance technologies and assist users in the evaluation of
compliance strategies, definition of specification requirements, and evaluation of FGD system proposals.
The major components of the initial version of the CAT Workstation are described in the following sections
and include:
• Economic Screening Module (ARCOMP)
('provides optimized economic evaluation of system-wide emission compliance strategies)
• Utility System Databases
(contains economic screening input and results)
Default Databases (ERAM, TAG)
(contains default utility-specific input (ERAM) and general economic parameters (TAG))
"Verified" Databases
(contains user-specified, utility-specific information serving as alternate default databases)
"Working" Databases
(contains input and results for all saved evaluation scenarios)
• Technology "Macro" Screening and User Input Module
(provides for screening and selection of emission control technologies to be considered in the
evaluation of compliance strategies)
• CAT Tools
(contains tools for the analysis/evaluation of selected technologies)
- FGDCOST
(provides estimation of site-specific FGD system costs)
- CQIM
(provides estimation of cost and performance impacts of switching coals)
- NOxPERT
(provides selection and cost estimation of site-specific NOx emission compliance strategies)
- FGDPRISM
(provides process simulation model for wet limestone and magnesium-enhanced lime FGD
systems)
• Technology Guideline Modules
(contains a compendium of technical and economic information on selected emission control
technologies)
• Functional Specification Guideline Modules
(generates application-specific Junctional specification guidelines for selected technologies)
• Continuous Emission Monitoring Guideline Module
(contains a compendium of technical and economic information on continuous emission monitors)
The relationship of these components of the CAT Workstation is shown in Figure 1. This figure illustrates
the general flow of information in the CAT Workstation at a simplified level of detail.
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Future additions and enhancements to the CAT Workstation may include additional technology guideline
modules and associated functional specification guidelines; a set of operations training modules; accessing
an enhanced version of FGDPRISM supporting process analysis/optimization and providing automated
generation of process specification guidelines; a financial/risk analysis module; integration of additional,
related EPRI software applications; and a tie-in to EPRINET.
The CAT workstation consolidates and manages the technical and economic information necessary to
evaluate the economic impact of the strategies available to utilities working to comply with the Clean Air
Act. Previously EPRI-developed software tools are used to refine the input data for economic evaluations
of various technologies and implementation strategies across a utility system. The economic evaluations
identify the unit-technology combinations that result in the lowest evaluated cost for all plants within a
single utility system. The influence of external forces can also be evaluated by assessing options such as
buying or selling emission allowances or kilowatts.
Economic Screening Module (ARCOMP)
The Economic Screening Module (ARCOMP) is the heart of the CAT Workstation. This module performs
economic screening of all possible unit-technology combinations selected by the user to be a potential part
of a compliance strategy for the Clean Air Act. This economic screening evaluates the total cost of
compliance with the Clean Air Act for each possible combination of candidate technologies and units in the
utility system. The total evaluation period may be broken down into a number of periods which are
multiples of yearly increments. These individual evaluation periods may differ in length.
For each evaluation period, each technology type that the user has chosen as applicable to each unit defined
in the user's project is evaluated to determine the unit's emission level, capital costs associated with the
technology, and operating costs for the unit. Each of the individual units' emissions and costs are then
summed for the period providing a total period emission level and cost. If the total emission level for all
the units in a given period are greater than the allowable-emission level for the period, the combination of
technologies is not acceptable.
The algorithm employed by the Economic Screening Module is designed so that all viable technology
combinations are evaluated by the program. This assures that the full spectrum of available options are
considered and analyzed resulting in the lowest-cost compliance strategy over the entire evaluation period.
The capital and operating costs for each period are converted to a user-defined levelized basis and then
summed giving the total compliance cost. The lowest cost sets of unit-technologies combinations for all
periods (i.e., 50 lowest cost options) are output to the user. As with any computer software that evaluates
economic options over extended periods, the results of any particular run will be very dependent on the
input data. Therefore, users are recommended to conduct an evaluation of several sensitivity runs before
proceeding with the next steps in the overall evaluation/decision process.
Input Data. The following general classes of input data are used in the economic analysis conducted by
the Economic Screening Module of the CAT Workstation:
• Project Data — Miscellaneous system data including unit names, emission allowance buy/
sell/bank strategy, and general economic factors.
• Period Data — Time-dependent information such as economic factors and unit capacity
information for each user-defined time increment (period) of an evalua-
tion.
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• Unit Data — The unit location, type, ratings, and current configuration, including
period-based emission allowances plus if and when the utility chooses to
"Opt-In" the unit for additional emission credits (if qualified).
• Technology Data — Specific technology information such as space requirements, water
requirements, etc. associated with the technology installation.
• Unit-Technology Data — Technology application to a specific unit. For example, the unit heat
rate, S02 emissions, and capital and operating costs with a specific
technology installed. User-defined technology combinations are consid-
ered as a single technology by the evaluation program.
• Fuel Data — Fuel characteristics including coal and other fuel types, chemical com-
positions, and economic information.
• Evaluation Output — Results of the economic evaluation such as each technology choice for
each unit for each period, costs, and total and unit emission levels.
Screening Algorithm. The algorithm used to screen clean air technology implementation strategies is based
upon defining a number of pass/fail tests for the unit-technology combinations considered for a period. The
fundamental pass/fail test is that the sum of all emissions from each unit for each year during the period
must be less than or equal to the allowable emissions fincluding emission credits and allowance buy/sell/-
bank strategy) for the period. Several user-specified restrictions that constitute additional pass/fail criteria
are used to supplement this fundamental emission level criteria. These restrictions eliminate a large number
of unit-technology combinations and reflect realistic constraints imposed by practical considerations,
including available cash-flow. Some of these additional restrictions include:
• Technology Lifespan — A unit will be locked into using an installed technology for a mini-
mum amount of time after technology installation. This constraint
reflects that a practical implementation strategy would not install a
capital-cost-intensive clean air technology with the intent of replacing
this technology in a short time with an alternate technology.
• Tech-Switch Periods — The calculation of emissions is performed on a period-by-period
basis. Outside factors may prevent a technology switch at a plant
during a specific period or periods. To accommodate this constraint
and minimize the number of permutations, the user will specify the
periods that each unit can switch emission control technology. Each
unit's technology-switch periods are independent of each other. The
unit-specific switch period overrides the end of a technology lifetime
(a unit will not be allowed to switch technologies until the next unit
technology switch period). Figure 2 displays the relationship between
overall evaluation period, calculation periods, and technology-switch
periods. For example, using the switch periods defined in Figure 2,
Unit 3 can switch technologies at the beginning of periods 4, 8, and
9.
• Inter-Unit Dependencies — A technology and or fuel choice may only be applicable for a group
of units rather than a single unit due to site-specific commercial
physical constraints. The user shall select the technology-fuel inter-
unit dependencies. Dependencies may be single-sided (one or many
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units dependent upon a single unit) or double-sided (all units in the
dependency must switch to the same technology-fuel combination at
the same time).
Emission Calculations. The Economic Screening Module receives as input the S02, NOx and particulate
removal efficiencies for each of the technology options under study at a given unit. These removal
efficiency levels are used in calculating the yearly emission rate for each unit and the total emissions for the
period using each of the unit-period-based capacity factors. The emission level used for period calculations
is adjusted by the unit capacity factor for the period assuming a linear relationship between capacity factor
and emissions.
Emission Credit Banking and Selling. The user may specify a strategy which will define the maximum
amount of emission credits that will be bought, banked, or sold per year. The amount of emission credits
bought, banked, or sold may be specified in units of absolute emission credits or as a percentage of the total
allowable emissions. For example, a user may specify that they will sell up to 10% of the utilities banked
emission credits or up to an absolute amount (e.g., 10,000 tons SO2).
Total emissions and emission credit transactions are calculated on a yearly basis.
Period costs also consider cost of, or profits from, emission credit transactions within the period.
Economic Calculations. All costs for each unit are calculated on a levelized, period basis using user-
specified period-based escalation rates. Each unit combination has fixed costs; variable costs (including
heat rate penalty, auxiliary power, consumables, etc.); derate costs, if applicable; and, if a technology
switch has occurred, capital costs for a given period. All levelized unit costs are summed for all units to
provide a total period cost. All levelized period costs are summed to give a total cost for the given unit-
technology combinations.
Some of the major economic parameters that can be user-specified are summarized as follows, including the
degree and dependency of variability that can be specified:
Parameter Dependency
Discount Rate Fixed for all Periods
Levelized Fixed Charge Rate Fixed for all Periods
Capital Cost Escalation Rate Period Dependent
Derate Cost Escalation Rate Period Dependent
Fuel Escalation Rate Fuel and Period Dependent
Operation and Maintenance Cost Escalation Rate Period Dependent
Utility System Databases
A security system to limit access to the CAT databases is provided to protect the large amount and variety
of data which may be stored on the CAT Workstation. For example, a utility may wish to enter the current
projection of future capacity factors for all units to be used as a consistent basis for all present and future
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CAT analyses. Accordingly, this information is stored in a protected, verified database to prevent
modification by casual CAT users but allow modification when the utility's system capacity factor
projections are revised.
The CAT software employs a number of different data files which are modified as the user refines input
data and eliminates non-viable technology options. To safeguard this data, the CAT database structure
provides protected default databases plus a working database structure as explained in the following
paragraphs.
Default Databases. A utility-specific database generated by EPRI's Emission Reduction Analysis Model
(ERAM) simulation will be provided to EPRI-member utility users. This database will include baseline unit
and alternative technology data for each of the utility's units as default values for an initial analysis. This
utility-specific ERAM analysis will provide economic impact data on the use of various emission control
technologies with different coal types for each unit in the utility's system. This baseline data is used as the
default database in the CAT Workstation that provides users with a starting point in the analysis of clean air
technology implementation strategies. Users are able to refine this default data through the use of a number
of specific tools (see CAT Tools) or through user-friendly input screens. The output of these tools may then
be used to improve the input to the economic evaluation.
The CAT Workstation also includes a database of default economic parameters from EPRI's Technical
Assessment Guide (TAG).
"Verified" Databases. The verified databases are defined as CAT databases which the user wishes to save
as official files which can serve as alternate default databases. For example, general economic information
which should be used for all investigations would be saved in a "verified" database.
Users are able to maintain one or more verified databases to reflect different compliance strategies.
"Working" Databases. The working databases are used to store different user-defined plant and economic
configurations. For example, working databases contain CAT information necessary to explore user-
defined modifications such as changes to plant specific economic parameters, fuel costs, plant capacity
factor, etc. Users have the ability to create and store different compliance strategies under development in
the working database. A working database may contain evaluations of different technologies, fuel types,
and unit configurations.
A user can copy data from verified data files to working data files, but only users with the required access
level will be able to store data from a working database to verified data files. This will prevent accidental
loss of data and allow individuals the opportunity to perform various analyses without the fear of destroying
original input data.
The user can create new data records in a working database and can also copy an existing verified data
record from the verified database with the following options:
1) Keep same key data field identifier (i.e., unit name for unit database)
2) Enter a new key data field identifier.
This allows quick generation of different scenarios using the verified database as the source of information.
A new user will typically initially create a active database from the default ERAM databases. The user can
then review the data, run an economic analysis, and/or modify the data. At this point the user can save the
data in a working or verified database for future use. On subsequent sessions the user may recall the
working or verified data.
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Technology "Macro" Screening Module & User Input Module
The Technology "Macro" Screening Module helps users review and screen out inappropriate and/or
impractical technologies for clean air compliance based on some basic unit design criteria. This module is
used to create and modify clean air technology application scenarios across the utility system for economic
analysis. This module also performs modifications to the CAT databases.
The initial information contained in the CAT databases will be based upon the supplied ERAM database and
generic default databases. The generic default databases will contain required information not supplied by
the ERAM databases, such as default economic parameters from EPRI's TAG. The user will create
different scenarios for analysis by modifying the various CAT databases stored for that scenario using the
User Input Module. The verified CAT databases will not be modified by this action. The user will also
have the option of resetting all or sections of the verified or working databases to the original ERAM/-
default values.
Access to the CAT tools (described in the following paragraphs) with tool-specific help will be provided.
Descriptions of the tool input choices will be provided and a method to review the input data before running
the selected tool included. A method to review the output from each tool before adding the information to
the CAT working databases will also be provided.
CAT Tools
The CAT workstation provides a number of technology-specific tools to refine input data for use in the
economic-screening module and to allow the user methods to further analyze/evaluate the selected
technologies. The different CAT tools (CQIM, FGDCOST, NOxPERT, and FGDPRISM) will use the
CAT databases as a source of input information. The output from the CAT tools can be used to update and
refine the CAT databases. Users will be able to review the output from the CAT tools without updating the
CAT databases. As an aid in maintaining input data source control to the CAT databases, the CAT
workstation will automatically track the sources of input data to the economic analysis module.
Flue gas Desulfurization Cost (FGDCOST). EPRI's FGDCOST is an existing interactive cost estimating
model that planners and engineers can use to quickly obtain estimates of site-specific flue gas desulfurization
(FGD) system costs. Fifteen different FGD technologies are currently included. The model uses internally
stored design information to enable users to readily estimate capital, O&M, and total levelized costs for
both new and retrofit applications. The model computes costs by using site-specific data entered by the
user and default values for the selected FGD process. User inputs revolve around economic criteria,
boiler/coal characteristics, site conditions, and adjustments for retrofit difficulty. Sensitivity analyses can be
performed for variations in utility economic and design criteria, as well as site-related alternatives.
FGDCOST will refine the FGD emission-reduction technology data in the CAT database used as input to
the economic-evaluation module. To execute the FGDCOST software, CAT will start FGDCOST and send
information from the CAT database to the FGDCOST process. FGDCOST will complete the analysis and
CAT will allow the user to view the FGDCOST results and update applicable data.
FGDCOST will use CAT databases as input. Relevant output from FGDCOST will be used to update the
CAT databases.
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goal Quality jmoact Model (COIMV EPRI's CQIM is an existing user-friendly program capable of
predicting cost and performance impacts of switching coals in existing pulverized coal and cyclone-fired
generating units. The CQIM program can be used for analyzing coal purchase options, determining coal
quality price adjustments, analyzing fuel switching and blending options, analyzing acid rain legislation
compliance options, screening coals prior to test burns, and many other tasks associated with estimating
coal quality cost and performance impacts. Detailed equipment models determine unit and system
performance, auxiliary power, consumables, waste generation, derates, replacement power, and mainte-
nance costs. The program includes a detailed steam generator heat transfer model and a detailed mainten-
ance/availability model. CQIM will refine the coal switch/blending technology data in the CAT database
used as input to the economic-evaluation module.
The CAT software will generate CQIM-compatible input data files based upon user-entered data from the
CAT databases. Relevant output from CQIM will be used to update the CAT databases.
NOxPERT. EPRI's NOxPERT is an existing interactive model that planners and engineers can use to
quickly select and obtain cost estimates of site-specific NOx emissions compliance strategies. The program
uses internally stored algorithms to predict NOx emission levels from coal-fired boilers, and recommend a
technology for user specified NOx emissions reductions. The program calculates the costs of implementing
the recommended technology and provides technical advice about the selected technology. It provides the
user with the ability to examine the technical and economic implications of legislation for different NOx
control scenarios. However, NOxPERT is not meant to be a substitute for detailed cost estimates of NOx
control implementation or emissions testing.
NOxPERT can be accessed from the CAT Workstation to refine emission-reduction technology data in the
CAT database used as input to the economic-evaluation module. The CAT software will generate
NOxPERT-compatible input data files based upon CAT databases. Relevant output from NOxPERT will be
used to update the CAT databases.
Flue gas Desulfurization Process Integration and Simulation Model (TGDPRISMV FGDPRISM is a
process simulation model for wet limestone and magnesium-enhanced lime FGD systems. FGDPRISM
provides a powerful tool for predicting a number of very important FGD system performance indicators
through the use of PC simulations. The model can be extremely valuable in designing and evaluating new
FGD systems as well as in troubleshooting and investigating process or equipment modifications for
operating FGD systems. FGDPRISM can also be used to evaluate FGD technologies based upon process-
stream chemistries.
FGDPRISM is based on fundamental chemical engineering principles. The model consists of unit
operations modules using equilibrium, mass transfer, and thermodynamic principles to simulate performance
of chemical processes. The unit operations are sequenced and "communicate" with each other through
streams defined in the input file. A number of templates which set specific sequences for unit operations
and streams are included in the model. These templates define configurations for simulating FGD system
overall material balance, reaction tank design, spray and/or tray absorber designs, and complete system
simulations using spray and/or tray absorbers for inhibited, natural, or forced oxidation wet limestone FGD
systems.
It is expected that the FGDPRISM output will be used primarily by the CAT user to develop the process
design portions of S02 control system specifications and/or evaluate FGD system proposals rather than as
input to the CAT economic analysis. CAT will generate FGDPRISM-compatible input data files based
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upon the CAT databases and provide FGDPRISM input help information based upon the FGDPRISM user's
manual.
Technology Guideline Modules
The following set of Technology Guideline Modules is being provided in the CAT Workstation that spans
the range of options being considered by the utility industry for clean air compliance:
• FGD Technology Options (General Considerations)
• Wet Limestone Forced Oxidation FGD Systems
• Spray Dryer FGD Systems
• Duct Sorbent Injection
• Coal Cleaning
• Coal Blending/Switching
Additional Technology Guideline Modules may be added in the future. These modules provide the CAT
Workstation user with a wide range of background information that will help the user make informed
decisions regarding the selection of technologies for further evaluation. Each of these Technology
Guideline Modules is being based primarily on existing EPRI R&D results and information. The content of
these modules is being organized according to the outline summarized in Table 1.
Functional Specification Guideline Modules
This module performs the generation of unit-specific functional specification guidelines for each technology
in a given emission compliance scenario. These functional specification guidelines reflect the user-input
baseline data and technology guideline choices. The basis of these guidelines will be paragraphs for key
elements of each technology from existing standards and EPRI handbooks.
Continuous Emission Monitoring Guideline Module
A Technology Guideline Module covering continuous emission monitoring technology information is also
being provided in the CAT Workstation. This module is intended to provide users with the capability to
review the technology information to make informed decisions regarding the implementation of continuous
emission monitors.
TYPICAL CAT WORKSTATION SESSION
The state-of-the-art user interface that S&L has developed for the CAT Workstation is predominantly icon-
driven and hypermedia. Although pull-down menus are provided, the primary means of navigation is
intended to be the actual information content being presented on the computer screen. These navigational
tools include a wide variety of intuitive graphical objects, MVCR"-style buttons, a "button bar" of chapter
icons across the top of the screen, and the hypertext links to the text itself. All information contained in the
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Technical Screening Module, Economic Evaluation Module, and Technology Guideline Modules of the
CAT Workstation can be accessed by either "pointing" (moving the cursor to a specific on-screen object
with the mouse) or "pointing and clicking" ("pointing" followed by immediately pressing the left mouse
button) at an object of interest. Throughout these modules, hypertext information is designated by italicized
text. "Pointing and clicking" at any italicized text accesses relevant hypertext information.
The concept of "information visualization" and content of the CAT Workstation are illustrated by the series
of screens presented in Figures 3-11.
Typically, a first-time user will begin by reviewing the series of screens that provide an overview on using
the CAT Workstation. Figure 3 shows one of these screens that illustrates the steps involved in using the
workstation to evaluate emission reduction implementation strategies. This illustration serves a dual
function as an alternate navigation aid. Clicking on any one of the illustrated steps brings the user directly
to that portion of the CAT Workstation. As shown in Figure 3, the user is also provided with a complete
set of pull-down menus and a set of icons representing each of the major operations in the CAT Work-
station. These icons are displayed across the top of the screen in a "button bar" throughout the CAT
Workstation. These icons serve both as a visual reminder of the major functions of the workstation, as well
as a shortcut to any of these functions.
Pointing at any one of these icons displays the appropriate function name to avoid confusing neophyte or
infrequent users.
Typically, a first-time user is going to proceed through the CAT Workstation functions in sequential order.
After creating a working file by copying the default file, the user will proceed to the Project Setup screen to
review the units, fuels, and technologies that are contained in the database, as shown in Figure 4. The user
can elect to add and/or delete units, fuels, and technologies from the working database.
Electing to add a fuel to be available for evaluation, the user is presented with a screen (Figure S) that lists
all of the coals and other fuels currently in the database. The user can create a new fuel by selecting any
two of the listed fuels and specifying a blend by percentage.
The user can specify performance, economic, and configuration data for each of the units to be evaluated.
Figure 6 shows the screen for specifying unit-specific economic and emissions data. The information on the
left side of this screen is fixed for the entire evaluation. The information on the right side of this screen
may be changed for each of the periods being evaluated.
Figure 7 shows the screen used to specify the periods to be evaluated and to specify period-specific
economic parameters. The left side of the screen allows the user to scroll through each of the currently
specified evaluation periods and to view and edit period-specific economic parameters. The user can also
elect to add or delete evaluation periods. The right side of the screen shows the currently specified
evaluation periods and illustrates the addition of an evaluation period.
Once all of the unit, economic, and technology information has been specified, the user can either have the
CAT Workstation screen all technology and fuel combinations that are technically feasible for each unit, or
manually select the specific technology-fuel combinations to be evaluated for each unit, as shown in Figure
8. This screen shows a manual screening where the user is selecting specific technology-fuel combinations
to be evaluated for each unit in the utility system.
The last step before conducting an economic evaluation is to specify any fuel and/or technology dependen-
cies among the units being evaluated, as shown in Figure 9. Any unit listed in the user-specified dependen-
cy group must switch to the same fuel, technology, or technology-fuel combination being evaluated for any
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one of the units in the dependency group that has been designated as a "Master". This dependency applies
only to fuels, technologies, and technology-fuel combinations that are explicitly specified by the user for the
dependency group.
Once the economic evaluation has been completed, the user is provided with a listing of the fifty lowest cost
implementation scenarios, ranked by cost, and a summary of the total cost for each evaluation period for
the selected scenario as shown in Figure 10. The user can also view a summary of the specific technology-
fuel combinations that comprise each of the top-ranked scenarios for each evaluation period, as shown in
Figure 11.
Once the user is satisfied with an evaluation, the next step is to refine the performance and cost data for the
unit-technology-fuel combinations in the top-ranked scenario(s) using the appropriate CAT Tools: FGDC-
OST and/or CQIM. The user would then re-run the evaluation and continue refining the data as necessary.
The user will consult the CAT Technology Guideline Modules when in need of background information to
help decide on which technologies should be evaluated. These modules will be consistent with those being
developed for the State-of-the-Art Power Plant (SOAPP) Workstation, a parallel EPRI project. Examples of
the content of these modules are provided in Figures 12-14. These figures show screens from the
Technology Guideline Module on Improved Electrostatic Precipitators, which typifies these modules.
Figure 12 shows the process description overview screen for precharging/staging. The basic difference
between this advanced technology and conventional precipitators is illustrated by the simplified process
schematic. Clicking on the icons for any of the alternate technologies allows the user to quickly compare
process differences. More detailed, hypertext-linked technical information on the selected process is
available by clicking on the listed subjects.
Figure 13 shows the economics overview screen comparing the relative total evaluated life cycle costs for
the four improved electrostatic precipitator technologies to that for conventional technology. Clicking on
unit size, fuel type, or emission limit allows the user to vary these parameters and immediately see the
impact on evaluated costs. Again, more detailed economic information is available by clicking on the listed
subjects.
Figure 14 shows a screen comparing the detailed construction schedule for a selected advanced technology
to that for conventional technology. Again, clicking on unit size, fuel type, or emission limit allows the
user to vary these parameters and immediately see the impact on construction schedule.
HARDWARE/SOFTWARE REQUIREMENTS
The CAT workstation is designed to operate under DOS 3.3 or above with the Microsoft Windows 3.0 or
above operating environment. Use of CQIM requires the installation of OS/2 Version 1.1 or above.
The minimum hardware configuration to run the CAT Workstation is as follows:
1) 386-25 Mhz Microprocessor (w/ math co-processor)
2) 8 MByte RAM
3) 300 Mbyte Hard Drive
4) Mouse or equivalent pointing device
5) VGA graphics Card with VGA monitor
6) HP Laserjet Printer or equivalent
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SUMMARY AND CONCLUSIONS
EPRI and Sargent & Lundy have entered into a strategic alliance to provide a Clean Air Technology (CAT)
Workstation to assist utilities in evaluating and implementing emission reduction strategies. The CAT
Workstation provides an integrated, interactive set of software tools which educates users on selected
emission reduction technologies and assists users in the evaluation of compliance strategies, definition of
specification requirements, and evaluation of S02 control system proposals.
The usefulness of the CAT Workstation goes far beyond the initial identification and evaluation of
compliance strategies. The flexibility and ease of use of the CAT Workstation make regular re-evaluation
of compliance strategies feasible in the face of changing economic factors and system planning consider-
ations.
ACKNOWLEDGEMENTS
The authors wish to Mr. Thomas Tokarski for his design of the user interface for the CAT Workstation.
The authors also wish to acknowledge Mr. Dennis P. Ward for his original concept for ARCOMP, the
economic evaluation module, and for his expertise regarding Clean Air Act implementation considerations
embodied in the economic evaluation module of the CAT Workstation.
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Table 1
CAT Workstation Technology Guideline Module Outline
Technology Descriptions
- Conventional Technology
- Advanced Technologies
Design Basis
- Performance
- Scope of Supply
- Balance of Plant Impacts
- Configuration Drawings
Schedule
- Overall Duration
Detailed Durations
- Advanced Construction Methods
Economic Data
- Total Capital Requirements
- Fixed Operating and Maintenance Costs
- Variable Operating and Maintenance Costs
- Fuel Costs (directly attributable to each technology)
- Availability Impact
- Total Evaluated Cost
Operating Experience
New Versus Retrofit Issues
Bibliography (data bases)
- Literature
- Codes/Standards
Glossary
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Figure 1
CAT WORKSTATION
General Flow of Information
User
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Module
FGDCOST
FGDPRISM
Output
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Verified
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CQIM
NOxPERT
Technology
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Economic
Screening
Module
Working
Database
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Figure 2
Unit-Specific Technology Switch Periods for Economic Analysis
Unit 1
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=» No Technology Switch Allowed in Period
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Figure 3
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Economic Evaluations of 28 FGD Processes
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ECONOMIC EVALUATIONS OF 28 FGD PROCESSES
R. J. Keeth
P. A. Ireland
United Engineers & Constructors, Inc.
5555 Greenwood Plaza Boulevard
Englewood, Colorado 80111
P. T. Radcliffe
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94304
ABSTRACT
During the period of 1982-1986, EPRI sponsored a study performed by United
Engineers & Constructors Inc. (then Stearns-Roger Corporation) to develop costs
for 26 flue gas desulfurization processes. EPRI has initiated a follow-on
effort to update these economic evaluations to 1990 costs, as well as to analyze
the technical merit and commercial status of currently available and emerging
S02 control technologies. The results of the technical and economic evaluations
have been published in a two volume report, EPRI GS-7193 (I). This paper will
present the results of this recently completed study, which was conducted by
United Engineers & Constructors, Inc. Capital and operating costs for the 28
FGD processes evaluated to date (wet, dry and sulfur recovery technologies) will
be presented. A discussion of the estimating methodology is included along with
a description of the EPRI spreadsheet computer models which allow the user to
calculate site specific FGD costs for any of the 28 processes.
SUMMARY
The technical, economic and commercial evaluations of 28 FGD processes have been
completed. The processes evaluated are listed in Table 1. This paper presents
comparative cost estimates for the first 28 processes investigated. Additional
processes may be evaluated in the future. EPRI's new computer model (FGDCOST),
Preceding page blank
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which was released this year following utility testing and review, is briefly
described. The model provides the flexibility to readily adapt the cost
estimates to specific plant sites and utility criteria.
The results of the evaluations indicate that:
• Overall, FGD costs are lower than previously estimated.
• Costs in terms of $/ton of S02 removed are very close for many
technologies.
• The dry injection technologies generally have much lower
capital costs; however, total levelized costs will often be
higher due to larger quantities and higher cost of the
reagent required.
Costs for the major categories of FGD processes can be summarized as follows.
For retrofit FGD installations, the range of capital requirements and total
levelized costs over 15 years of service life with no inflation (constant dollar
analysis) are estimated to be:
1990 Dollars
Capital $/ton S02
$/kW (Constant S)
Wet FGD 180-260 460-620
Sulfur Recovery FGD 250-380 640-820
Dry FGD 50-220 410-1,470
The proper use of the estimates for technology screening is explained in this
paper, where the reader will also find qualifications and cautions regarding
their use. Further explanation of the estimate basis is included in GS-7193. A
computerized FGDC0ST model that can help utilities tailor these cost estimates
to specific plant sites is available from EPRI.
INTRODUCTION
EPRI recognized the utility industry's need for cost information in order to
develop plans for complying with acid rain legislation. EPRI began a project in
July, 1988, to update cost estimates for flue gas desulfurization (FGD) systems.
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EPRI's previous evaluations were published in a five volume report (CS-3342)
over a four year period from 1983 through 1986. The first two volumes of the
updated FGD Economic Evaluations were published this year as EPRI report GS-
7193.
This paper presents only a limited summary of the comparative overall cost
estimates. Detailed technical, commercial and economic evaluations and
breakdowns of costs for each process are included in GS-7193.
The evaluations are intended to provide the utility industry with a means to
make informed choices when screening alternative FGD technologies. The
objectives of the current project included the following:
• Update comparative cost estimates for those FGD processes
that are commercially marketed.
a Assess the promise of emerging technologies, clarifying their
potential, as well as their risks and drawbacks.
• Evaluate both wet, dry and by-product recovery technologies.
a Incorporate recent technological advancements and research
results.
t Modify criteria to current industry practice.
t Produce a new computer cost model with greater user
flexibility.
A utility project advisory committee is involved in the review of results, and
provides feedback on assumptions used in developing the estimates and design
criteria. The computer model developed by UE&C under this contract went through
demonstration testing by the advisory group.
TECHNICAL & ECONOMIC CRITERIA
All cost evaluations were developed within the framework of EPRI's Technical
Assessment Guidelines, updated September, 1989 (EPRI Report P-6587-L). Overall,
the estimates can be considered to have an absolute accuracy of +20%, and a
relative accuracy of +10% (when comparing one process to another for the same
conditions). A very brief description of the cost estimating methodology
fol1ows.
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General design criteria and sparing requirements were established jointly by
UE&C and EPRI. The basic design criteria were reviewed with selected major
suppliers of each process to establish essential design requirements and
component sizing. Quotes were obtained from three or four bidders for all major
pieces of equipment. Prices were then cross-checked with a national
computerized material cost tracking network. Bulk quantities and installation
labor charges were developed to arrive at installation factors for each piece of
equipment. Labor manhours were adjusted for local productivity rates (Kenosha,
WI is the base case).
The installed costs are allocated to eight technical cost areas to derive the
Total Process Capital cost. The Technical Cost Areas are listed in Table 2.
Components of the Process Capital are listed in Table 3. Other costs, such as
general facilities, engineering and home office fees, and contingencies are
applied to each cost area and factored in to obtain the Total Plant Cost.
Indirect costs such as AFDC (allowance for funds during construction), pre-
production costs, and inventory capital are included to arrive at the Total
Capital Requirement. A breakdown of the total capital cost components is shown
in Table 4. Appropriate retrofit factors are applied to each cost area,
reflecting the additional costs that would be expected for a typical retrofit
situation. Site characteristics which can significantly affect retrofit capital
costs include seismic zone, access and congestion, soil/geotechnical conditions,
demolition and underground obstructions.
Operating labor and maintenance costs were also developed. The operating labor
costs are based on the number of FGD system operators, supervisors, laboratory
personnel, etc., estimated for each process. Maintenance factors are applied as
a percentage of the process capital cost for each subsystem to develop the
system maintenance cost. Maintenance factors are assigned based on complexity
of equipment and severity of process conditions. A ratio of 40% labor and 60%
materials is used for maintenance cost development.
Variable operating costs include reagent, power, steam, water, waste disposal,
and credit for by-product sale. The capital and operating costs were converted
to a levelized cost using the appropriate fixed charge rate for capital and
levelization factor for O&M costs. Final cost estimates, in terms of $/kW-yr,
mills/kWh, and $/ton of S02 removed, are presented in the following formats:
t First-year costs
2-76
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• Current levelized dollars (assuming 5% annual inflation)
• Constant levelized dollars (0% inflation)
Table 5 lists the general technical and economic design criteria used in these
evaluations. Criteria specific to each process are presented in the associated
evaluation sections of the final report.
Equipment redundancy has been included to ensure acceptable reliability. Spares
were included for FGD components whose loss would require immediate shutdown of
the system. Components such as tanks, silos, agitators, and heat exchangers do
not have spares. Three 50% absorber modules were included in all wet FGD
systems.
Factors for process and project contingencies were assigned for each technical
cost area. Process contingency factors reflect the stage of development of each
process - commercially available, installed in the size range of 20-100 MW,
pilot scale, and bench scale. Project contingency is an allowance for
additional equipment or other costs that would result from a more detailed
design. Each technical cost area within a single process will have different
contingency factors.
An example of the One-Page Summary output from the cost model is shown in Table
6. This example was generated for a new installation of the wet limestone
forced oxidation FGD process.
COMPARATIVE COST SUMMARIES
Figures 1 and 2 present comparative capital cost ranges for each of the wet FGD
and sulfur recovery processes evaluated to date as retrofits to a 300 MW plant
burning a 2.6% sulfur coal. All of these systems are capable of 90% S02
removal. Capital costs for dry technologies in a retrofit scenario are
presented in Figure 3. Figures 4 and 5 present total levelized costs in terms
of $/ton of S02 removed on a constant dollar basis (1990 $) for the retrofit wet
and recovery systems. Figure 6 presents levelized costs for the retrofit dry
FGD systems.
The results demonstrate that the commercially available wet throwaway (and wall-
board grade gypsum by-product) FGD systems can be retrofit with capital costs in
the range of $180 to $260/kW. The total levelized costs for these throwaway
2-77
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systems will be in the range of $460 to $620/ton of S02 removed (constant
dollars). Dry FGD systems can be retrofit at a capital cost in the range of $50
to $220/kW. Total levelized costs for these dry processes will be in the range
of $410 to $l,470/ton S02 removed. The sulfur recovery systems have
substantially higher capital costs due to the inclusion of by-product production
facilities and storage systems ($250-$380/kW). This high capital cost causes
the total levelized constant dollar costs to also be high ($640 to $820/ton S02
removed).
It should be noted that lime spray dryers have not been commercially applied to
units burning coal with a sulfur content greater than 2%. Recent research,
however, has demonstrated S02 removal capability above 90% with a variety of
lime reagents while burning coal with sulfur content greater than 2%.
Performance has been found to be enhanced by the presence of chlorides.
Two of the FGD processes (HYPAS and NaTec) evaluated are being commercially
targeted for specific market niches, and were therefore evaluated separately.
With relatively higher reagent costs, but lower capital costs, it was believed
that these processes would be used more as S02 trimming systems. The HYPAS
system was evaluated for a coal with sulfur content of 1.5%, and assuming a
maximum 70% removal capability. HYPAS includes a downstream pulse jet fabric
filter. NaTec also specified that a low sulfur (0.48%) coal be used as the
basis for their evaluation due to the high cost of the reagent. A 50% removal
rate was selected for this analysis.
CHANGES FROM PREVIOUS EPRI ESTIMATES
The design and economic criteria for the base case current cost estimates have
changed from those used in previous (1982-86) EPRI cost estimates. All of these
base case criteria can be varied to fit the criteria for a specific site using
the FGDC0ST computer model. The principal changes in the base case include the
following:
Plant Size - reduced from 2-500 MW units to one 300 MW, which corresponds to the
size range for a large percentage of the coal-fired boiler population.
Coal Composition - coal sulfur content was reduced from 4.0% to 2.6% and heating
value was increased from 10,800 to 13,100 Btu/lb, which EPRI believes is more
representative of the coal typically burned today. This heating value and
2-78
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sulfur content also match the Department of Energy coal used in the Clean Coal
Technology program. These changes resulted in a 35% reduction in S02 removed
and a 12% reduction in the flue gas volume. (The computer model will permit
sensitivity analyses for coals ranging from 0.5% to 6.0%.)
Engineering - reduced from 12.5% to 10% of total process capital to reflect the
experience and knowledge gained from the first generation of FGD systems
installed at utility power generating stations.
Maturing Technology - Many of the problems with the first generation of
scrubbers have been solved, and overseas designs have incorporated numerous
advancements. As the industry benefits from the learning curve, design
improvements are being incorporated in newer, more standardized designs. These
advancements are reflected in reduced contingency, less component sparing, in-
situ oxidation, and reduced reheat.
Financial/Accounting Practice - With the reduced plant size (from 1000 MW to 300
MW), the construction period was reduced form 3 to 2 years, resulting in a lower
Allowance for Funds During Construction. In addition, when presenting capital
and operating costs expressed in $/kW and mills/kWh, respectively, the kW used
are the plant output before the FGD system addition, whereas the original study
used the net kW after the FGD system addition. FGD power is now charged
strictly as an operating expense at 50 mills/kWh.
Market demand may also impact the FGD marketplace. Very few FGD systems have
been sold in the past few years, and suppliers have been willing to reduce their
mark-ups during this period of reduced demand. It is quite probable that this
may change to a seller's market, resulting from a large number of buyers
entering the marketplace simultaneously. It is very difficult to quantify the
magnitude of this impact, and the impact is likely to be substantially different
depending upon the type of process. The tendency for cost increases will be
restrained to some degree by market penetration from foreign FGD systems
suppliers, who have been actively developing their processes overseas where
stringent acid rain controls have been enacted. A means for adjusting for
market demand escalation has been built into the FGDCOST model.
2-79
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FGD COST MODEL
The model is a menu-driven spreadsheet (one spreadsheet for each FGD process)
that uses internally stored design and cost information to enable users to
readily estimate capital, O&M, and total levelized costs for both new and
retrofit applications.
The model computes costs by using site-specific data entered by the user and/or
default values for the selected FGD process (3). User inputs revolve around
economic criteria, boiler/coal characteristics, site conditions, FGD system
operating parameters and adjustments for retrofit difficulty. Site
characteristics which can significantly affect retrofit costs include plant
location, seismic zone, access and congestion, soil/geotechnical conditions,
demolition and underground obstructions.
With the technical design criteria, reagent and coal selected, the model first
characterizes the flue gas stream exiting the boiler, then creates a material
balance for the designated FGD system. Values from the material balance are
used in capacity/cost function relationships to develop material costs for major
components. Each component has a distinct capacity/cost function based on
vendor quotations. Material costs are escalated to plant startup date dollars,
then multiplied by installation factors (also adjusted for capacity or size) to
arrive at total installed costs. Indirect costs for general facilities,
engineering and home office fees, and process and project contingencies are
added in to obtain the Total Plant Cost (TPC).
The Total Plant Cost is de-escalated to obtain the actual money spent over the
construction period, generating the Total Cash Expended (TCE). The Allowance
for Funds During Construction (AFDC) is calculated using the AFDC rate (cost of
capital for construction) and construction duration. Total Plant Investment is
equal to TCE + AFDC. Other indirect costs such as preproduction, inventory
capital, initial chemicals, and royalties are added in to arrive at the Total
Capital Requirement (TCR).
In general, capital costs are based on vendor quotations obtained prior to
passage of the 1990 Clean Air Act Amendments. These modifications to the CAA
may cause an increase in demand for FGD system components, and corresponding
escalation for FGD services and equipment. The user can enter an estimate of
the market demand escalation to adjust the TCR.
2-80
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Capita^ costs are converted to annual charges using levelized fixed charge rates
and added to O&M costs calculated by the model to obtain the total annual
level ized costs which are expressed in terms of both mills/kWh and $/ton of S02
removed. First year costs are also calculated.
A detailed discussion of EPRI's cost estimating methodology is presented in the
1989 EPRI Technical Assessment Guide (TAG), EPRI report number P-6587-L (2).
Incorporating the TAG guidelines into the model serves to standardize the
results. This allows a comparison of the costs for each process on a consistent
basis.
Site- and unit-specific variables such as S02 removal efficiency, sparing
philosophy for all major components, waste disposal and labor costs can be
modified. The model guides the user through the retrofit factor selection
describing the degree of difficulty associated with access/congestion,
underground obstructions, and soil conditions. Estimates for a new plant can be
developed by accepting the default settings. Once inputs are completed, the
spreadsheet can be recalculated generating a new cost estimate.
User inputs can be saved as a worksheet file, to be later retrieved for use in
subsequent runs. Sensitivity analyses can be performed for variations in
utility economic and design criteria, as well as site-related alternatives.
This enables users to identify the relative importance of different cost
elements, such as capital equipment, energy, manpower, and reagent. FGDCOST
replaces RETROFGD, a computerized FGD cost estimating code released by EPRI in
1987.
CONCLUSIONS
Analysis of the 28 processes evaluated to date indicates that FGD technology has
matured and that the escalating cost trend of the past has been halted. The
levelized control costs in terms of $/ton for most of the processes are within a
relatively narrow range. When looking at only wet throwaway FGD systems, there
is not a substantial difference in capital costs, although greater variability
can be expected when adjusting costs for site-specific conditions. The dry
injection processes offer lower capital expenditures, but typically have higher
operating costs for the medium and high sulfur coals due to their higher reagent
cost. However, they may be a practical choice for retrofit on older, smaller
2-81
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units that are frequently cycled in load, or that have limited space for
retrofit of a wet FGD system. The HYPAS process may be suitable for plants
requiring an upgrade in particulate collection.
Site-specific retrofit factors will have a significant impact on costs. In
addition, plant modifications beyond the FGD system (such as waste disposal,
stack relining/rebuilding, particulate control upgrades to accommodate the dry
processes, etc.) can have a significant cost impact.
Cost estimates in this paper are based on use of standard organic linings over
carbon steel substrates (predominantly rubber for absorbers and flakeglass for
outlet ducts). The capital costs can be substantially higher if high grade
alloys are utilized. A menu of alloy choices for the absorber, ducts and stack
liners is included in the FGDCOST model.
Comparing wet FGD with the dry injection technologies is difficult to do on an
equal basis. The dry technologies vary widely in their level of development and
many concerns remain with their performance and impacts on the balance of plant.
Most of the wet processes are commercial and have a much larger experience base.
The dry injection processes involve much less equipment relative to wet FGD.
Retrofit factors may differ between wet and dry injection FGD processes
retrofitted at the same plant, since access/congestion will be different and
soil conditions will have less of an effect on the dry FGD process equipment.
The wet FGD processes are normally designed for 90% S02 removal efficiency or
greater. The dry processes have efficiencies ranging from 50% to 90%.
The FGD supplier base has undergone substantial restructuring over the past few
years, which has altered pricing strategies. A dramatic increase in market
demand may lead suppliers to alter their pricing strategies. The timing of a
utility's contract may be a significant factor in the cost of services and
equipment.
CAUTIONS & RISKS
Estimating the costs of flue gas desulfurization (FGD) at a new power generating
station is a difficult task. Evaluating the cost impact from retrofitting FGD
at existing installations is even more difficult. In both cases the estimates
are frequently a subject for debate, with widely varying viewpoints, depending
2-82
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on the viewer's perspective. In many cases, the assumptions and bases used to
develop such estimates are not provided, and it is difficult to reproduce or
reasonably compare the results.
Often, the reason for different cost estimates can be found in differences in
scope. This project is attempting to present the bases for all the estimates in
a consistent format, and make the estimate methodology as transparent as
possible, clearly defining battery limits for each process. It must be
emphasized that the use of premises or assumptions different from EPRI's
criteria could alter the comparative ranking of process costs.
Site-specific retrofit factors will have a significant impact on costs. All FGD
process costs were evaluated on the basis of a moderately difficult retrofit,
assuming a 1.3 retrofit factor. In the recent NAPAP (National Acid
Precipitation Assessment Program) study sponsored by the EPA, 200 plant sites
were assessed for retrofitting FGD. Most of the sites had retrofit limitations,
with retrofit factors ranging from a low of 1.19 to as high as 3.0 versus new
plant costs (4). In addition, plant modifications beyond the FGD system (such
as waste disposal, stack relining/rebuilding, particulate control upgrades to
accommodate the dry processes, etc.) can have a significant cost impact.
This study does not take into account differences in plant outage times for
installation of the FGD system. The wet FGD systems, as well as those dry
processes with separate reaction vessels can normally be constructed with the
plant on-line, with the inlet and outlet ducts connected to the existing
ductwork during a normal unit outage. The dry injection technologies may
require longer outage periods for installing gas path injection systems and
removal of existing internal obstructions.
REFERENCES
1. Keeth, R. J., et al. Economic Evaluation of FGD Systems. EPRI GS-7193,
Volumes 1 and 2, EPRI Publications, 1991.
2. EPRI GS-7525L, FGDCOST User's Manual. 1991.
3. EPRI P-6587-L, Technical Assessment Guide, 1989.
4. Emmel, T., et al. "Retrofit Costs of S02 Controls in the U.S. and the
Federal Republic of Germany," present at EPA/EPRI 1990 S02 Control
Symposium, May 1990.
2-83
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WET THROWAWAY CAPITAL COSTS
(RETROFIT, 300 MW, 2.6% S)
1990 t/kW
250
200
150
100
50
L6PO LSWB INH DBA CI 21 PURE MQL 8ISC S-H KRC NSP LDA L6DA
RECOVERY PROCESS CAPITAL COSTS
(RETROFIT, 300 MW, 2.6% S)
400
300
200
100
0
WLMN-LORO 80XAL I6PRA MagOn L8F0
1990 t/kW
j i ; I r I ii— i
DRY THROWAWAY CAPITAL COSTS
(RETROFIT, 300 MW, 2.6% S)
1990 t/kW
250
200
150
100
50
'W
60%
60%
90%
LSD LIFAC CFB FSI E! DSI DSD ADVA
LSFO
ALTERNATE THROWAWAY CAPITAL COSTS
(RETROFIT, VARIOUS S%, REMOVAL & MW)
500
400
300
200
100
0
NATEC LSFO HYPAS LSFO PASS LSFO
.6%/60%/300MW 1.5%/60%/3O0M W 2.6%/90%/100MW
1990 9/kW
-------
WET THROWAWAY LEVELIZED COSTS
(RETROFIT, 300 MW, 2.6% S)
600
500
400
300
200
100
0
LSFO LSWB INH OtA C121 PURE MQL BISC 6-H KRC N6P IDA L6DA
CONSTANT 1990 $n*ON OF 602 REMOVED
J_J l_ _ _l_ _ _L_1_Lj_ _ _lJ L_ _l_l 1 II I 1 i L_L
RECOVERY PROCESS LEVELIZED COSTS
(RETROFIT, 300 MW, 2.6% S)
1000
800
600
400
200
0
WLMN-LORD SOXAL I6PRA MagOx LSFO
CONSTANT *n*ON OF S02 REMOVED
DRY THROWAWAY LEVELIZED COSTS
(RETROFIT. 300 MW, 2.6% S)
700
600
500
400
300
200
100
0
ALTERNATE THROWAWAY LEVELIZED COSTS
(RETROFIT, VARIOUS S%, REMOVAL & MW)
3000
2500
2000
1500
1000
500
0
NATEC L6FO HYFAS LSFO PASS LSFO
.5%/50%/300MW 1.5*/60*/300MW 2.6%/90%/100MW
CONSTANT */TON OF S02 REMOVED
80%
60%
90%
r
J.
LSD LIFAC CFB
FSI
DSI
DSD ADVA
LSFO
CONSTANT »/TON OF SQ2 REMOVED
J -x*r-:-x1 I
-------
Table 1
FGD PROCESSES EVALUATED
IN EPRI STUDY
Wet Throwawav
Limestone with Forced Oxidation (LSFO)
Limestone with Wall board Gypsum (LSWB)
Magnesium Enhanced Lime (MGLM)
Limestone/Inhibited Oxidation (LSINH)
Limestone with Dibasic Acid (LSDBA)
Pure Air/Mitsubishi (PURE)
CT121/Bechtel (CT121)
NSP Bubbler (NSP)
Passamaquoddy Recovery Scrubber (PSMQY)
Saarberg Holter (S-H)
BISCHOFF (BSHF)
Noel1/KRC (KRC)
Regenerable Throwawav
Lime Dual Alkali (LDA)
Limestone Dual Alkali (LSDA)
Dry Throwawav
Lime Spray Dryer (LSD)
Furnace Sorbent Injection (FSI)
Economizer Injection (EI)
Duct Sorbent Injection (DSI)
Duct Spray Drying (DSD)
Tampella LIFAC (LIFAC)
Lurgi Circulating Fluid Bed (CFB)
HYPAS (HYPAS)
ADVACATE/Moist Dust Injection (ADV)
NaTec Dry Sodium Injection (NATEC)
Sulfur Recovery
SOXAL (SOXAL)
Wellman-Lord (WM-LD)
Magnesium Oxide (MgO)
ISPRA Bromine (ISPRA)
2-86
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Table 2
COST AREAS FOR PROCESS CAPITAL BREAKDOWN
Area
Description
10
20
30
40
50
60
70
80
Reagent Feed System
S02 Removal System
Flue Gas System
Regeneration System
By-product System
Waste Handling System
General Support Area
Miscellaneous Equipment
10:
20:
30:
40:
50:
60:
70:
80:
Reagent Feed System - all equipment required for storage, handling and
preparation of raw materials, reagents, and additives used in each process.
S02 Removal System - equipment required for S02 scrubbing, such as the
absorption tower, recirculate pumps and other associated equipment.
Flue Gas System - ductwork and fans required for flue gas distribution to
the S02 scrubbing system, plus gas reheat as required.
Regeneration System - specific to regenerable systems, equipment used to
regenerate spent reagent for return to the process, plus any
preconditioning system for S02 or H2S off-gas.
By-product System - production equipment for salable process by-products
and storage facilities for the final products.
Waste Handling System - equipment required for fixation, treatment, and
transportation of all waste materials produced by each scrubbing process.
General Support Area - additional equipment required to support FGD system
operation.
Miscellaneous Equipment - This system will include plant modifications
necessitated by the addition of FGD. Examples include stack
rebuild/reline, boiler modifications for dry injection, additional ESP
collection area, additional insulation or linings for the ESP or Fabric
Filter, and/or an enlarged ash handling system to transport the increased
amount of waste solids. Also included are costs for electrical equipment
tie-ins and other associated systems.
2-87
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Table 3
PROCESS CAPITAL COMPONENTS
Earthwork
Concrete
Buildings and Structures
Process Equipment
Piping
Electrical
Painting
Instruments and Controls
Insulation
Direct Field Labor
Indirect Field Costs
Payroll Taxes
Insurance
Bonds
Construction Supplies
Temporary Facilities
Construction Equipment
Vendor Fees
Total Process Capital
Table 4
CAPITAL COST COMPONENTS
Process Capital (Includes Sales Tax) +
General Facilities +
Engineering and Home Office Fees +
Project Contingency +
Process Contingency
= Total Plant Cost TPC
Total Cash Expended TCE* +
AFDC (funds during construction)
= Total Plant Investment TPI
Royalty Allowance +
Preproduction Costs +
Inventory Capital +
Initial Catalyst and Chemicals +
Land
Total Capital Requirement, TCR
*TPC x Adjustment factor per Table 3-4 of EPRI TAG (P6587-L)
2-88
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Table 5
TECHNICAL AND ECONOMIC CRITERIA
FOR FGD ECONOMIC EVALUATIONS
technical
Single 300 NW unit
Design Coals:
All systems except HYPAS and NaTec =
2.6X sulfur Appalachian Coal
13,100 Btu/lb (HHV)
HYPAS = 1.5% S coal
« 13,000 Btu/lb
NaTec = 0.48% S coal
* 8,020 Btu/lb
Kenosha, HI location
2-year construction period
65% plant capacity factor
Cbaseloaded)
Moderate retrofit difficulty (1.3
retrofit factor) for all processes
90% S02 removal for all wet and regenerable FGD,
spray dryer, Lurgi CFB Advacate/MDI
50% for dry injection technologies, except
60% for HYPAS, 80% for Tampella-LIFAC
Tho operating absorber modules plus
one spare
Particulate removal equipment or upgrades
not included (except PJFF in HYPAS)
Particulate removal meets NSPS
(0.03 Ib/MM Btu)
137% excess air at scrubber inlet
Boiler modifications not included
ID fan cost allocated on basis of
FGD pressure drop
Stack rebuilding or relining riot
included
Note: A 1.3 retrofit factor assumes:
"Minor underground obstructions
(i.e., piping and ductbanks)
"Access interference by
existing structures
"Large crane access is limited.
economic
January, 1990 dollars
15-year plant life (retrofit)
Current dollar analysis:
Discount rate * 11.5%
For 15-yr. book life, 15-yr. tax life:
Levelled fixed charge rate = 19.2%
First-year fixed charge rate = 24.5%
Annual Inflation » 5%
Real annual escalation = 0.3%
(power and steam)
Constant dollar analysis:
Discount rate * 6.2%
For 15-yr. book life, 15-yr. tax life;
Leveliled fixed charge rate = 14.0%
First-year fixed charge rate = 17.4%
Real Annual Escalation = 0.3%
(power and steam)
General facilities « 10% of Total Process Capital
A/E engineering and home office fees =
10% of Total Process Capital
Maintenance and contingency factors vary by
process and technical cost area:
Project contingency = 10 to 30% of Total
Plant Cost
Process contingency « 2 to 30% of Total
Plant Cost
Maintenance Factors = 1.5 to 10% of Total Cost
Electric Power (in plant) = 50 mills/Rub
Operating labor = $20/hr
Lime = $55/ton (delivered)
Limestone « $15/ton (delivered)
Soda ash = $93/ton (delivered)
DBA = $360/ton
Formic acid = $820/ton (delivered)
Sulfur emulsion » $220/ton
Dry solids disposal (trucked to landfill) =
$8.00/dry ton (unlined)
Sludge disposal (trucked to landfill) =
S8.15/dry ton (unlined)
$9.25/dry ton (lined)
Sludge disposal to pond = $6.00/dry ton
Gypsum disposal (pumped and stacked) =
$4.75/dry ton
Gypsum by-product credit = $2.00/ton
Sulfur by-product credit = $90/Lton
Sulfuric acid by-product credit = $50/ton
Potassium oxide by-product credit = $350/ton
Steam = $3.50/1000 lb.
2-89
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Table 6
SAMPLE OF ONE PAGE SUMMARY OF THE LSFO ECONOMIC EVALUATION
INPUTS
Fuel Type ¦ Applacfc.
* S Coal • 2.60
Plant's Net Rating (MO • 300.00
Plant Capacity Factor « 65%
Plant Location • Wisconsin
OUTPUTS
Reagent Type ¦ Mtdmt-Ls
Reagent coat (t/tcn) ¦ 15.00
see Removal » 90X
Ca/S Removed Molar Ratio « 1.10
Reagent Reqjired (tons/hr) • 9.44 Boiler Efficiency (X) 86.00
Fly Ash from Coal (tons/hr) * 8.42 Fffl Power Ccrsmption (*J) 4.97
FGD Slufce, dry (tons/hr) « 15.27
CAPITAL COSTS (~/* 20X)
1990
(»)
Market Demand Escalation
Power Outage Penalty
Land Cost
TOTAL CAPITAL REQUIREMENT (TCR) 64,094,519
(Including Market Demand Escalation,
Power Outage Penalty and Land Co6t)
(*/KV)
10 Reagent Feed System * 10,912,914 36.4
20 SOE Removal System * 20,778,753 60.3
30 Flue Gas System = 7,248,628 24.2
40 Regeneration • 0 0.0
50 Byproduct Handling « 0 0.0
60 Solids Handling * 2,124,078 7.1
70 General Stpport Ecfjipment ¦= 546,240 1.8
80 Miscellaneous Equipment ¦= 1,218,416 4.1
TOTAL PROCESS CAPITAL
General Facilities 4,282,903 14.3
Engineering and Heme Office Fees 4,282,903 14.3
Process Contingency 1,027,897 3.4
Project Contingency 7,419,794 24.7
TOTAL PLANT COST (TPC) 59,842,525 199.5
42,829,029 142.8
61,694,794 205.6
TOTAL CASH EXPENDS) (TCE) 58,417,703 194.7
Allowance for Finds (AFUDC) 3,277,091 10.9
TOTAL PLANT 1NVEST>CNT (TPI)
Preproduction Co6ts 1,981,657 6.6
Inventory Capital 203.9Z3 0.7
Initial Catalyst and Chemicals 0 0.0
Royalties 214,145 0.7
TOTAL CAPITAL REQUIREMENT (TCR) 64,094,519 213.6
0.0
0.0
0.0
213.6
OffRALL MATERIAL COST ADJUSTMENTS
Retrofit Factor *
Installation Factor *
1.291
2.183
FIRST-YEAR AM) LEVEL IZH) COSTS <~/" 20X)
First Year
Levelized - Current Dollars
30 Years
Levelized - Constant Dollars
30 Years
Major Co6t Components
1990
*
S/KU-YR
MILS/KWH
VTon SOB
Removed
VKU-YR
HILS/KUH
S/Ton SOS
Removed
S/KH-YR
HILS/KUH
S/Ton SOS
Removed
Fixed 0 ( H
Variable Operating
Fixed Charges
3,435,516
3,599,448
13,588,038
11.45
12.00
45.29
2.01
2.11
7.95
116.84
122.42
462.14
18.47
19.74
35.25
3.24
3.47
6.19
188.44
201.38
359.68
11.45
12.24
22.65
2.01
2.15
3.98
116.84
124.87
231.07
Total
20,623,001
68.74
12.07
701.40
73.46
12.90
749.51
46.34
8.14
472.78
2-90
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STRATEGIES FOR MEETING SULPHUR ABATEMENT TARGETS
IN THE UK ELECTRICITY SUPPLY INDUSTRY
W S KYTE
PowerGen pic
Moat Lane
Solihull
West Midlands
B9I 2JN
2-91
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2-S2
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STRATEGIES FOR MEETING SULPHUR ABATEMENT TARGETS
IN THE UK ELECTRICITY SUPPLY INDUSTRY
ABSTRACT
Three major events have impacted on the generation of electricity in the United Kingdom in the latter
part of 1990 and the early part of 1991. These are the privatisation of the public electricity supply
industry, the publication of the National Plan by Government for implementing the EEC Large Com-
bustion Plants Directive and the passing and implementation of the Environmental Protection Act,
1990.
The implications of these events and their interaction will be discussed in the paper together with the
options and strategies which will be utilised to achieve the required reductions in sulphur dioxide
emissions in a competitive generation market. The implications of the evolving UK environmental
regulation will be highlighted.
Preceding page blank
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STRUCTURE AND ORGANISATION OF THE INDUSTRY IN ENGLAND AND WALES
HISTORICAL BACKGROUND
Under the Electricity Act 1947 the structure of the nationalised electricity supply industry in England
and Wales (ESI) had the following features.
# The Central Electricity Generating Board (CEGB)
produced the vast majority of the electricity generated
in England and Wales and contributed some 94 per cent of
the electricity supplied to the total system in England
and Wales in the year ended 31 March 1990.
# The CEGB owned and operated the bulk transmission system
and its share of the interconnections with France and Scotland.
It also operated the other interconnection assets based in England
# The 12 Area Boards purchased electricity, almost all of it
from the CEGB, and distributed and sold it to customers
within their designated areas in England and Wales.
# The Electricity Council exercised a co-ordinating role
for the ESI, providing services in areas of common interest.
Under this structure the CEGB had a statutory duty to provide bulk supplies of electricity to the 12
Area Boards and had an effective monopoly in generation, and bulk transmission.
The New Industry Structure
In February 1988, HM Government published its proposals for the restructuring and subsequent
privatisation of the Electricity Supply Industry (ESI) in a White Paper entitled "Privatising Electricity".
The White Paper included proposals for the introduction of competition into generation and supply.
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The subsequent legislation, the Electricity Act, received Royal Assent in July 1989. After a period of
preparation and negotiation, the new industry structure was introduced on 31 March 1990. Under
the new structure:
# The CEGB's assets and liabilities have been transferred to four successor compa
nies.
# Three of these successor companies are engaged predominantly in generation.
Ownership of the CEGB's fossil fuelled power stations has been equitably divided
between National Power and PowerGen in the ratio 60:40; the two companies
have sites throughout England and Wales. Its nuclear power stations have been
transferred to Nuclear Electric. It is intended that Nuclear Electric will remain
within the public sector.
# The national grid and the CEGB's interests in the interconnections with France
and Scotland, together with the pumped storage power stations at Dinorwig and
Ffestiniog, have been transferred from the CEGB to the National Grid Company
(NGC), the fourth successor company. NGC is the subsidiary of The National
Grid Holding pic (NG Holding); NG Holding is owned by the RECs.
# The business of the 12 Area Boards have been transferred to the 12 Regional
Electricity Companies (RECs).
# The co-ordinating role of the Electricity Council has been abolished.
# Shares in National Power and PowerGen were sold in February 1991.
National Power, PowerGen, Nuclear Electric and other generating companies compete in the genera-
tion of electricity by bidding into a 'pool' operated by the NGC. The CEGB's statutory duty to pro-
vide bulk supplies of electricity has been abolished.
New licensing and regulatory arrangements also apply in respect of Scotland. However, Scottish
Power pic (Scottish Power) and Scottish Hydro-Electric pic (Hydro-Electric) carry out the activities of
generation, transmission, distribution and supply in Scotland on a vertically integrated basis, as before.
Using available capacity across the Scottish interconnections, each of these companies competes with
other generators in the generation of electricity for sale in England and Wales. The nuclear power
stations previously owned by the South of Scotland Electricity Board are owned and operated by
Scottish Nuclear Limited (Scottish Nuclear), which carries on business only as a generator. Shares in
Scottish Power and Hydro-Electric were sold during 1991, but Scottish Nuclear will remain within the
public sector.
Factors which will influence National Power's and PowerGen's respective shares of the market in-
clude their competitiveness in relation to each other and to other generators, the extent of moves to
own generation by large electricity consumers, the availability of Nuclear Electric's nuclear power
stations and the volume of electricity transmitted across the interconnection with France. These last
two factors will determine the proportions of the market taken by Nuclear Electric and EdF respec-
tively, which directly affect the size of the market available to other generators.
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Existing Generating Capacity
At 31 December 1990, the vast majority of generating capacity in England and Wales was owned by
the CEGB successor companies and Table I provides an analysis of the capacity of these successor
companies by energy source at that date.
Hydro,
Fossil
Fuelled
Nuclear
Wind and
Pumped
Storage
Total
Capacity
MW
MW
MW
MW
%
National
Power
29,445
-
41
29,486
50.2
PowerGen
18,711
-
53
18,764
32 . 0
Nuclear
Electric
-
8,333
24
8, 357
14.2
NGC
-
-
2, 088
2, 088
3.6
48,156
8,333
2, 206
58,695
100. 0
Table I. The Capacities of CEGB Successor Companies at
31 December 1990
In England and Wales 86.4% of the CEGB's plant was non-nuclear, 53.5% was coal-fired and 17.7% oil-
fired. The non-nuclear plant is rather old; at December 1990 66% of PowerGen plant and 63% of
National Power plant was over 20 years old.
During most of the 1980s and as at 31 March 1990 there was generating capacity in England and
Wales substantially in excess of that which would have been considered necessary by the CEGB to
comply with the ESI's standard for generation security and both National Power and PowerGen have
announced closure programmes for elderly, inefficient, plant.
A decision to build new generating capacity will primarily depend on the return provided by the
projected difference between the revenues earned by the plant and the plant's operating and capital
costs.
There are already a large number of proposals for Combined Cycle Gas Turbine (CCGT) plant from
National Power, PowerGen, RECs and other parties.
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Advanced Coal Technologies
PowerGen, National Power and others have funded a project to assess a process for the conversion
of coal to a gas which could be burnt in substitution for natural gas at CCGT power stations. The
project was completed in December 1990. If successfully developed for commercial application, such
a process would permit generation at a higher thermal efficiency with lower S02 (and NOx) emissions
than existing coal-fired power stations.
PowerGen is also participating in research to assess the use of topping cycles based on gasification of
coal combined with fluidised bed combustion. If established commercially, this process would permit
generation at a high level of thermal efficiency and produce significantly lower emissions than those
arising from conventional coal-fired generation.
The current stage of development of advanced coal technologies in the UK means that it is too early
to assess their potential impact although in the longer term it is possible that these technologies will
play an important role.
ELECTRICITY GENERATION AND THE ENVIRONMENT
Introduction
The environmental impact of the construction, operation and decommissioning of major power
stations in England and Wales is regulated by a range of legislation, in some cases reflecting initiatives
taken within the EC. Of particular importance to fossil fuelled power stations is legislation relating to
their emissions and discharges. Recently, attention in the UK and the EC has focussed on the extent
to which fiscal measures might be used to protect the environment. The nature and impact of such
measures on the electricity generation industry are as yet uncertain.
Principal Legislation
The Environmental Protection Act 1990, which provides a framework for legislation in this area, will
be the principal means through which HM Government will impose limits to meet the UK's environ-
mental obligations, including those on S02 and NOx emissions, under relevant EC Directives and
United Nations Economic Commission for Europe Protocols. The Environmental Protection Act will
confer powers on HM Inspectorate of Pollution (HMIP) to impose limits on power station emissions
through authorisations which will be required for the operation of each power station. HM Govern-
ment caused the relevant regulations under the Environmental Protection Act relating to emissions to
come into effect on I April 1991.
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Regulations (The Environmental Protection (Prescribed Processes and Substances) Regulations 1991)
issued by the Department of Environment required that applications for existing large combustion
process plants be made by 30 April 1991. (Where applications are made in accordance with the
Environmental Protection Act and to the above timetable, the plant is permitted to continue to oper-
ate under existing controls until such date as an authorisation or refusal of an authorisation under the
Environmental Protection Act is issued).
The Environmental Protection Act introduces two new concepts into pollution control. The first is
integrated pollution control, i.e. the integrated control of all releases to air, water and land. This will
require HMIP, when considering applications for authorisations, to seek to minimise pollution of the
environment taken as a whole, having regard to the best practicable environmental option.
The second concept is best available techniques not entailing excessive cost (BATNEEC). The Envi-
ronmental Protection Act is designed to ensure the use of BATNEEC by the operators of scheduled
processes (which include electricity generation) for preventing emissions of prescribed substances or,
where that is not practicable, for minimising them and for rendering them harmless and for rendering
harmless any other substances which might cause harm if released. The use of BATNEEC is one of
the objectives which HMIP must seek to achieve when imposing specific conditions in authorisations.
Other objectives are compliance with directions of the Secretary of State given for the implementa-
tion of international obligations, compliance with quality standards and objectives prescribed by the
Secretary of State and compliance with any plan of emission reductions made by the Secretary of
State under the Environmental Protection Act. Where any of these objectives conflict, the more
onerous standard will apply. The Secretary of State has the power to direct whether specific condi-
tions should or should not be imposed. The obligation to use BATNEEC will also be imposed on
operators by way of a condition that the Environmental Protection Act implies into each authorisation
with respect to aspects of the authorised process, even when those aspects are not regulated by a
specific condition.
The concept of BATNEEC relates to working practices and other operational matters as well as to
technology. HMIP will require that any emission abatement equipment fitted to a power station
should be fully utilised within normal operating parameters. The obligation to use BATNEEC will
continue beyond the timescales set by the National Plan. HMIP has a duty to follow developments in
technology and techniques, and its view of BATNEEC may change accordingly over time.
In respect of emissions to air, the principal EC Directives currently in force are the Air Framework
Directive (84/360) and the Large Combustion Plants Directive (88/609) (LCPD). Article 13 of the Air
Framework Directive requires the implementation of policies and strategies for the gradual adaptation
of existing plant to best available technology for controlling emissions, taking into account a number of
factors including the life expectancy and rate of utilisation of the plant and the desirability of not
entailing excessive cost. The LCPD requires member states to draw up programmes for the progres-
sive reduction of total emissions of S02 and NOx from existing large combustion plant (i.e. that for
which consent was granted before July 1987); this includes all the fossil fuelled power stations owned
by National Power and PowerGen with the exception of gas-oil turbine power stations.
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The LCPD also requires member states to impose limits on emissions of S02, NOx and particulate
matter from large combustion plant for which consent is or was granted after June 1987.
The National Plan
For existing plant, the LCPD will be implemented by means of a national plan drawn up by HM Gov-
ernment under the Environmental Protection Act (the National Plan) which specifies the reductions
required for different industrial sectors and, in the case of the electricity industry in England and
Wales, for National Power and PowerGen. Individual quotas totalling the company emission limits
prescribed in the National Plan will be allocated to each power station through authorisations granted
to the two companies under the Environmental Protection Act and will be enforced by HMIP.
In drawing up the National Plan, HM Government took account of the combination of measures by
which the electricity industry in England and Wales would achieve the required reductions in S02
emissions.
Table 2 sets out the limits prescribed in the National Plan on total S02 emissions from existing power
stations of National Power and PowerGen and Figure I shows these data against the overall UK
targets.
The Environmental Protection Act empowers the Secretary of State to revise the National Plan.
HMIP intends to enforce control of emissions of S02 and NOx at each existing power station through
procedures which have regard to the need for operational flexibility. Each power station will be
allocated a quota of emissions by HMIP on the basis of total expected emissions during the calendar
year. The allocations to power stations owned by a particular company will add up to the total annual
emission limit for that company prescribed in the National Plan. In practice, a company may propose
an allocation scheme and submit it to HMIP for approval at any time. It is expected that consultation
on annual quotas will take place in November of the preceding year.
A company will have to notify HMIP immediately upon a power station's emissions of S02 or NOx
reaching 95 per cent of the allocated quota for that power station and will again have to notify HMIP if
the emissions reach 100 per cent The company could continue to operate the power station on
passing 100 per cent, but only if it had already applied to HMIP for an appropriately increased quota
balanced by reductions within the total emissions limit for the company, and provided that HMIP had
not indicated that it refused to accept these new allocations. HMIP has indicated that it would nor-
mally accept a balanced revision within the total emision limit of a company, provided that other
conditions in the authorisations were not breached.
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1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
National
Power
1. 595
1 , 583
1,497
1,373 '
1,290
1,189
1,085
982
920
857
793
727
660
PowerGen
1,085
1,077
1, 019
969
87 8
810
739
669
626
583
540
495
450
Total
2, 680
2,660
2,516
2,342
2,168
1, 999
1,824
1,651
1,546
1,440
1,333
1,222
1,110
(kilotonnes)
Table 2. S02 Emission Limits for National Power and
PowerGen plant in UK National Plan
LARGE COMBUSTION PLANT DIRECTIVE
UK IMPLEMENTATION 0FS02 LIMITS
3750
750 -
~i r i
(1980) 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
LIMIT FOR INDUSTRY SECTOR:
ICEGB ~ NATIONAL POWER m POWERGEN OTHER INDUSTRY Hi REFINERIES
Figure I.
2-100
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If it appeared, as a result of unforeseen circumstances, that there was a likelihood of the UK not being
able to meet its electricity supply requirements without exceeding the emission limits set out in the
National Plan, HM Government would consider the need for any amendment to the annual emission
limit of a company, and for a direction to HMIP that an application by a company for a consequent
increase in S02 or NOx quotas should be agreed and its individual plant authorisations amended
accordingly. HM Government's policy for dealing with such applications would depend on the re-
quirements of the Environmental Protection Act, the Air Framework Directive, the LCPD, other EC
obligations and individual circumstances. If, during a fuel security period, the Secretary of State were
to give directions regarding the operation of power stations, he would do so having taken account of
the need for any amendments to plant authorisations. The Secretary of State has the power to direct
HMIP to amend such authorisations should this be necessary.
In the absence of material developments (e.g. developments in technology or international commit-
ments), HMIP will review the conditions of each authorisation at least once in every four years and, if
necessary, new conditions will be imposed taking account of developments of pollution abatement
techniques, including the potential for operational changes leading to reduced emissions of pollutants.
HMIP intends, in issuing initial authorisations, to bring together, in uniform format, controls of the
type currently required by the Health and Safety at Work etc. Act 1974 and, subject to any views
from the National Rivers Authority (NRA), those imposed under the Water Act 1989. Given the
objectives under the Environmental Protection Act, which are to be achieved by conditions in authori-
sations, HMIP expects that initial conditions attached to authorisations will in general be at least as
stringent as the controls which apply at present.
Authorisations granted under the Environmental Protection Act in respect of any new power stations
will impose specific emission rate limits for S02, NOx, dust and any other relevant release. They will
require the use of BATNEEC, taking into account, amongst other things, the size of the power station
and type of fuel used.
Possible Revisions to SQ2 Emissions
The LCPD provides that, in 1994, the EC Commission shall report to the EC Council on the imple-
mentation of the Directive and may propose the revision of the targets for 2003 in the case of S02,
the EC Commission may also propose the revision of the dates on which those targets apply. Before
I July 1995, the EC Commission will review the standards for new plant.
In addition, an international protocol, under which the UK may be required further to limit overall
S02 emissions, is currently under negotiation.
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In the Environment White Paper published in September 1990, HM Government expressed support
for the critical loads approach. The critical load of a pollutant is the level which a particular environ-
ment can tolerate without adverse effects. Adoption of that approach could, in the longer term, lead
to tighter emission controls and less flexibility in allocating emission limits amongst individual power
stations. The critical load concept is covered in more detail in the next section.
CRITICAL LOADS
Gases affecting the acidity in the atmosphere occur naturally worldwide and acid deposition is a natu-
ral phenomenon. It is well known that emissions into the atmosphere of certain gases, principally S02
and NOx, may lead to an increase in the acidity of rain or snow. These gasesmay also be deposited
directly on surfaces, or may be incorporated in fog or mist which is then captured by vegetation.
These several processes are generaly referred to as acid deposition, or acid rain.
Much research has been and continues to be done to determine the effects on the environment of
acid deposition. Various effects have been identified which are in general brought about by accumu-
lated depositions over many years. Certain effects are deleterious. Some of these effects have been
more clearly demonstrated than others. In a number of cases there is no more than an association
between acid depositions and the observed effect
The role of acid deposition in each case is influenced by the type and duration of deposition, previous
depositions, climate, local geology and other factors. The emitting sources include domestic combus-
tion of coal and oil, industry, motor vehicles and livestock. The specific contribution that emissions
from power stations may make to acid deposition in any given country or area will vary considerably
over time, with their distance and direction from such power stations and with prevailing meteoro-
logical conditions. In addition, emissions in the country or area of deposition will themselves affect
the relative contributions of UK power stations to acid depositions in these places.
Studies are being carried out at a national and international level to analyse and assess the extent to
which such emissions in one area contribute to deposition in another. In particular, the European
Monitoring and Evaluation Programme (EMEP) has been established to track emissions throughout
Europe. Although precise techniques are not available, EMEP publishes tables annually showing each
country's calculated contribution to deposition in other countries.
The critical loads approach has been adopted by the UK and other European governments and by the
United Nations Economic Commission for Europe (UNECE). This approach, linked with the tracking
work undertaken by EMEP, seeks to identify where emission controls would be most effective in
reducing pollution levels, although the accuracy with which this could be done remains uncertain. The
concept is likely to be increasingly influential in future pollution control strategies, including the review
in 1994 of the LCPD and in forthcoming UNECE agreements. Emissions are likely to continue to be
controlled internationally through nationally imposed emission standards and legislation, and the
possibility of specific targetting affecting the electricity generation industry or even individual power
stations (whether to trace responsibility for actual emissions or to control future emissions) in the
foreseeable future cannot be dismissed.
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MEASURES TO REDUCE S02
There are a number of measures by which S02 emissions may be reduced, other than by merely
limiting generation. Table 3 summarises the relative emissions from a range of plant types and pro-
vides a basis for decision.
Plant
S02
NOx
C02
PF
1
1
1
PF+FGD+LNB
0.1
0.6
1.05
Oil
1.2
0.75
0.85
Gas
0
0.5
0.6
CCGT
0
0.25
0.5
PFBC
0.1
0.3
0.95
PFBC Topping
0.1
0.4
0.9
IGCC
0.05
0.3
0.95
IGCC Advanced
0.05
0.25
0.9
Table 3. Relative Emissions from Base Load Plant
Fuel Switching and Other Measures
Total emissions of S02 from existing fossil fuelled power stations can also be reduced by switching to
lower sulphur fuels, such as low sulphur coal or oil, by burning natural gas, or by increasing thermal
efficiency. Displacing generation from existing coal fired power stations by that from certain other
types of new plant, such as CCGTs, would also reduce overall S02 emissions for a given level of
electricity output.
At present, National Power and PowerGen are heavily dependent on coal-fired power stations fuelled
by BCC coal. The future strategy for fuel procurement is intended to give the companies the ability
to use a mix of competitively priced fuels from diversified fuel sources and to reduce dependence on
any one fuel source or supplier.
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The key elements of the fuel strategies are:
# to develop natural gas-fired generating capacity and secure long-term access to
gas supplies;
# to diversify coal supplies by increasing purchases of low sulphur imports and of
private UK coal;
# to enhance the utilisation of oil-fired power stations by increasing the use of oil
when it is commercially attractive to do so and by burning Orimulsion should
current tests establish that Orimulsion is a commercial option; and
# to develop port and transport facilities to give the capability significantly to in
crease imports of coal.
Combined Cycle Gas Turbine (CCGT) Plant
CCGT plant is likely to be the major form of new generating capacity constructed in England and
Wales for at least the next five years. Natural gas is currently available at a competitive price for
power generation and the thermal efficiency of CCGT plant is expected to be approximately 50 per
cent compared with between 35 and 38 per cent for a large coal-fired power station. In addition,
CCGT plant can be built more cheaply and quickly than coal-fired plant with an equivalent capacity
and requires significantly lower manning levels for its operation. CCGT plant also posses major envi-
ronmental advantages, producing virtually no S02 and about a quarter of the NOx and about half of
the C02 for the same output as an equivalent capacity coal-fired power station not fitted with low
NOx burners.
In addition to the competitive benefits offered by CCGT plant, the substitution of gas-fired generation
for coal-fired generation will help National Power and PowerGen to reduce dependence on any one
fuel source and to meet their respective overall emission limits. Options for use of gas include co-
firing and the use of topping cycles.
Flue Gas Desulphurisation (FGD)
The CEGB undertook research into a number of measures to reduce S02 emissions, including exten-
sive engineering studies of FGD systems. It concluded that the most suitable process for its fossil
fuelled power stations was the limestone gypsum FGD process, which is currently in use at fossil
fuelled power stations in Germany and Japan. National Power is installing FGD equipment using this
process to its power station at Drax (4000MW) and PowerGen has started construction of FGD
plant at Ratcliffe (2000MW) Power Station and has also applied for consent to instal FGD equipment
at Ferrybridge C power station (2000MW). Installation of FGD equipment will involve National
Power and PowerGen in major capital expenditure and significant additional operating costs at the
power stations concerned.
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Compliance Strategy for Future Capacity Additions:
The Role of Organic Acid Additives
2-105
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2-106
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COMPLIANCE STRATEGY FOR FUTURE CAPACITY ADDITIONS:
THE ROLE OF ORGANIC ACID ADDITIVES
C. V. Weilert
R. D. Norton
Burns & McDonnell Engineering Company
4800 E. 63rd Street
Kansas City, Missouri 64130
ABSTRACT
The S02 allowance program provisions of the Clean Air Act Amendments of 1990 require
beginning January 1, 2000, that owners of all new utility units must hold allowance:
equal to the annual tonnage of S02 emissions from the unit. Utilities which are noi
planning capacity additions must include in their planning the means by which th<
necessary allowances will be obtained.
For any utility which currently owns a generating unit equipped with an FGD system
overscrubbing the existing unit may be one source for the allowances necessary foi
future coal-fired capacity additions. By significantly increasing the S02 remova"
efficiency performance of the existing FGD system, the utility can create a bank o-
unused allowances sufficient to meet the future needs of a new unit of similai
capacity.
This paper reports the results of evaluation of the technical feasibility, operationa'
impacts, and cost effectiveness of this overscrubbing scenario. The advantages o1
using organic acid additives to reduce S02 emissions from an existing wet limeston<
FGD system are discussed. The future availability and supply of organic aci<
additives are also addressed.
Preceding page blank
2-107
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COMPLIANCE STRATEGY FOR FUTURE CAPACITY ADDITIONS:
THE ROLE OF ORGANIC ACID ADDITIVES
INTRODUCTION
The passage of the Clean Air Act Amendments of 1990 (P.L. 101-549) has created a nev
concern for utilities planning capacity additions. As part of the new Title IV -
Acid Deposition Control, Section 403(e) requires that:
"After January 1, 2000, it shall be unlawful for a new utility
unit to emit an annual tonnage of sulfur dioxide in excess of the
number of allowances to emit held for the unit by the unit's
owner or operator."
Except for a short list of new and previously planned units which are specifically
identified in Section 405(g)(2), there will be no allocation of allowances to nev
utility units. Any units for which planning is just now beginning will certainly not
be given any allocation. It will be the responsibility of the owner to obtain the
necessary allowances by the time that they are needed, which will (presumably) be
January 30, 2001 or January 30 following the year the unit begins operation, whichever
is later.
A utility contemplating the addition of baseload generating capacity in the nev
regulatory environment created by P.L. 101-549 will need to address two key concerns:
1. How to minimize the number of allowances required for the new unit.
2. Where to obtain the required number of allowances.
The subject of compliance strategies for future capacity additions is both broad and
complex. This paper addresses the topic of sulfur dioxide allowance progran
compliance planning by utilities which already have operating wet limestone FGC
systems. It considers the role that may be played, in general, by overscrubbing these
systems, and, specifically, by the use of organic acid additives to achieve this FGC
system performance improvement.
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ALLOWANCE REQUIREMENTS FOR NEW UNITS
The number of allowances required for a new unit will depend upon a range of factors
including the fuel burned, the unit capacity, the heat rate, the annual capacit
factor and the S02 control equipment efficiency.
Regulatory Considerations
The S02 control equipment efficiency required for a new unit will be establishe
through the new source review process, including the prevention of significan
deterioration (PSD) permit application. Recent trends in the development of emissio
control systems and the corresponding emergence of the "top down" methodology fo
determination of "best available control technology" (BACT) required by permittin
authorities has resulted in a downward ratcheting of emission limitations for ne
sources. In the current "technology-forcing" atmosphere of new source review, th
number of S02 emission allowances required for a new unit will be considerably les
than one might have assumed five years ago. Emission limits equivalent to 95 percen
S02 removal will be a starting point for future coal-fired units.
Example Case
For purposes of illustration throughout this paper, the example case of a new 300-M
coal-fired unit was developed. The assumptions regarding the factors affecting th
number of allowances required for this new unit, and the range of allowances required
as a function of the S02 potential of the fuel, are shown in Table 1.
SOURCES OF ALLOWANCES FOR NEW UNITS
Because the new unit will receive no allocation of allowances, and because the tota
number of allowances available to all existing and new utility units will be limite
to 8.90 million tons, there are only a few alternatives for obtaining allowances. Th
basic choices are:
1. Purchase allowances at EPA auctions.
2. Purchase allowances on the open market.
3. Redistribute allowances already held by the utility.
The third choice dictates that the number of allowances needed for the existing unit
within the utility's system be reduced at least by the number required for the ne
unit. The allotment of Phase II allowances not used by a given unit in a particula
year can be "banked" for the future, and eventually transferred to the account of th
new unit. Theoretically, the emission reductions required to achieve this could b
2-109
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made by fuel switching at the existing units. However, by the time the new unit is
to be installed, all of the existing units will effectively be limited to a system-
wide average S02 emission rate of approximately 1.2 lbs/mmBtu (the basis for
establishment of Phase II allowances). This will make any further reduction ir
emissions by fuel switching alone difficult.
Another way to reduce the need for allowances by the existing units is to improve the
performance of an existing FGD system. A utility generating unit which is currently
equipped with an FGD system is not subject to Phase I of the Clean Air Act's acic
deposition control requirements. Thus it has no allocation of Phase I allowances.
The likelihood that improvement in the performance of an existing FGD system would be
part of a Phase I S02 compliance strategy is limited due to the requirement of Sectior
408 that a unit to be used for compensating generation (i.e., emissions-basec
dispatching) in a compliance plan would become an affected unit under Phase I and be
subject to the N0X reduction requirements of Section 407.
A more likely scenario is that the FGD performance improvement would be included ir
planning for Phase II compliance, including the considerations of capacity expansior
options by the utility.
EXISTING SCRUBBED UNITS AS A SOURCE OF ALLOWANCE BANKING
There are two reasons why existing units which are equipped with FGD systems can serve
as a possible source of allowance banking for future use by a new unit. One relates
to the allowance allotment scheme established in the legislation. The other relates
to the potential for overscrubbing noted above. Each is explained in more detail
through the use of specific examples in the following sections.
Allowance Allocations for Existing Scrubbed Units
Section 405(d) of the Clean Air Act provides that coal-fired units which had 1985 S0;
emission rates below 1.20 lbs/mmBtu will receive Phase II allowances 20 percent ir
excess of those which would otherwise have been required based on annual S02 emissions
for that year. The equation used for calculating the allowances for units in this
category is:
Basic allowance allotment =
1985-1987
Baseline x
mmBtu
1985
emission x 120%
rate
(1)
2000
2-110
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Table 2 shows the effect of this allowance allotment for the example 300-MW unit, ovei
a representative range of 1985 emission rates for existing U.S. FGD systems. Thi
total allowances shown in Table 2 include an adjustment to subtract 2.8% of the basii
allowances as provided by section 416(b). Note that, by comparison to Table 1, th<
number of excess Phase II allowances for the existing unit is in some cases adequati
to cover the complete allowance needs of a new unit of the same capacity.
Overscrubbinq for Additional Banking
In many cases the excess allowances allotted to an existing scrubbed unit, such a:
those illustrated in Table 2, will not be enough to cover the allowance requirement:
of a new coal-fired unit. In these instances, the existing unit with a scrubber ha:
the capability to provide a larger bank of unused allowances through the use of th<
overscrubbing scenario.
Degree of Overscrubbinq Required. The additional S02 emission reduction required o-
an existing FGD system to cover the allowance requirements of a future unit can b<
calculated using the following equation:
R « 100 ( 1 - (( A, - A2 ) / E, )) (2;
Where:
R = Additional reduction required in existing unit emissions, %
A, = Existing unit allowances (tons/yr)
A2 = Required allowances for new unit (tons/yr)
E, = Existing unit current emissions(tons/yr)
For the case in which the existing unit requires all of its allowances and has n<
excess available (i.e., E1 = ^ ), the equation reduces to:
R - 100 ( A2 / A, ) (3;
Tables 3 and 4 presents the results of this calculation using equations 2 and 3.
respectively, for the example case in which an existing unit's FGD system performanc<
will be improved to provide a bank of allowances for an identical size new unit. Th(
data tabulated shows the percentage reduction required in the current S02 emission!
from the scrubbed unit. For the most prevalent cases, in which existing FGD syster
S02 emissions are between 0.9 and 1.2 lbs/mmBtu, the additional S02 emission reductior
required is typically less than 20 percent, even when none of the original exces:
allowances shown in Table 2 are considered.
Effectiveness of Overscrubbinq. Evaluation of the technical feasibility o1
overscrubbing an existing FGD system to provide an allowance bank for future capacity
2-111
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addition must include an assessment of the relative benefit to be obtained from
overscrubbing. As shown in Tables 3 and 4, it will be relatively easier and more
effective to apply the overscrubbing scenario at a unit with a current emission rate
close to 1.2 lbs/mmBtu than at one with a significantly lower emission limit.
Another factor which influences the effectiveness of overscrubbing is the physical
design of the FGD system with regard to bypass. Many of the first generation utility
FGD systems in the U.S. were not designed to scrub 100% of the flue gas produced by
the steam generator. Typically, these systems were designed to bypass 15% to 25% or
more of the flue gas, either to provide reheat for stack plume dispersion or simply
to provide a more economical design in those cases in which high system removal
efficiency was not required to meet an emission limit of 1.2 lbs/mmBtu. This design
feature has a significant bearing on the effectiveness of overscrubbing. Table 5
provides a comparison of the effectiveness of overscrubbing as a function of the
percentage of the total flue gas flow which must be bypassed due to the FGD system
design. Although the increase in absorber removal efficiency from 80% to 90% or from
90% to 95% represents a 50% reduction in S02 emissions leaving the absorber, the
bypass significantly reduces the effectiveness of overscrubbing. Obviously, it is
preferable to apply the overscrubbing scenario at an FGD system which has the
capability to scrub 100% of the flue gas generated by the unit. However, comparison
to Tables 3 and 4 shows that for units with an emission rate of 0.9 lb/mmBtu or
greater, even with a 40% bypass, the net reduction in S02 emissions resulting from
increasing absorber efficiency from 80% to 90% is still adequate to create an
allowance bank sufficient for a new unit of identical capacity.
Operational Impacts. When using overscrubbing at an existing FGD system as a strategy
for allowance banking, a utility must consider the impacts on operation of the FGD
system. Removing greater quantities of S02 than that for which the system was
originally designed will tax the capabilities of component equipment in the reagent
preparation and waste handling subsystems. In general, the operational impacts of
overscrubbing will be directly related to the percentage change in the mass rate of
S02 removal. Table 6 illustrates the change in S02 removal on a mass rate basis (e.g.
tons/hr) due to various degrees of overscrubbing as a function of the initial system
S02 removal efficiency.
The data shows that the lower the initial system S02 removal efficiency is, the
greater the operational impact of overscrubbing will be. However, in all but a few
of the cases evaluated, the percentage increase in the mass rate of S02 removal is 10%
or less. Especially for FGD systems with original design removal efficiencies of 80%
2-112
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to 90%, the operational impact of overscrubbing is relatively small. Th<
corresponding increase in operating requirements for equipment such as thickeners,
pumps and piping systems should probably be within the original design margins. Foi
equipment which is normally operated on a batch basis, such as ball mills and vacuur
filters, the additional throughput required each day can be handled by increasing th<
equipment run time.
OPTIONS AVAILABLE FOR OVERSCRUBBING
In order to improve the removal efficiency performance of an FGD system it i:
necessary either to increase the percentage of total flue gas treated by decreasing
the bypass flow or to improve the efficiency of the absorber tower.
Operation With Reduced Bypass
Some existing FGD systems were originally designed with the capability to treat 10(
percent of the flue gas but currently utilize partial bypass to minimize operating
costs, including costs for operating stack gas reheat systems. For these system:
there will be an economic tradeoff between the benefits of increased system S0;
removal for allowance banking purposes and the costs of operating with less bypass
available for reheat or the costs of conversion to wet stack operation.
For systems originally designed to treat less than 100% of the flue gas it may b«
possible to increase the flow through the absorbers somewhat. The extent to whid
this technique can be used will be limited by the need to maintain bypass for stacl
gas reheat and by concerns with the adverse consequences of increasing the flue ga<
flow through the absorber towers to levels not anticipated in the initial design.
These consequences include increased mist carryover, increased absorber pressure drop,
and decreased absorber efficiency due to reduction in operating liquid-to-gas ratic
(L/G).
Improving Absorber Tower Efficiency
Depending upon the degree of improvement required in absorber tower efficiency, th«
following techniques, or combinations thereof, are available for implementation. All
of these techniques act to improve S02 removal efficiency of the absorber tower by on«
or more of the following basic mechanisms:
• Increasing the mass transfer area at the gas/liquid interface.
• Improving the extent of contact between the gas and the liquid.
• Enhancing the liquid phase alkalinity.
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Operational Changes. Some improvement in absorber performance can be attained simplj
by changing the way the absorber is operated and controlled. Examples of this are:
• Increasing the reaction tank pH control setpoint.
• Increasing the reaction tank density control setpoint.
• Operating all available recycle spray pumps, including spares.
Mechanical Modifications. Physical changes to the design of the absorber tower car
provide significant performance improvement. Alternatives include:
• Installing additional levels of sprays, and pumps to serve them.
• Installing internal contacting devices, such as perforated trays.
• Boosting pump flows by increasing operating speed.
• Changing out spray nozzles to increase flow and optimize spray
droplet size and surface area.
Chemical Additives. Certain chemicals are known to have the capability to improve th(
removal efficiency of wet lime or limestone S02 absorbers when added to the
recirculating slurry.
• Soluble alkali additives, including sodium and magnesium compounds.
• Organic acids.
Performance Improvement Comparison
To compare the relative capabilities for absorber efficiency improvement of some ol
the alternatives listed above, we reviewed the results of parametric testing conductec
at the EPA Alkali Scrubbing Test Facility. A correlation equation for the S02 removal
performance of a wet limestone spray tower absorber was used to generate the curve;
shown in Figure 1. The base case spray tower operating conditions included a L/C
ratio of 80 gal/kacf, a recycle slurry pH of 5.7, and an adipic acid concentration ol
zero. Each variable was then increased from the baseline condition while the other
two were held constant at the baseline value. The range of variation considered for
each parameter was:
1. Addition of adipic acid to the recycle slurry at concentrations
from zero up to 1000 ppm.
2. Increasing the L/G ratio by 50 percent, from 80 to 120 gal/kacf.
3. Increasing the recycle slurry pH from 5.7 to 5.9.
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These ranges are considered to be representative of the modifications which would bi
considered for a full-scale operating FGD system.
The results of the performance improvement comparison, as shown on Figure 1, indicati
that the addition of adipic acid at a concentration of 1000 ppm was predicted t<
result in a 54.5% reduction in the baseline S02 emissions. The increase in L/G ratii
to 120 gal/kacf was predicted to provide a reduction of 42.1%. The increase in pH ti
5.9 resulted in a predicted reduction of 28.2% when compared to emission:
corresponding to the baseline performance. Thus, based on the data presented ii
Tables 3, 4, and 6, any of these three alternatives could be used at an existing uni'
equipped with a wet limestone FGD system to provide the degree of overscrubbini
necessary to create an unused allowance bank adequate for a new unit of the sami
capacity.
ORGANIC ACID ADDITIVES FOR OVERSCRUBBING AT EXISTING FGD SYSTEMS
We have shown that several technically feasible alternatives are available foi
overscrubbing existing wet limestone FGD systems to the extent necessary for allowanci
banking in association with future capacity planning. One of these alternatives, thi
use of organic acid additives, has a number of advantages over the others, and appear:
to be a candidate for widespread application.
Industry Experience
There is now more than a decade of full-scale commercial experience with the use o
organic acid additives for improvement in the performance of wet limestone FGI
systems. Organic acid additives which have been demonstrated at full scale includi
adipic acid, formic acid, sodium formate, and "dibasic acid" (a waste acid mixturi
which is a by-product of adipic acid production). Although in many cases the use o'
organic acid additives has been initiated to resolve performance shortfalls relativi
to contract guarantees, the experience gained has shown that dramatic improvements ii
removal efficiency performance can also be realized in FGD systems which are currently
meeting their emission limitations.
Existing data from testing and full-scale operation of organic-acid promoted we'
limestone FGD systems demonstrates that, on wel 1-designed systems, organic aci<
additives at concentrations below 1000 ppm in the recirculating slurry can achievi
significant performance improvements. As shown in Figure 1, starting from a baselim
of 80% removal efficiency, performance could be increased to 90% or more. Whei
starting from an unpromoted baseline performance of 90%, improvement to 95% i:
achievable. Most existing wet limestone FGD systems in the U.S. have absorber:
2-115
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designed for removal efficiencies between 80% and 90%. Therefore the potential exists
for the use of the overscrubbing scenario based on organic acid additives at
approximately 50 existing units.
The degree of performance improvement possible may vary based on the specific FGD
system design or the operating conditions at a given plant. For example, organic acid
additives may not be effective in low sulfur coal applications in which the
performance of the S02 absorber is likely to be gas film limited. In these cases, the
capability for achievement of the required performance improvement can be predicted
through the use of currently available FGD performance models. If necessary, the
expected performance improvement can be positively verified by a short-term organic
acid addition test of the operating FGD system.
Advantages Over Other Alternatives
As noted above, the addition of organic acid additives may not be a viable alternative
for overscrubbing at an existing wet limestone FGD system in every case. However, for
those cases in which it is, it has a number of important advantages over the other
alternatives. These comparative advantages are indicated in Table 7. The principal
advantages of organic acid addition as a technique for overscrubbing wet limestone FGD
systems are that it can produce significant increases in removal efficiency without
affecting either power consumption or absorber pressure drop and that it can do so
without requiring major capital expenditures.
By comparison, as shown in Figure 1, increasing the pH of the recycle slurry can also
produce improvement in removal efficiency, and this can be done with no capital
expense. However, operating at elevated pH setpoints typically is associated with
reduced reagent utilization, resulting in pluggage and scaling within the absorber
tower, especially in the mist eliminator section. By contrast, organic acid addition
typically can allow operation at lower than normal pH setpoints, promoting improved
reagent utilization and reduced potential for scaling. This improved reagent
utilization is important in reducing the impact of the overscrubbing scenario on the
reagent preparation and feed systems.
AVAILABILITY OF ORGANIC ACID ADDITIVES FOR FGD USE
Background and History
Adipic Acid. Initial commercialization of the use of organic acid additives for
performance improvement in wet limestone FGD systems in the U.S. was based on the use
of adipic acid. However, adipic acid was almost immediately supplanted by dibasic
2-116
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acid (DBA) as the FGD performance improvement additive of choice. DBA is preferre
for FGD use due to its significantly lower cost, typically about one-third that o
adipic acid. Several U.S. FGD systems currently use periodic addition of smal
quantities of adipic acid for short term performance enhancement during critica
periods such as episodes of unusually high coal sulfur content.
Adipic acid is used in the production of nylon, and the increasing demand worldwid
for products made from nylon fibers has resulted in steady growth in adipic aci
production. In the U.S., adipic acid (and therefore DBA as well) is produced at tw
facilities in Texas and at one in Florida. In Canada, there is an adipic aci
production facility in eastern Ontario.
Dibasic Acid (DBA). Today, DBA is in routine use at about 10 wet limestone FG
systems in the U.S. DBA is a mixture of glutaric, adipic and succinic acids which i
formed as an impure liquid byproduct during the production of adipic acid. As a wast
acid mixture, DBA has limited potential for commercial use, and disposal of th
mixture by incineration and other means has been commonly practiced in the adipic aci
industry. Additional processing of DBA can convert it to dibasic esters (DBE) whic
have greater commercial value than DBA, but not all of the adipic acid productio
facilities currently have the capability to produce DBE. Increasing restrictions o
available disposal methods, along with market conditions, has resulted in the adipi
acid producers either implementing or contemplating increased conversion of DBA t
DBE.
Sodium Formate. In the late 1980s the trend toward emphasis on conversion of DBA t
DBE resulted in some concern about the future availability and cost of DBA for use a
an additive for FGD performance improvement, and the Electric Power Research Institut
(EPRI) was involved in testing of sodium formate as a possible substitute for DBA i
FGD applications. At least one FGD system in the U.S. now routinely uses sodiui
formate as an additive to improve S02 removal performance. Sodium formate is
neutral salt of formic acid, the simplest of the organic (carboxylic) acids which hav
been used in FGD systems.
Sodium formate is produced as a pure coproduct in the production of pentaerythritol
which is used in the formulation of synthetic lubricants, notably jet engine turbin
lubricants. In the U.S., pentaerythritol (and sodium formate) is produced at thre
plants, two in Ohio and one in Missouri.
2-117
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Formic Acid. Formic acid has not been routinely used in FGD systems in the U.S., and
domestic production of formic acid is limited. Most formic acid used in the U.S. is
imported from Europe.
Current Availability Situation
Table 8 presents the results of an assessment of the current availability of adipic
acid and DBA in the U.S. The data presented are approximations based upon information
obtained from industry sources. U.S. production data for sodium formate and formic
acid were not available. According to this assessment there is currently about 25
million lbs/yr of additional DBA available for use in FGD systems beyond the current
usage rate.
Future Considerations
The future availability of organic acids for use in FGD applications will depend or
a number of factors. Some of the factors which would result in greater availability
of these additives are:
• Increasing production of adipic acid worldwide, resulting in
reduced exports from U.S. production. Industry sources estimate
that current U.S. exports of adipic acid are approximately 100
million lbs/yr. These may become available for domestic use.
• Greater use of alternatives to DBA for FGD use. For example,
expanded utilization of sodium formate.
• Increasing availability to the U.S. market of DBA and adipic acid
produced in Canada. Current Canadian production of adipic acid
is estimated to be 300 million lbs/yr, and this is not included
in the data shown in Table 8. The owner of the Canadian adipic
acid production facility, which also owns two of the three U.S.
plants, has indicated a renewed commitment to serve the utility
FGD industry and to meet the demand for organic acid additives.
• Continuation of the trend toward fuel switching as a favored acid
rain compliance strategy by U.S. utilities. This will decrease
the potential demand for additives to be used in retrofit FGD
systems.
Factors which will tend to result in a decrease in the availability of organic acid
additives for FGD use include:
• Increasing conversion of DBA to DBE.
• Possible future utilization of organic acid additives by retrofit
FGD systems installed for compliance with Phase I. Several of
the recent specifications for Phase I FGD retrofits have included
a request for alternate bids based on the use of organic acid
promotion.
2-118
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The net result of these competing factors is expected to be that an adequate suppl
of organic acids will be available for use in overscrubbing existing FGD systems i
the year 2000 and beyond.
With regard to DBA specifically, based upon information obtained in discussions wit
industry sources, the future availability of this most popular organic acid additiv
for FGD systems is anticipated to amount to 25 to 40 million lbs/yr over and abov
that which is currently being used for FGD applications.
Assuming a DBA consumption rate of 15 pounds per ton of S02 removed and an increas
in the mass rate of S02 removal of 10 percent at each existing FGD system which begin
to use it, the DBA consumption per incremental ton of S02 removed would be 165 pounds
This means that if all the projected DBA available for use as described above wer
used in existing FGD systems, the supply would be adequate to scrub an additiona
150,000 to 250,000 tons of S02 annually. Based on allowance requirements for ne;
units as shown in Table 1, this could create an allowance bank sufficient for th
addition of 100 new units of 300 MW capacity each.
Even if the available supply of DBA were exhausted, there will still be th<
possibility of using adipic acid, sodium formate or formic acid as an organic aci
promoting agent.
CONCLUSIONS
The allowance banking scenario in which overscrubbing at existing units with FGI
systems is employed as a source of Phase II allowances appears to be both technical 1.
and economically feasible. It has been shown that this scenario can easily create .
bank of unused allowances adequate to provide the necessary allowances for additioi
of a new unit of the same capacity as the existing scrubbed unit. Of all th<
alternatives available for accomplishing the necessary overscrubbing, the use o
organic acid additives is preferred from the standpoint of avoiding large capita
expenditures and significant operational impacts on the existing FGD absorbers.
A survey of the organic acid industry indicates that there should be adequate supplie:
of DBA and adipic acid for use in FGD systems in the future. Utilities which an
considering the use of the overscrubbing scenario may wish to contact the organic acii
suppliers to confirm the availability and price of the necessary additives. In somi
cases, a test to verify the performance improvement attainable at a given FGD systei
may be required.
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L/G RATIO
RECYCLE pH
ADIPIC
95
-90
>T 90-
O
z
UJ
o
LL
LL
-85
85-
UJ
_l
<
>
O
2
-80
80-
LLI
DC
75
0
500
ADIPIC CONCENTRATION, ppm
1000
80
100
UG RATIO, gal/kacf
120
5.7
5.8
RECYCLE SLURRY pH
5.9
Figure 1. Comparison of Alternatives for Efficiency Improvement
2-120
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Table 1
EXAMPLE NEW UNIT
Assumptions
Unit Size = 300 MW
Heat Rate = 10,000 Btu/kWh
Capacity Factor = 65%
S02 Removal = 95%
Allowances Required
Fuel S02 (lbs/mmBtu): 2 3 4 5
Emissions (lb/mmBtu): 0.10 0.15 0.20 0.25
(tons/yr): 854 1281 1708 2135
Table 2
EXISTING SCRUBBED UNIT
ALLOWANCE BANKING POTENTIAL
Assumptions
Unit Size = 300 MW
Heat Rate = 10,000 Btu/kWh
Capacity Factor = 65% (same as in 1985-1987)
Emission rate remains consistent.
Basic Allowances reduced by 2.8%.
Results
Actual Emissions Phase II Allowances
lb/mmBtu
tons/vr
Total
Excess
<1.2
10,249
11,955
1706
0.9
7,687
8,966
1279
0.6
5,125
5,977
852
0.3
2,562
2,989
427
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Table 3
EXISTING UNIT OVERSCRUBBING TO PROVIDE ALLOWANCES
FOR IDENTICAL SIZE NEW UNIT - CASE 1 (EQUATION 2)
Percentage Reduction Required
Existing Unit New Unit Emissions (Ib/mmBtu)
Emissions
(lbs/mmBtu)
0.10
0.15
0.20
0.25
<1.2
0.0
0.0
0.0
4.2
0.9
0.0
0.0
5.6
11.1
0.6
0.0
8.4
16.7
25.0
0.3
16.7
33.4
50.0
66.7
Table 4
EXISTING UNIT OVERSCRUBBING TO PROVIDE ALLOWANCES
FOR IDENTICAL SIZE NEW UNIT - CASE 2 (EQUATION 3)
Percentage Reduction Required
Existing Unit New Unit Emissions (Ib/mmBtu)
Emi ssions
(lbs/mmBtu)
0.10
0.15
0.20
0.25
<1.2
7.1
10.7
14.3
17.9
0.9
9.5
14.3
19.0
23.8
0.6
14.3
21.4
28.6
35.7
0.3
28.6
42.9
57.1
71.4
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Table 5
INFLUENCE OF BYPASS DESIGN
ON EFFECTIVENESS OF OVERSCRUBBING
Removal Efficiency Additional
Design Absorber System S02 Reduction
Bypass
Initi al
Final
Initial
Final
Achieved
0%
80%
90%
80%
90%
50%
0%
90%
95%
90%
95%
50%
20%
80%
90%
64%
72%
22%
20%
90%
95%
72%
76%
14%
40%
80%
90%
48%
54%
12%
40%
90%
95%
54%
57%
7%
Table 6
OPERATIONAL IMPACTS OF OVERSCRUBBING
Initial System
SO-, Removal, %
90
90
80
80
70
70
60
60
Required Reduction
in SO-, Emissions
10%
30%
10%
30%
10%
30%
10%
30%
Final System
SO-, Removal, %
91
93
82
86
73
79
64
72
Change in
Tons/hr S02
Removed
+1.1%
+3.3%
+2.5%
+7.5%
+4.3%
+12.9%
+6.7%
+20.0%
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Table 7
ADVANTAGES OF ORGANIC ACID ADDITIVES
WHEN COMPARED TO OTHER PERFORMANCE IMPROVEMENT ALTERNATIVES
ro
I
t—1
4^
Absorber Performance
Improvement Alternatives
Operational Changes:
Increased pH
Increased density
Operate spare pumps
Mechanical Modifications:
Add spray levels & pumps
Install sieve tray
Increase pump speed
Changeout spray nozzles
Greater
Efficiency
Increase
X
X
X
X
X
X
X
Lower
Capital
Cost
X
X
Lower
Power
Consumption
X
X
X
X
X
No
Change
in aP
X
X
X
Easier
to Test
X
X
X
X
Unaffected
Bv High CI"
Chemical Additives:
Magnesium compounds
Sodium compounds
X
X
-------
Table 8
ORGANIC ACID AVAILABILITY FOR FGD USE:
CURRENT SITUATION
Product
Adipic Acid
DBA
Approximate
U.S. Production
Comments
1,800
X
106
lbs/yr
Negligible FGD use
90
X
106
lbs/yr
Total
50
X
106
lbs/yr
Converted to DBE .
40
X
106
lbs/yr
Available for FGD use
<15
X
106
lbs/yr
Actual FGD use
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A BRIEFING PAPER FOR THE STATUS OF THE
FLUE GAS DESULFURIZATION SYSTEM AT
INDIANAPOLIS POWER & LIGHT COMPANY
PETERSBURG STATION UNITS 1 AND 2
BY
C.K. Rutledge - Project Engineer
S.R. Wolsiffer - Lead Engineer
Indianapolis Power & Light Company
S.M. Gray - FGD Process Engineer
Radian Corporation
J.E. Martin - Lead Mechanical Engineer
C.P. Wedig - Lead FGD Process Engineer
Stone & Webster Engineering Corporation
Preceding page blank
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Intentionally Blank Page
2-128
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A BRIEFING PAPER CONCERNING THE STATUS OF THE
FLUE GAS DESULFURIZATION SYSTEM AT
INDIANAPOLIS POWER & LIGHT COMPANY
PETERSBURG STATION UNITS 1 AND 2
ABSTRACT
This paper presents a brief description of the status of the retrofit wet limestone flue gas desulfurization
system project at Indianapolis Power & Light Company (IPL) Petersburg Units 1 and 2. This project was
initiated by IPL in response to the Clean Air Act of 1990 and is intended to treat the flue gas from two base
load units with a combined capacity of approximately 700 MW gross electrical output.
Preceding page blank
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A BRIEFING PAPER CONCERNING THE STATUS OF THE
FLUE GAS DESULFURIZATION SYSTEM AT
INDIANAPOLIS POWER & LIGHT COMPANY
PETERSBURG STATION UNITS 1 AND 2
ORGANIZATION OF PROJECT
IPL is the owner and operator of the Petersburg Station located in southwestern Indiana. Stone & Webster
Engineering Corporation (S&W) is the Engineer and Constructor for the project. Radian Corporation is a
sub-contractor to S&W in the area of FGD process. The project is organized as a team with each company
providing services. The suppliers of the FGD system and new stack are scheduled to be selected and join
the team in December 1991 and early 1992 respectively. Other material suppliers and field contractors will
be selected in 1992.
MILESTONE SCHEDULE OF THE PROJECT
As a result of competitive bidding, S&W was awarded the engineering and construction contract for this
project in January 1991. During the first few months of the project, the IPL/S&W/RADIAN project team
conducted studies to select the FGD process type, interviewed potential scrubber vendors, performed
conceptual engineering, and in June 1991 issued a specification to five scrubber vendors for competitive
bidding. In September 1991, proposals were received from each of the scrubber vendors and the compari-
son of bids began. Some of the critical path milestones of the project are as follows:
- Scrubber Vendor Selected
December 1991
- New Stack Supplier Selected
Spring 1992
- S&W Construction Mobilization in Field
Spring 1992
- S&W Completes Absorber Area Foundations
Early 1993
- Absorber Area Released to Scrubber Vendor
Spring 1993
- Unit Tie Ins
Spring 1994
- FGDS Owner's Acceptance Test No. 1
Fall 1994
- FGDS Operation
Winter 1994
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Figure 1 - Petersburg Station
DESCRIPTION OF PETERSBURG STATION
The Petersburg Generating Station is located in Pike County, Indiana, about three miles north of Petersburg,
Indiana (Figure 1). The station consists of four coal fired units with ratings of Unit 1 (239), Unit 2 (418),
Unit 3 (510), and Unit 4 (515) net MW. Units 1 and 2 will be retrofit with FGDS as a result of this
project. Units 3 and 4 presently operate with wet limestone FGDS included as part of the original unit
installation. A major challenge to the project team is to fit a high-efficiency limestone FGD system into a
tight site surrounded by the river and operating plant equipment.
DESCRIPTION OF THE PETERSBURG UNITS 1 AND 2 FGDS PROJECT
The Units 1 and 2 FGD process will be forced oxidized wet limestone producing gypsum cake and employ a
new wet stack. Two full sized absorber modules are planned, one for each unit. There is no real estate
available for a spare absorber. Although each unit will have a single absorber, reliability will be built into th
system through spare major components such as recycled pumps and controls. In addition, reliability will be
maintained by reducing or eliminating certain components such as recycle pump discharge valves and
absorber outlet dampers.
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The new flue gas handling and absorber systems will be located on the south-west side of the station. Unit 1
will employ a single booster fan which will pressurize the Unit 1 absorber. Unit 2 will employ two booster
fans which will pressurize it's absorber. The scrubbed gas from the absorbers will be discharged to a new
stack which will be designed with individual flues dedicated to their respective absorbers. The existing stack
and a dedicated flue of the new stack will be used for emergency bypass purposes and to alleviate any
additional risk of boiler implosion to furnaces that were originally designed to operate pressurized. The
design inlet flue gas of the individual absorbers is approximately 1,200,000 and 2,240,000 acfm at 340
degrees F for Units 1 and 2 respectively. The absorbers will be designed for high reliability and will be
capable of approximately 95 percent sulfur dioxide removal for a wide range of sulfur coals. Bleed slurry
from the absorber reaction tanks will be fed to dedicated tanks and pumped approximately 4500 feet to the
solids dewatering and handling area.
New primary and secondary solids dewatering equipment will be located in a common area on the east side
of the station near the existing Unit 3 and 4 solids handling systems. The resulting gypsum cake will be
handled by conveyors. The base case evaluation of scrubber vendor proposals is being analyzed assuming the
production of commercial grade gypsum suitable for use in the local wallboard industry.
The new limestone handling and slurry preparation area will be common to both Units 1 and 2 and will be
located on the northwest side of the station. Limestone of 3/4 inch by 1/4 inch will be delivered by truck,
stored outside, reclaimed, belt conveyed to three limestone silos, ground by three 50-percent wet ball mill
circuits to produce 90 percent through 325 mesh particles. The resultant slurry will be stored in two
limestone slurry storage tanks and circulated to the FGD absorbers.
Unit 1 and 2 new distributed control system (DCS) consoles will be located in the existing FGDS power and
control building which presently services the Units 3 and 4 scrubbers. This will result in a centralized control
area for all the station's FGD systems.
USE OF EPRI/EPA/DOE PROGRAMS IN THIS PROJECT
The project team used the EPRI-developed FGDPRISM ver. 1.1 computer program, as one of several tools,
to assist in determining the desired internal absorber configuration. S&W developed the design inlet flue gas
properties and Radian developed recommended liquid to gas ratios, spray level spacings, nozzle parameters,
and other process design criteria. The FGDPRISM program was used in the bid specification and comparison
of bids phases of this project.
Results of an EPRI/IPL sponsored limestone particle size analyzer test at Petersburg Unit 3 have been used
on the Unit 1 and 2 FGDS project. The Unit 1 and 2 limestone slurry preparation system will employ an
on-line limestone grind analyzer to determine the percent by weight limestone which passes through 325
mesh.
In addition to the aforementioned programs, other EPRI/EPA/DOE-sponsored FGD programs and reports
have been used to assist our project.
SUMMARY
The Petersburg Units 1 and 2 retrofit wet limestone/gypsum FGDS project is proceeding on schedule and is
planned to be operational by the end of 1994.
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Evaluation of SO2 Control Compliance Strategies at
Virginia Power
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EVALUATION OF S02 COMPLIANCE STRATEGIES
AT
VIRGINIA POWER
J.V. Presley
H. Tomlinson, P.E.
R.H. Ulmer, P.E.
Virginia Power
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, Va. 23060
ABSTRACT
This paper will address the process undertaken by Virginia Power to assess SOj
control strategies available for complying with the Revised Clean Air Act. In
April 1990, in anticipation of the passage of an amended Clean Air Act, Virginia
Power assembled a task force of personnel from a wide cross section of the
company. This task force was given the responsibility of providing an assessment
of the requirements of the new legislation, evaluating compliance alternatives
and providing recommendations for implementation of the least cost alternative.
Twenty-four potential S02 compliance options were identified for evaluation for
Phase I. These options included various levels of coal switching, gas co-firing
and scrubbing. Each option was evaluated and compared to a base case which
assumed no S02 control. As a result of our evaluations, the lowest cost and
least risk approach to Phase I S02 compliance for Virginia Power appears to be
to construct a scrubber for one unit (550 MWf) at our Mt. Storm Power Station.
'receding page blank
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EVALUATION OF S02 CONTROL COMPLIANCE STRATEGIES
AT
VIRGINIA POWER
INTRODUCTION
After ten years in the making, the Clean Air Act Amendments (CAAA) of 1990 were
signed into law on November 15, 1990. Although many difficult air quality issues
are addressed by the legislation, those areas dealing with acid rain have the
most immediate and direct impact on the electric utility industry. This paper
deals with the ongoing process of evaluating and implementing S02 control options
at Virginia Power.
Virginia Power is the primary subsidiary of Dominion Resources, Inc. Our
electrical service territory includes the eastern 2/3 of the state of Virginia
and the northeastern corner of North Carolina, where we operate under the name
of North Carolina Power.
Virginia Power's rated net electrical output of 12,255 is produced by one of the
most diversified generation networks in the nation. Baseload generation consists
of 4326 MW of pulverized coal generation and 3382 MW of nuclear generation.
Intermediate and peaking requirements are met by 1747 MW of oil fired generation,
189 MW of combined cycle generation, 1260 MW of pumped storage generation, 1019
MW of simple cycle combustion turbines and 332 MW of conventional hydroelectric
generation.
Additionally, 900 MW of coal fired generation and 130 MW of hydro generation are
supplied under long term purchase agreements with other utilities. 1320 MW are
supplied under long term contract by Cogenerators and Independent Power
Producers.
IDENTIFICATION OF CONTROL OPTIONS
In April 1990, in anticipation of the passage of an amended Clean Air Act,
Virginia Power assembled a task force to address issues expected to result from
the legislation. This task force included representation from many areas of the
company, including environmental, engineering, operations, rates and regulation,
fuel procurement, transportation, power supply, technical assessment, planning
and financial. The purpose of the task force was to provide an assessment of the
requirements of the proposed legislation, identify and evaluate compliance
alternatives and provide recommendations for implementation of those
alternatives.
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Where feasible, the task force was to build on prior evaluations performed to
determine the potential cost impacts of previously proposed acid rain
legislation. Through earlier efforts, Virginia Power had determined that the
cost of reducing S02 emissions by scrubbing at our Mt. Storm Power Station was
less than half the cost of reducing S02 emissions at our in-system coal-fired
stations on a dollar-per-ton basis. Furthermore, space had been reserved at Mt.
Storm for the addition of scrubbers. Most of our in-system coal fired stations
are very space-limited making scrubber retrofits extremely difficult.
Shortly after the task force was organized, a subcommittee was formed to address
S02 compliance options. With the proposed legislation based on a phased
approach, Virginia Power's system was easily delineated into two categories.
Phase I compliance would require the reduction of emissions from Mt. Storm Power
Station, a station with three 550 MW units. Phase II, in addition to further
reductions at Mt. Storm, would also require S02 reductions and/or offsets for
18 in-system fossil fired units. Because of the magnitude of Phase II S02
reductions, the subcommittee eliminated any Phase II option that did not include
full scrubbing of all three Mt. Storm units.
Initial brainstorming sessions by the SOj control subcommittee identified the
following S02 reduction methods for further Phase I evaluation:
1. Blending in-system coal sulfur content down from its current 1% sulfur
average to 0.7% sulfur.
2. Blending in-system coal sulfur content down from its current 1% sulfur
average down to 0.65% sulfur by the use of "western coals".
3. Blending Mt. Storm coal sulfur content down from its current 1.8% to
1.6%.
4. Replacing current fuel oil with 0.3% sulfur fuel oil for our oil fired
units.
5. Restricting capacity factors on the Mt. Storm units.
6. Installing a 95% scrubber on one Mt. Storm unit. (90% scrubbing and
98% scrubbing were eliminated as less cost effective.)
7. Installing 50% reduction technologies such as in-duct spray drying on
two Mt. Storm units.
8. Have a third party own and operate a scrubber at Mt. Storm.
9. Gas co-firing at Mt. Storm.
Phase II options identified by the subcommittee included scrubbing all three Mt.
Storm units plus one of the following:
1. Reducing in-system coal sulfur content to 0.7%.
2. Installing in-duct spray drying technology on five units identified as
having adequate duct runs between the air preheaters and the
precipitators.
3. Installing scrubbers on the four units at the Chesapeake Energy Center.
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One option that was not included in Virginia Power's initial evaluation was the
purchase of SOz allowances. Although this innovative approach should provide
industry with the flexibility to achieve compliance at the lowest possible cost,
it was not evaluated due to the uncertainties over the cost and future structure
of the trading program that has yet to be established. A survey of other
utilities indicated that most were not including a trading option in their Phase
I S02 control strategy evaluations, but intended to continue to monitor the
development of this option as a trading program is established.
SCREENING AND COST EVALUATION
S02 compliance screening was performed for each option identified. An initial
base case was established which included no provisions or adjustments for acid
rain legislation. This work was performed by Virginia Power's System Planning
Department using PROVIEW and PROMOD computer software. The future generation and
production cost projections from the base case and control option cost
projections were input into another computer model called SEROP (S02 Emissions
Reduction Optimization Program), developed by Wisconsin Power and Light. This
work was performed by Virginia Power' s Corporate Technical Assessment Department.
Estimates of future S02 emissions under each compliance scenario were then
compared with estimates of the S02 allowances available to Virginia Power under
each phase to determine whether or not the strategy would achieve the required
S02 reductions. Non-complying options were eliminated from further
consideration.
Surviving Phase I options included:
• Blend Mt. Storm coal to 1.6% sulfur, restrict capacity factors at Mt.
Storm, burn 0.3% sulfur No. 6 oil at oil-fired units.
• Install one scrubber at Mt. Storm by 1995.
• Blend Mt. Storm coal to 1.6% sulfur for 1995-1996, install one scrubber
in 1997, co-fire Mt. Storm units with natural gas for 1995-1996.
• Install in-duct sorbent injection technology on two Mt. Storm units.
• Blend Mt. Storm coal to 1.6% sulfur, co-fire Mt. Storm units with
natural gas.
• Install one scrubber at Mt. Storm by 1997 (assuming compliance
extension granted by EPA).
All three of the Phase II options identified earlier survived the initial
compliance screening and were economically evaluated based on the first scrubber
being installed in either 1995 or 1997. After the technical screening was
completed, the economic evaluation was performed. Surviving Phase I and Phase
II options were combined and run through PROMOD and Virginia Power's corporate
financial models to determine the present value of the revenue requirements for
each strategy. A total of thirty-two Phase 1/11 combinations were actually
modeled with an additional eighteen cases estimated based on the results of the
cases modeled.
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The results of the computer models indicated the option with the least cost
present worth value involved adding one scrubber at Mt. Storm in 1997 followed
by two additional scrubbers at Mt. Storm in 2000 combined with a switch to 0.7%
sulfur coal at Virginia Power's in-system coal fired units. This strategy is
based on several key assumptions, any changes to which may dramatically alter
these results. Key assumptions include:
• The EPA will permit the first Mt. Storm scrubber to be delayed until
1997, including providing allowances for the two Mt. Storm units which
are not scrubbed in Phase I.
• The estimated cost of low sulfur coal does not change significantly
from current projections.
• Virginia Power's projected peak load growth of 2.01% does not
significantly increase.
ACTIONS TAKEN
The option of obtaining an EPA extension to install a scrubber at Mt. Storm by
1997 involves an assumption that is beyond Virginia Power's control. Therefore,
Virginia Power elected to maintain the option of installing a scrubber by 1995.
Assuming a 36 month schedule from contract award until commercial operation
requires that a scrubber contract be awarded by January 1992. To support this
schedule, Virginia Power began preparing scrubber specifications in December
1990. As a utility with no operating scrubbers, outside consulting support was
considered essential to a successful program. After careful consideration of the
capabilities of several companies, a contract was issued to the Radian
Corporation to provide review and consulting services during the preparation of
the scrubber specification. Scrubber specifications were completed and request
for proposal (RFP) documents were issued on April 30, 1991. The RFP is based on
the scrubber contractor supplying a complete scrubber installation for Mt. Storm
Unit 3. Key technical requirements for the scrubber were that it be a wet
limestone forced oxidation scrubbing system designed for 95% S02 removal. Two
fifty percent absorber vessels were required in the base bid and the waste
product is to be throw away gypsum.
The RFP also required the bidders to quote a price if the scrubber construction
is delayed for two years. The pricing was to be provided such that Virginia
Power would know the cost impact of delaying the project at any time during the
first two years of the contract. This will allow Virginia Power to make an
informed decision if a compliance extension is obtained from the EPA.
Scrubber proposals were received from 5 scrubber bidders on September 4, 1991,
and are being evaluated by Virginia Power and Radian. In the discussion of S02
control options identified for evaluation earlier in this paper, it was stated
that S02 allowance trading was not evaluated due to the uncertainties surrounding
this option. In order to quantify the cost of this option, Virginia Power
solicited to purchase S02 emissions allowances on July 3, 1991. Responses
«
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were received on September 3, 1991. Allowance bids will be reviewed in
conjunction with the scrubber bids to finalize compliance options.
SUMMARY
In early 1990, Virginia Power began the process of determining the best option
of controlling S02 emissions from its fossil fired stations in order to comply
with the 1990 Clean Air Act Amendments. This process consisted of four basic
steps. Identification of available options was the first step. Quantification
and evaluation of the cost of each option followed. The third step involves
maintaining options as long as possible, allowing additional time to gather facts
and/or confirm assumptions. The fourth step will be implementation.
Virginia Power is currently proceeding on both the third and fourth steps. It
appears likely that Phase I SOz emissions compliance will be met by scrubbing one
unit at Mt. Storm Power Station. Whether initial operation of the scrubber will
be by 1995 or 1997 depends on the timing and actions taken by the EPA.
Evaluation of options for Phase II SOz emissions compliance indicates that the
other two Mt. Storm units will be scrubbed in combination with fuel switching at
our in-system coal fired units. Final decisions concerning Phase II compliance
are not expected before 1996.
Virginia Power has utilized the expertise of many company personnel to evaluate
a variety of SO2 compliance strategies. Virginia Power has adopted a compliance
strategy which fulfills the regulatory requirements in a practical and cost
effective manner. Virginia Power will continue to use this method to evaluate
our strategy as we and our industry work to meet our environmental goals.
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Session 3A
WET FGD PROCESS IMPROVEMENTS
OVERVIEW ON THE USE OF ADDITIVES
IN WET FGD SYSTEMS
R. E. Moser
D. R. Owens
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94303
ABSTRACT
The use of performance enhancing additives in wet FGD systems has become much
more common in recent years. This paper presents an overview of how additives
have historically been used and their current status in wet FGD systems, and discusses
what functions additives may perhaps fulfill in future system designs. Characteristics
of additive use, such as concentrations required, consumption mechanisms, and the
effects of additive combinations are reviewed. The roles additives can play in
allowing much wider flexibility in operations is detailed, along with a brief discussion
of the capital and operating costs for the use of additives.
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INTRODUCTION
The use of additives in wet FGD systems is not something new. Yet, the subject of
additive use in FGD systems still seems to carry a stigma. It is not clear why this is. In
fact, it is not altogether clear what is considered to be an "additive". An "additive" is
defined in Webster as "any of various substances added to a product, process or device
to improve performance or quality." Is the lime or limestone reagent used for FGD
considered to be an additive? Probably not. The use of an alkaline reagent is inherent
to the process. How about the magnesium in magnesium-enhanced lime? Again,
since the magnesium is part of the naturally occurring reagent, nobody seems to
consider that this falls into the category of additive use. When dolomitic lime is
added to a limestone FGD system to increase SO2 removal, as a number of systems
were designed to do in the U.S. in the 70s, is that not clearly the use of an additive?
Somehow that managed to avoid any stigma. Yet when the use of organic acids in
enhancing the SO2 removal efficiency of an FGD system comes up, negative images
of magic elixirs and snake-oil salesmen seem to abound.
Would air sparged into the reaction tank for forced oxidation not be an additive? It
certainly has never had that connotation. Yet the use of an oxidation inhibitor, such
as thiosulfate, is considered to be an additive. Flocculant addition to thickeners to
assist in solids settling or liquor clarification is fairly common in wet FGD systems.
Biocides are periodically added to wet FGD systems to combat anaerobic bacteria and
the generation of hydrogen sulfide gases in thickeners and sumps. Yet both
flocculants and biocides have managed to avoid any stigma.
Perhaps the negativity stems from the interpretation that an FGD system is somehow
deficient in its design if "additives" are required to make it work properly. This is not
the case for gypsum scale control. Gypsum scaling is an artifact of not properly
controlling oxidation chemistry or crystal growth characteristics. It has very little to
do with any design deficiency. Today, many wet FGD systems operate in the U.S.
wherein the natural oxidation rate is very successfully inhibited through the use of
thiosulfate to the point where gypsum scaling does not occur. The use of emulsified
sulfur to produce thiosulfate in situ has made this option very economical.
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Which brings us to the crux of the negative connotation of additives: the fix of
having to add an organic acid so that the FGD system can remove enough SO2 to
meet emission requirements. While it is unfortunately true that a number of FGD
systems were unable to remove adequate SO2 as originally designed to be operated,
this situation has provided the opportunity to better understand the dynamics of the
relationship between gas-side and liquid-side mass transfer. It is this relationship
which ultimately limits the SO2 removal efficiency of an FGD system. If the system
can achieve higher removal efficiency with the addition of a buffering agent such as
an organic acid, then the problem is not a function of gas/liquid contact afforded by
the design, it is a function of the liquid phase chemistry. There are about a dozen
FGD systems in the U.S. which currently use organic acids for SO2 removal
enhancement. In none of these cases was the system, in fact, designed with the use of
additives included. Thus the genesis of the "additives" stigma.
It is important to move beyond any negativity associated with additive use and begin
to objectively look at the enormous benefits possible associated with understanding
and improving the design and operation of FGD systems. Additives are not magic
potions peddled by snake-oil salesmen and they do not work through any
supernatural mechanism. They work because they provide us tools to integrate and
manipulate the process chemistry such that FGD systems can be designed at lower
capital cost to operate less expensively with higher removal efficiency, higher
reliability, and with much greater operating flexibility.
CURRENT STATUS
Additives have been used commonly in two primary applications in U.S. FGD
systems in the past few years: for SO2 enhancement and for gypsum scale control.
Additives have also been shown to improve limestone dissolution under certain
circumstances and their benefit in improving calcium sulfite solids quality has been
documented. Additional applications for additives which are being researched and
which may well become common in the next decade involve advances in improving
calcium sulfite and gypsum solids quality, in improving oxidation efficiency, and in
understanding the effects of multiple additive formulations.
SQ2 Removal Enhancement
Both organic and inorganic compounds are being used in the U.S. to improve SO2
removal efficiency. As SO2 is absorbed by the scrubbing liquor, acid is formed which
must be continuously neutralized for the absorption process to continue unhindered.
The rate at which this neutralization occurs significantly affects how much and how
rapidly SO2 can be absorbed into the liquor. Sodium- and magnesium-based processes
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contain an ample supply of liquid-phase alkalinity in the form of sulfite ion. As long
as there is an abundance of sulfite ion in solution, the sulfite/bisulfite equilibrium
reactions buffer the pH of the scrubbing liquor such that the neutralization of
absorbed SO2 does not limit the rate at which SO2 can be absorbed from the gas.
These processes are said to be "gas-phase limited" because the limitation in how
much SO2 can be removed revolves strictly around how well the gas and liquid
contact each other and is largely a function of the total droplet surface area. L/Gs for
these systems, even for high-sulfur coal applications, are frequently as low as 20 to 30.
With lime or limestone FGD processes, however, there is very little liquid-phase
alkalinity. The primary source of alkalinity is in the solid phase, as calcium
hydroxide or calcium carbonate, respectively. The rate at which the solid phase
dissolves, therefore, largely determines how effectively the absorbed SO2 can be
neutralized, and becomes the rate-limiting step. Thus, these processes are said to be
"liquid-phase limited". Now the design L/G is not nearly as much a factor of total
droplet surface area, but rather is constrained more by the bulk of liquor available to
provide the meager liquid-phase alkalinity and the amount of solid-phase alkalinity
present and the residence time in the absorber. Since lime is much more soluble than
limestone, lime-based FGD systems require a lower design L/G. Also, because lime is
more soluble, the system can be operated at a higher pH, where the buffering effects of
the small amounts of sulfite present are more effective. Further, in the U.S., nearly
all of the operating lime systems use naturally occurring magnesium-enhanced lime
as the reagent and, in a very real sense, contain their own built-in additive. Since the
magnesium allows the liquor to hold a larger reservoir of liquid-phase alkalinity in
the form of sulfite ions, the design L/G can be further reduced.
Limestone systems present an even greater challenge in that limestone is much less
soluble. In an unassisted limestone FGD process, the rate at which limestone
dissolves in the absorber and the amount of limestone present per unit volume of
recirculating slurry, called the limestone loading, become very important factors in
the absorber design. The design L/G must be higher and is now much more critically
related to how much sulfur must be removed and neutralized in each pass of liquid
through the absorber. It is not at all uncommon for recirculated liquor which enters
the absorber at pH 5.5 to leave the absorber at pH 3.5. As the pH is dropping, the SO2
vapor pressure over the liquor is increasing, substantially reducing the driving force
for SO2 to be absorbed from the gas. Therefore, this pH depression must be offset by
the combined effects of liquor volume and limestone dissolution in the absorber.
Inorganic species such as magnesium or sodium which enter the FGD system with
the make-up water or are added as additives (as dolomitic lime or soda ash) can assist
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in SO2 removal in limestone FGD systems by holding alkaline sulfite in solution and
diminishing the requirement for solid-phase alkalinity. Organic acids assist in SO2
removal because they are effective in buffering the pH of the bulk liquor by
undergoing a series of equilibrium reactions among the various species. Dibasic acid
(DBA), a mixture of adipic, glutaric and succinic acids, is quite effective due to the
large combinations of dissociated species which undergo these buffering reactions.
Each of these acids added separately is capable of doing a reasonable job of buffering
the liquor pH. Formic, citric, and acetic acids have, likewise, been demonstrated to do
a reasonable job. The effectiveness of each of these species in buffering is dependent
upon the pH at which the various equilibrium reactions have the maximum
convertability of species. The closer this optimum pH is to the operating pH at which
the FGD system liquor is to be maintained, the more effective the buffering capacity of
the organic acid for FGD. The significance of this is that the SO2 removal is now not
nearly as dependent on the availability and dissolution rate of solid-phase alkalinity.
With this requirement altered, the L/G does not have to be as large. The higher the
concentration of the organic acid, the greater the buffering capability, the more the
SO2 removal is improved. While this is extremely fortuitous, it is not magic!
Gypsum Scale Reduction
Gypsum scaling has probably been the single largest cause of absorber down time in
U.S. FGD applications. With our current knowledge of the chemistry which causes
gypsum scaling, however, there is no reason for there ever to be additional absorber
down time attributed to gypsum scaling. When the liquid-phase chemistry becomes
supersaturated with respect to calcium sulfate (gypsum), precipitation must occur.
Figure 1 illustrates the two regimes under which gypsum precipitation can occur:
through crystal growth or through nucleation. The gypsum relative saturation
within the liquor determines which precipitation mechanism will occur. At relative
saturations above 1.3 to 1.4 nucleation dominates, causing uncontrolled formation of
small nuclei, resulting in scaling on whatever surfaces are available. When the
amount of gypsum seed crystal surface area is high, the gypsum relative saturation is
reduced and crystal growth on existing crystals preferentially occurs. The primary way
gypsum scaling was combatted prior to the mid-80s in the U.S. was through forced-
oxidation chemistry. In this case, the "additive" is air sparged into the reaction tank
to oxidize all, or very nearly all, of the solids to gypsum. As long as adequate
amounts of gypsum solids are maintained in the slurry, crystal growth dominates and
scaling does not occur.
There are several techniques involving additives which have been successfully used
to combat gypsum scaling. The most common and effective way used has been to
inhibit the natural oxidation of sulfite to sulfate using thiosulfate. Since up to 15
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mole percent sulfate is included as a solid solution in the calcium sulfite hemihydrate
crystal lattice, inhibition of sulfite oxidation to a level below 15% eliminates
supersaturation in the liquid phase and the formation of gypsum solids Thiosulfate
inhibits sulfite oxidation because it interferes with the propagation of the free-radical
oxidation reactions by itself reacting with the sulfite free radicals. The use of
emulsified sulfur to create thiosulfate in situ by reaction with sulfite has reduced the
cost of this treatment by about 80%, making it an extremely economical way to
eliminate gypsum scaling in an FGD system. Emulsified sulfur is currently being
added to perhaps two dozen U.S. FGD systems with excellent results. A refinement
on this technique is the combined use of a chelating agent, such as EDTA, in very
small doses, with thiosulfate.1 The sulfite free radicals with which the thiosulfate
reacts are thought to be formed by the reaction of trace metals with sulfite. The EDTA
ties up the trace metals which solubilize in the scrubber and effectively blocks the
oxidation initiation reaction in which the sulfite free radicals are created. This
combination has been demonstrated at bench-scale to be very effective and is
currently being demonstrated at one full-scale FGD system.2'3
Another technique which is being used with success at one FGD system is the use of
crystal modifiers in the make-up water to alter the supersaturation at which gypsum
nucleation occurs. With this treatment, higher natural oxidations can be tolerated in
the FGD system before nucleation begins, thus reducing gypsum scaling.
Limestone Dissolution
Limestone dissolution can be influenced either positively or negatively by additives
in wet FGD. Just as calcium sulfite and gypsum solids precipitate as a function of
relative saturations, limestone dissolves as a function of its relative saturation.
Therefore, if the liquid-phase concentrations of calcium and/or carbonate are
decreased, limestone will dissolve more readily. Both inhibited-oxidation and forced-
oxidation chemistries can enhance limestone dissolution compared to a natural
oxidation chemistry. In the case of inhibited oxidation, when the liquid-phase sulfate
concentration is lowered, the liquid-phase calcium concentration and calcium
carbonate relative saturations are also reduced. The magnitude of the beneficial effect
this has on limestone dissolution depends on the amount of calcium which was in
the liquid phase initially and the original limestone utilization. The liquid-phase
calcium concentration is closely related to the liquid-phase chloride concentration.
The greatest improvement would occur if the reduction in liquid-phase calcium were
a significant percent of the total soluble calcium and if the system were operating at
lower limestone utilizations (<90%). While inhibited-oxidation chemistry reduces
the liquid-phase calcium concentration, forced-oxidation chemistry actually reduces
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the the liqiud-phase carbonate concentration. In this case, the sparging of air through
the absorber reaction tank strips CO2 from the solution, reducing the carbonate
concentration and the calcium carbonate relative saturation, thus allowing limestone
to dissolve more readily.
The addition of magnesium can have the opposite effect on limestone dissolution, by
increasing the liquid-phase sulfite concentration. Higher levels of soluble sulfite can
have a blinding effect on limestone particles. It is thought that sulfite can tie up some
of the surface active sites on the limestone particle and make dissolution more
difficult. This has been noted in several full-scale FGD systems. Thus, while the
addition of magnesium to a wet limestone FGD system increases SO2 removal, it is
likely that limestone utilization would be decreased. Of course, it would be possible
to reduce the operating pH to improve the limestone utilization while still having
increased SO2 removal due to the higher liquid-phase sulfite levels.
Calcium Sulfite Solids Quality
As mentioned previously, calcium sulfite is incorporated as a solid solution within
the calcium sulfite crystal matrix up to about 15 mole percent. Thus if the oxidation
rate is kept below 15%, all of the sulfate formed in the liquid-phase will be lost from
the system in this manner and gypsum solids cannot be formed in the absorber or
reaction tank. The research associated with inhibited oxidation chemistry has shown
that as the amount of sulfate formed decreases, i.e. as the amount of sulfate as solid
solution within the calcium sulfite is lowered, the resulting calcium sulfite solids
demonstrate improved settling and dewatering characteristics. TVA obtained a
patent on the use of thiosulafte to improve calcium sulfite solids properties.4 What
has been found through subsequent research is that while modest improvements
occur in the gradual reduction of the oxidation rates below the 15% level, a step
change in solids improvement occurs if the oxidation rate can be reduced below
approximately 5%. Figure 2 illustrates HSTC data taken over several years of
operation of how thickener unit areas, a measure of how large a thickener is required
to achieve a specific underflow concentration (30% in this case), as a function of
sulfite oxidation rates. Calcium sulfite solids which exhibit settling and dewatering
characteristics similar to gypsum consistently result at very low oxidations. It is
entirely possible that sulfite solids can be reliably produced in this manner which can
be dewatered and disposed of similar to gypsum solids, i.e., small thickeners, smaller
filters or centrifuges, not requiring fixation, and/or possible stacking schemes. It is
not clear that the use of thiosulfate alone can accomplish these very low oxidation
rates under a variety of operating conditions. Research is centered on the possible
combined use of EDTA and thiosulfate to be able to consistently achieve these very
low oxidation rates. Research will also be investigating the properties of these
3A-7
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improved sulfite solids so that "state-of-the-art" inhibited oxidation FGD systems can
be designed to take advantage of these properties.
CHARACTERISTICS OF ADDITIVE USE
Concentration of Additive Required
It is certainly necessary to know at what concentration it is desirable for the additive
to be present in the FGD system. For example, the improvement in SO2 removal
obtained through organic acid addition depends on a number of factors including the
mass transfer characteristics of the absorber without any additives present, the
operating pH, the coal sulfur, the buffering capacity of the specific organic acid(s), and
the concentration of additive. The shape of the curve of SO2 removal vs. organic acid
concentration, however, will always resemble the curve shown in Figure 3. There
will always be a steep portion of the curve where larger improvements result from
relatively small increases in organic acid concentration, followed by a less-steep slope,
followed by a flattening of the curve. The greatest improvements actually result when
the FGD system is "underdesigned". This flat region of the curve means that the
absorber has reached the gas-phase limitation, and the alkalinity available to
neutralize absorbed SO2 is no longer a rate-limiting factor. Higher levels of additives
are of little benefit once the gas-phase limitation is approached.
With oxidation inhibition via sulfur addition, the quantity of thiosulfate required
depends on those factors which effect the natural oxidation rate, including the flue
gas oxygen concentration, the mass transfer characteristics of the absorber, the
adiabatic saturation temperature, the presence of trace metals which catalyze the
oxidation, and the chemistry of the system (i.e., the operating pH and the liquid-phase
sulfite concentration). The capability to inhibit oxidation via thiosulfate requires that
the sulfite free radicals formed in the initiation reaction are not allowed to participate
in the oxidation propagation reactions. As such, the concentration of thiosulfate
present to react with the sulfite free radicals is important. However, since the
concentration of thiosulfate in no way effects the rate of formation of these sulfite free
radicals, it is not easy to generalize precisely how much is necessary in any given
situation. Higher thiosulfate concentrations normally result in lower oxidation rates.
However, since higher liquid-phase thiosulfate concentrations can ultimately result
in higher liquid-phase calcium concentrations if the additional thiosulfate is not
reducing the amounts of sulfate formed, it is important to not indiscriminately keep
raising the thiosulfate concentrations. The best way to determine the optimum
concentration is to perform full-scale tests to determine the relationship in the
3A-8
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particular FGD system of thiosulfate concentration vs. oxidation rate. The chemistry
of thiosulfate addition has been documented in previous FGD Symposium papers.5'6
Additive Consumption Rates
How much additive is needed to be added to the system to maintain a specific
concentration ultimately determines the cost of using the additive. The addition rate
depends on the rate at which the additive is lost from the system. The loss
mechanisms include non-solution losses, such as chemical degradation,
coprecipitation, vaporization, and solution losses, i.e., liquid entrained with the
solids. Which of these loss mechanisms apply, and their relative importance in the
total additive losses, depend on the specifics of the additive and the chemistry of the
FGD system.
Chemical degradation of the additive to a form which is not effective can occur. In
the case of forced-oxidation, oxidative decarboxylation of the various organic acids is a
major factor in the amount of total losses of additive. In inhibited-oxidation, this
reaction does not occur to any measurable extent. Just the opposite occurs for
coprecipitation losses. Coprecipitation losses occur with calcium sulfite and not with
gypsum. Therefore, in inhibited oxidation, where the product solids are sulfite solids,
coprecipitation losses are a significant contributor to the total additive losses. The
propensity for any given additive to coprecipitate with the sulfite solids varies
substantially and can be influenced by what other additives are present. Since sulfite
solids are produced in very small quantities in forced-oxidation systems,
coprecipitation losses are minimal.
Vaporization losses depend on the volatility of the additives and, to some extent
whether the operating mode is forced or inhibited oxidation. For example, additives
such as formic acid and acetic acid are higher in volatility than any of the DBA acids
and would be expected to incur higher losses through vaporization. It has also been
noted at the HSTC that for formic acid, vaporization losses are considerably higher
under forced-oxidation than in inhibited oxidation chemistry.
Lastly, the losses of soluble additive entrained with the solids is a significant
consideration and depends on the amount of solids generated and the moisture
content of the dewatered solids. Since gypsum solids usually have significantly less
moisture entrained than conventional sulfite solids, the losses through this
mechanism are normally lower. If sulfite solids properties can, indeed, be improved
to be similar to those of gypsum solids, additive losses would be significantly reduced
through this mechanism. Losses of additive with the filter cake could be lowered by
washing the filter cake, thus displacing these soluble additives and returning them to
the system. Unfortunately, consideration must also be given to the system water
3A-9
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balance and to the effect that cycling up concentrations of other soluble components,
notably chlorides, would have on the system chemistry.
How Additives are Introduced into the System
The manner in which additives are actually introduced into the FGD system can
change their consumption rate and their effectiveness, in some cases. If organic acids
are added to the FGD system with the reagent through the limestone tank rather than
directly to each absorber, there will be a limitation on how quickly changes in additive
concentration can be made to the absorbers. This may or may not be very significant
depending on the particular emission limitation situation faced by the unit and how
quickly things such as coal sulfur and load change in a given unit.
Since the in-situ conversion of sulfur to thiosulfate is fairly slow and depends on the
presence of liquid-phase sulfite, it is important that the residence time in which the
sulfur is in contact with sulfite-bearing liquid is maximized. This makes it desirable
to add sulfur to the reagent storage tank and to add process water containing some
level of soluble sulfite to that tank. This increases the residence time for sulfur in the
system as a whole. Still, sulfur conversion efficiencies of around 50% are usually the
best that are achievable for limestone systems. This has not been a major
consideration for limestone FGD system designs due to the low cost of emulsified
sulfur. When emulsified sulfur is added to lime systems through the lime storage
tank, conversion efficiencies of close to 90% have been achieved. It is thought that
the introduction of emulsified sulfur into the high pH regime of the lime reagent
tank produces smaller, more soluble and more reactive intermediates which are
converted more readily to thiosulfate. It has further been noted that introduction of
the emulsified sulfur to the lime slaker is beneficial in achieving an even higher
conversion.7 Presumably, the very high temperatures encountered during slaking
have a similar effect in increasing conversion efficiency.
There is evidence in some of the research being done on crystal habit modifiers that
the manner in which the additive is introduced, in fact, dictates whether they will
even work. As more is learned about different additives and as applications of
additives for other functions increase, the manner in which additives are introduced
may become a more important consideration.
Additive Combinations
As additive use becomes more common, the use of multiple additives will almost
certainly increase. It will become very important to consider the interactions between
these additives in selecting the best combination and in optimizing the way they are
used. Already noted is the example of combining EDTA with thiosulfate for more
effective oxidation inhibition. In this case, the mechanisms in which the two
3A-10
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compounds inhibit oxidation compliment each other for greater effectiveness. The
use of formate in inhibited oxidation chemistry is another interesting example. As
can be seen in Figure 4, formate itself effectively reduces oxidation.8 Yet, as Figure 5
shows, the use of both thiosulfate and formate in combination substantially reduces
the formate consumption rate such that the use of the combination actually reduces
the operating costs.8'9 While the coprecipitation rate can be correlated very well to
the calcium formate activity, a reduction in formate coprecipitation over and above
that which would be expected from the reduction in liquid-phase calcium resulted
when thiosulfate was present. The speculation is that thiosulfate preferentially
coprecipitates rather than formate. Since elemental sulfur costs much less than
formate, the actual operating costs decrease as a result of thiosulfate being sacrificially
lost. There is evidence that a similar phenomenon occurs when using other organic
acids under inhibited oxidation chemistry.10
There has also been evidence that, under certain chemistries, harmful interactions
can occur between additives. For example, it is possible that by inhibiting oxidation
and reducing the amount of sulfate available to enter the sulfite crystal matrix, that
more organic acid could, therefore, coprecipitate. If the organic acid preferentially
coprecipitates rather than thiosulfate, the result could be an increase in operating
costs due to increased losses of the more expensive organic acid. This has been
observed with adipic acid and thiosulfate under high-calcium chemistry conditions in
work performed at the HSTC.
ECONOMICS OF ADDITIVE USE
This discussion is not intended to be a comprehensive analysis of the economic
benefits of additive use. The SOAR (SO2 Advanced Retrofit) project, which is
currently moving forward at EPRI, is attempting to investigate in detail the manner
in which design alternatives, including additives, influence capital and operating
costs for new system designs. This project is a joint effort between Sargent & Lundy,
Radian Corporation, and United Engineers and is using both the FGDPRISM (FGD
process simulation model) and FGDCOST (FGD cost model) to examine a variety of
designs for cost and flexibility considerations in an effort to demonstrate a
methodology for selecting designs for new FGD systems. Preliminary results of this
project are reported in a separate paper.11
Capital costs for additive feed systems are quite modest, usually running in the range
of $100,000 to $300,000 installed. They generally consist of a storage tank, sometimes
requiring heating or heat tracing depending on the additive, a metering pump or
pumps, and piping. Operating costs vary depending on the concentration ranges
3A-11
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required, the consumption mechanisms which occur, the degree of solids dewatering
achieved, the coal sulfur content and, of course, on the unit size. A 600 MW unit
burning 2.6% sulfur coal might spend on the order of $75,000 to $100,000 annually for
DBA to maintain 500 ppm in solution, assuming no additive recovery through filter
cake washing. (The increased limestone required for the additional SO2 removed
may be two to three times more costly than the additive!) Inhibited oxidation
chemistry on the same size unit could be maintained to completely eliminate gypsum
scaling for perhaps $30,000 to $40,000 annually. Limestone reagent for 90% SO2
removal for the same plant would probably run close to $2,000,000 per year. Total
O&M plus variable operating costs (power, reagents, waste disposal, steam) could run
close to $10,000,000 annually. The bottom line is that the capital cost for additive feed
systems will run less than 1% of the total FGD system capital costs. Operating costs for
the additives accounts for perhaps 1 to 2% of the total operating costs. Considering
the benefits obtained from using additives, they provide a great benefit to cost ratio.
Figure 6 presents the results of an analysis done by EPRI on the marginal costs of
taking a system designed to remove 90% SO2 removal and increasing the SO2
removed through the use of organic acids, DBA in this case. The base cost in this
example was around $430/ton for the 90% removal system (wet limestone forced-
oxidation). The marginal costs, i.e., the costs to get the additional tons of SO2
compared to the 90% removal level, varied, depending on the amount of additive
required, from $50 to $150/ton - a number well below any projected values for
emission credits.
FLEXIBILITY OF OPERATION
There are a number of advantages in operating stability and flexibility which can be
derived from the use of organic acids which are often overlooked but very important
when considering their use in wet FGD systems. Clearly, they are effective and
economical into enhancing SO2 removal in a wet limestone FGD system. Whether
this translates to improving the removal efficiency of an existing FGD system,
reducing the size and cost of the absorber required for a new FGD system, or designing
new systems for very high removal efficiencies, organic acids clearly can be useful.
By simply having the capability to add organic acids to an FGD system, there exist
some built-in reliability features for the system. Trade-offs between additive
concentration and L/G, for instance, are possible by comparing pumping costs to
additive costs. Figure 7 illustrates FGDPRISM-simulated performance for a wet
limestone FGD system which is designed with an L/G of 135 (a four-header spray
system) to achieve 90% SO2 removal on a 2.6% sulfur coal without organic acid
3A-12
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enhancement. The addition of 500 ppm formate can boost the removal efficiency to
about 96%, and 1000 ppm formate can raise removal efficiency to above 98%. This
capability could be very useful in generating emission credits for sale or to offset a
period when the FGD system was required to be shut down. As is also shown in the
figure, if two recycle pumps were down at the same time, certainly an unusual
occurrence, the 90% removal could still be met with the addition of around 600 ppm
formate at an L/G of 68, allowing time for pump repairs to be made without suffering
a loss in removal efficiency. Without the capability of using the organic acid, this
system's removal efficiency would have dropped to about 71%.
It is also possible to trade-off additive concentration with operating pH. Figure 8
illustrates a plot of data from some recent full-scale simulation work carried out at
the HSTC.12 Note that by operating this FGD system at pH 5.8 with no additive, an
SO2 removal of 81% can be achieved. The option exists to achieve the same removal
efficiency by operating at pH 5.2 with the addition of about 300 ppm DBA. In this case,
the savings in reagent costs through higher limestone utilization could easily offset
the cost of the DBA. This figure also illustrates another very useful characteristic in
the relationship between additive concentration, SO2 removal and operating pH.
Note that at elevated additive concentration, there is very little change in the
removal efficiency as a function of operating pH. At 1500 ppm DBA concentration in
this illustration, the removal efficiency drops only about 1%, from 98% to 97%, when
the pH drops from 5.8 to 5.2. In a forced-oxidation system the lower pH also has
potential beneficial effects on oxidation efficiency and gypsum quality.
Another opportunity for flexibility which operating at a lower pH allows is the trade-
off of additive costs to limestone grinding costs. Producing a 70% past 325 mesh grind
compared to a 95% through 325 mesh grind requires roughly one-half the grinding
energy.13 Figure 9, based on FGDPRISM simulations, illustrates the effect of additive
concentration on SO2 removal at several different grinds. Operating at low pH with
additives allows the possibility of going to a considerably coarser grind while still
achieving good limestone utilization and good SO2 removal.
Perhaps an even more important use for this relationship for systems added on
existing boilers as a result of the Clean Air Act may involve the capability to
circumvent limestone blinding caused by high particulate loadings to the FGD
system. Limestone blinding due to aluminum fluoride complexes has been reported
in several FGD systems in the U.S. and Japan.14 It is caused primarily by aluminum
solubilizing from flyash entering the FGD system with the flyash combining with
fluorides which have been absorbed from the flue gas. These aluminum fluoride
complexes are capable of blinding limestone and can severely inhibit limestone
3A-13
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dissolution. It is realistic to assume that many of the FGD systems which will be put
in on old boilers will see considerably higher flyash loadings compared to most of the
FGD systems in operation today. Thus, there is concern about possible aluminum
fluoride blinding problems. In Japan, it is common to add sodium hydroxide to the
FGD system to raise the operating pH temporarily to above 6.0 (or until the ESP
performance is corrected) to precipitate the fluoride as calcium fluoride and to inhibit
the dissolution of aluminum from the flyash. In the U.S. this is not done. When
these episodes occur, the pH drops even though additional limestone is added due to
the blinding effects on the limestone. It is only when the pH has dropped to the point
where the increased limestone solubility overwhelms the blinding effect, usually
around 5.0, that the limestone utilization improves. Meanwhile, the SO2 removal
has dropped substantially, and load reductions are frequently required to remain in
compliance. By having the capability to add organic acid, the flexibility exists to
operate in a regime where limestone blinding would not be a problem while not
compromising SO2 removal.
The use of organic acids also allows the FGD system to operate at elevated levels of
chlorides without adversely influencing the system performance. Chlorides would
normally cause limestone dissolution to be impaired due to raising the soluble
calcium levels and the calcium carbonate relative saturation. If the pH is reduced to
achieve similar limestone utilizations, the SO2 removal would suffer. If the pH is
kept constant, the SO2 removal could be maintained but then limestone utilization
would drop dramatically with increasing reagent costs and the possibility of mist
eliminator scaling which could impact reliability. Since the liquid-phase alkalinity is
furnished by the additive, SO2 removal is essentially divorced from limestone
dissolution. Figure 10 is an FGDPRISM simulation showing the effects of chloride
concentration on SO2 removal at constant limestone loading with and without DBA
additive. Note that as the chloride changes from 10,000 ppm to 50,000, the SO2
removal decreases from 94% to 79%. In the presence of 500 ppm additive, this same
change in chloride concentration results in a decrease in SO2 removal of from 97% to
95.5%. With 1000 ppm DBA, the reduction is only from 98% to 97%. While it is not
expected that the coal chloride would be likely to change to this extent, this kind of
operating flexibility would allow a significant change in the system water balance
without necessarily impacting the system performance. This means that washing the
filter cake to recover additive can be done without having the increased chloride
concentration impair system performance.
The capability to use organic acids also allows the system to be very flexible with
respect to the inlet SO2 concentration. Since the organic acid provides the liquid-
phase buffering capability, the system is not nearly as sensitive to changes compared
3A-14
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to the situation where limestone dissolution in the absorber is critical. Figure 11
illustrates this point from some recent HSTC data. The FGD system was removing
90% at 2000 ppm inlet SO2. When the inlet SO2 was doubled to 4000 ppm, the SO2
removal decreased to 84% for an unassisted system. What would be even more
significant is that the outlet SO2 emissions rose from 200 ppm to 640 ppm. With
organic acid additives, in this case formate, less than 500 ppm additive was able to
achieve 95% removal with the 4000 ppm inlet SO2 flue gas, thus keeping outlet
emissions unchanged. Note the same characteristic here as was seen for changes in
pH, when the additive concentration is fairly high, there is little change in
performance even with a very large change in inlet SO2 concentration.
Lastly, there are a variety of organic acids which could be used to improve
performance of FGD systems. DBA is by far the most commonly used, but formic acid
and sodium formate are also being used. Any of the DBA acids (adipic, glutaric or
succinic) could be used individually. Citric acid was used in several early scrubbing
processes. There is evidence that a maleic acid could be used also. Even acetic acid is
a possibility, if you don't mind your FGD system smelling a bit like salad dressing!
Each of these acids would have their inherent pH at which they buffer most
effectively which would determine the concentrations required and would have
different consumption rates and mechanisms which would determine their addition
rates and costs, but almost any of them could be used. Figure 12 shows the
relationship between DBA and formate conducted at the HSTC under inhibited
oxidation conditions at a pH of 5.8, under a specific chemistry. In this case, DBA is
slightly more effective. The point is, there is no great danger of being a captive
market for a particular additive or to a particular supplier.
CAUTIONS ON ADDITIVE USE
While many positive aspects of additive use in FGD systems are being demonstrated,
there are some negatives which are being investigated as well. It is essential that the
use of additives does not create any cross-media problems. EPRI is investigiating the
effects on air, water and solid waste emissions. Vapor-phase emissions of 1 to 3 ppm
formate under forced-oxidation conditions have been measured at the HSTC. While
these levels are well below any exposure limits for workers, there is concern as to
whether they could be considered as a source of "toxic" emissions. Similarly, in
situations where FGD water discharges are either discharged or treated, the presence
of any organic species may be undesirable. Investigations on the effects of sulfur and
organic acids on solid waste properties have not yielded any measurable differences in
physical or chemical characteristics.
3A-15
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An area of possible concern which is still under investigation is whether the presence
of thiosulfate increases the corrosiveness of FGD liquor. Laboratory investigations
have been inconclusive.15 At least one full-scale site has reported increased corrosion
in 317L material in their outlet duct since initiating inhibited oxidation using
thiosulfate. Yet there are several dozen others using thiosulfate who have not
reported any evidence that thiosulfate is causing any increases in corrosion. There is
also some concern that by increasing the reducing atmosphere within the FGD liquor,
which thiosulfate certainly does, that conditions under which H2S is generated may
be more common. There is little evidence to support this, however, from operating
FGD systems.
FUTURE USES FOR ADDITIVES
The use of SO2 performance additives will increase substantially as a result of a
greater emphasis on high-efficiency SO2 removal. The least expensive way to obtain
reduced SO2 emissions is to improve the performance of existing FGD systems. As
was pointed out earlier, the capital costs of an additive feed system are modest. The
performance improvement is absolute. Similarly, if retrofit FGD systems are
required, the emphasis will be on installing very high efficiency FGD systems. While
high efficiency systems can be designed without using additive enhancement, the
most cost-effective way is to design for the use of organic acid additives.
Virtually all future limestone or lime systems will be designed to operate in either
the forced-oxidation or inhibited-oxidation mode. Inhibiting oxidation using
thiosulfate has become common and has been demonstrated to be very reliable and
effective in eliminating gypsum scaling. Improvement in solids characteristics and
the possible development of reuse options for calcium sulfite solids may increase the
the number of systems designed to operate in this manner.
Bench-scale research looking at several organophosphonate compounds as crystal
habit modifiers for both calcium sulfite and gypsum systems has been reported
previously.16 Pilot research is currently underway at the HSTC. Significant progress
has been made in understanding how these compounds work and under what
circumstances they could be useful for future FGD systems. It is entirely likely that
catalysts for improving oxidation efficiency will be used in future FGD system
designs. It is even possible that FGD systems using catalyzed oxidation may be
possible without the need for external air being sparged into the reaction tanks. As
more and more is learned about how additives work and their effects when used with
other additives, it may well become common practice to have additive combinations
formulated for specific chemistries and specific FGD systems.
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CONCLUSIONS
Additives can be used to improve performance, improve reliability and operating
flexibility, and reduce costs for new and existing FGD systems. High SO2 removal
efficiencies are possible with very modest increases in capital and operating costs.
Gypsum scaling should not be a problem in FGD systems. Additives to effect
dramatic improvements in solids characteristics are being demonstrated on pilot scale
and may well be commercially available in the near future. While the positive
aspects of additive use in FGD systems are being recognized, possible residual effects
on air, water and solid waste quality are also being investigated.
ACKNOWLEDGMENTS
The work reported in this paper is the result of research carried out in part at EPRI's
High Sulfur Test Center (HSTC) located near Barker, NY. We wish to acknowledge
the support of the HSTC cosponsors: New York State Electric & Gas, Empire State
Electric Energy Research Corp., Electric Power Development Co., Ltd., and the US
Department of Energy. The cosponsors provide valuable technical review of the
work in progress as well as funding test center operations.
REFERENCES
1. R. Moser and F. Meserole. U.S. Patent No. 4,994,246, February 1991.
2. G. Mailer, F. Meserole and R. Moser. "Use of Thiosulfate and EDTA to Inhibit
Sulfite Oxidation in Wet Limestone FGD Processes: Results of Laboratory and
Bench-scale Testing." In Proceedings: 1990 SQ2 Control Symposium, vol. 3,
September 1990, pp. 7B53-74.
3. G. Blythe, T. Slater and R. Moser. "Full-Scale Demonstration of EDTA and
Sulfur Addition to Control Sulfite Oxidation." presented at and to be published
with the Proceedings of the 1991 SO2 Control Symposium.
4. F. Garrison and W. Wells. U.S. Patent No. 4,454,101, June 1984.
5. D. Owens et al. "Inhibited Sulfite Oxidation by Thiosulfate in Wet
Lime/Limestone FGD Processes: Results of Laboratory Studies and Testing at
EPRI's HSTC Mini-Pilot." In Proceedings: First Combined FGD and Dry SQ2
Control Symposium, vol.1, April 1989, pp. 5-310 to 5-334.
6. R. Moser. D. Owens and D. Colley. "Control and Reduction of Gypsum Scale in
Wet Lime/Limestone FGD by Addition of Thiosulfate: Summary of Field
3A-17
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Experiences." In Proceedings: First Combined FGD and Dry SQ2 Control
Symposium, vol.1, April 1989, pp. 5-335 to 5-355
7. L. Benson and D. Stowe (Dravo Lime Company). Patent pending.
8. J.Burke, M. Stohs, T. Price and R. Moser. "Results of Sodium Formate Addition
at EPRI's HSTC and AECI's Thomas Hill Unit 3 FGD System." In Proceedings:
1990 SQ2 Control Symposium, vol. 2, September 1990, pp. 5-23 to 5-44.
9. R. Moser, J. Burke and D. Owens. U.S. Patent No. 5,034,204, July 1991.
10. M. Bailey et al. "Results of an Investigiation to Improve the Performance and
Relaibility of HL&P's Limestone Station FGD System." presented at and to be
published with the Proceedings of the 1991 SO2 Control Symposium.
11. C. Dene et al. "Develpoment of Advanced Retrofit FGD Designs." presented at
and to be published with the Proceedings of the 1991 SO2 Control Symposium.
12. EPRI High Sulfur Test Center: Pilot Plant TVA Simulation Test Results -
Options to Increase the SQ2 Removal Efficiency of TVA's Paradise Station FGD
System. Draft EPRI Report, September 1991.
13. EPRI High Sulfur Test Center Report: Guidelines for Selecting Limestone
Reagents for Wet FGD Systems. Draft EPRI Report, October 1991.
14. J. Jarvis, R. Farmer and D. Stewart, "Description and Mechanism of Limestone
FGD Operating Problems Due to Aluminum/Fluoride Chemistry." In
Proceedings: Tenth Symposium on Flue Gas Desulfurization, vol.1, May 1987,
pp. 7-79 to 7-85.
15. P. Ellis and D. DeBerry. "Preliminary Study of Effects of Additive Additions on
Four FGD Scrubber Alloys." In Proceedings: 1990 SQ2 Control Symposium, vol. 2,
September 1990, pp. 4B107-129.
16. F. Meserole et al. "Use of Crystal Modifiers for FGD Scrubber Solids." In
Proceedings: 1990 SO2 Control Symposium, vol. 3, September 1990, pp. 7B75-99.
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Nucleation
Region
Crystal
Growth
Region
1.0 1.3-1.4
Relative Saturation, R.S.
Figure 1. Precipitation of Gypsum
1200
2000
400
800
1600
Adipic Acid Concentration (ppm)
Figure 3. SO2 Removal Enhancement by Adipic Acid
50
40
30
20
10
0
Sulfite Oxidation
Figure 2. Relationship Between Sulfite Oxidation and
Unit Area for Inhibited Oxidation Samples
20 T
17
11
500 1500 2500 3500 4500
Formate Concentration (ppm)
Figure 4. Effect of Formate Concentration on Sulfite Oxidation
-------
20 T
15
10
high Ca ++ pH = 5.5
low Ca ++, pH = 5.5
high Ca ++, pH = 5.0
high Ca ++ S203 =
10
20
90
0
30
40
50
60
80
70
Calcium Formate Activity Product/1000
Figure 5. Formate Coprecipitation vs. Calcium Activity Product
100
95
90
80
~ L/G = 135
A L/G = 68
75
1 I I I _! I _l_
500 1000 1500 2000 2500 3000 3500 4000
70
0
Formate Concentration (ppm)
Figure 7. Effect of DBA and L/G on SO2 Removal Efficiency
450
400 "¦
350 --
300 "¦
250 -
200 --
150 ¦
100 --
50 "
Base Case
FGDPRISM & FGDCOST used
300 MW, 2.6% sulfur,
moderate retrofit, all costs
for additive included In the
capital cost changes
(See Figure 3 for Additive Concentrations)
90 91 92 93
-4—
94
95
96 97
98
99
j SO2 Removed
Figure 6. SO2 Emissions Marginal Costs vs. % Removal
100
95
N
o
V)
£
80
pH 5.2
pH 5.8
75
70
2000
1500
1000
500
0
DBA (ppm Buffer Capacity)
Figure 8. Effect of DBA and pH on SO2 Removal Efficiency
-------
inn
95
90
85
• — Base Case, 95% < 325
e— 90 % < 325
¦A— 67% < 325
sn
2000
1500
500
inoo
DBA Concentration (ppm)
OJ
>
I
N)
100
Figure 9. Effect of DBA and Limestone Grind
on SO2 Removal Efficiency
2000 ppm inlet SO2
4000 ppm inlet SO2
500 1000 1500 2000 2500 3000 3500 4000
Formate Concentration (ppm)
Figure 11. Effect of Inlet SO2 and Formate
on SO2 Removal Efficiency
100
>
0
6
01
05
O
- No Additives
500 ppm DBA
1000 ppm DBA
10000 20000 30000 40000 50000 60000
Chloride Concentration (ppm)
Figure 10. Effect of Chloride Concentration and DBA
on SO2 Removal Efficiency
pH 5.8, 2000 ppm inlet SO2, Spray tower
4.5
I 4.0
o
C/5
3 3.5
N
0
w
£ 3.0
II
a
1 2.5
V
I 2.0
z
1.5
0 500 1000 1500 2000 2500
Buffer Capacity (ppm)
Figure 12. Comparative Effect of DBA vs. Formate
on SO2 Removal Efficiency
98%
95%
90%
DBA
Formate
-------
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3A-22
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RESULTS OF HIGH S02 REMOVAL EFFICIENCY TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
Gregory E. Stevens
Steven D. Sitkiewitz
James L. Phillips
Radian Corporation
8501 Mo-Pac Boulevard
Austin, TX 78720
David R. Owens
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94303
Preceding page blank
3A-23
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Intentionally Blank Page
3A-24
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RESULTS OF HIGH S02 REMOVAL EFFICIENCY TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
ABSTRACT
This paper summarizes the results of recent tests conducted on the 4-MWe pilot-
scale wet scrubber at the Electric Power Research Institute's (EPRI) High Sulfur
Test Center (HSTC). Various options are being investigated for providing least-
cost compliance with 1990 Clean Air Act Amendments. These options include formate
and DBA addition under inhibited- and forced-oxidation conditions, magnesium-
enhanced lime reagent, and the use of trays and packing.
Results from the tests involving formate addition under forced-oxidation operation,
DBA addition under inhibited-oxidation operation, and the use of a tray under
inhibited-oxidation operation will be presented. The primary focus of this paper
is on S02 removal efficiency with a secondary emphasis on factors affecting oper-
ating costs. Two of these factors are the additive consumption rates and the tray
pressure drop.
Preceding page blank
3A-25
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RESULTS OF HIGH S02 REMOVAL EFFICIENCY TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
INTRODUCTION
The HSTC is located adjacent to New York State Electric and Gas Corporation's 650-
MW Kintigh Power Station in the town of Somerset, New York. The facility is oper-
ated and managed by EPRI for the purpose of improving S02 emission control tech-
nologies for the electric utility industry. A detailed description of the HSTC and
its capabilities has been reported previously (I).
This paper summarizes the results of recent tests which are part of an on-going
research project using the HSTC pilot wet FGD system (a 4-MW-equivalent FGD sys-
tem). The overall goal of this project is to investigate methods for enhancing
performance, reducing operating costs, and improving the reliability of existing
lime and limestone FGD systems. Results from the HSTC tests can also be used to
improve the design of new FGD systems.
Currently, the HSTC pilot tests are investigating options for achieving high S02
removal efficiencies. There are several conventional and non-conventional methods
for improving the S02 removal efficiency in an existing system. These methods
include using performance-boosting additives, adding a tray or packing to the
absorber, and simply increasing the reaction tank pH and absorber L/G. The High
S02 Removal Efficiency Project is designed to evaluate the various options using a
single FGD system so that the results can be compared on a consistent basis.
The specific objectives of the HSTC pilot-scale High S02 Removal Efficiency tests
are to:
• Demonstrate the ability of EPRI's pilot-scale FGD system to achieve
high S02 removal efficiencies (greater than 95%) using various
alternatives;
3A-26
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• Provide a consistent basis for an economic comparison of different
options for attaining high S02 removal efficiencies in new or exist-
ing lime/limestone FGD systems;
• Compare the performance and determine the consumption rates of dif-
ferent additives under inhibited- and forced-oxidation conditions;
and
• Determine the effects of additives on other process performance
indicators such as reagent utilization and solids dewatering prop-
erties and wallboard suitability.
Meeting these objectives will provide a basis for analyzing options for least-cost
compliance with 1990 Clean Air Act Amendments. It will also generate data to
improve the capabilities of EPRI's FGD PRocess Integration and Simulation Model
(FGDPRISM). Some of the more useful data for the model will be for additive degra-
dation, coprecipitation, and vaporization rates.
Seven performance-enhancing options are being investigated as part of the High S02
Removal Efficiency test program:
1. Installation of a tray--preliminary work completed in July 1990 and
further tests scheduled for December 1991.
2. Installation of packing--scheduled for early 1992.
3. Formate addition under inhibited-oxidation conditions using
limestone reagent--completed in April-July 1991.
4. Formate addition under forced-oxidation conditions—completed in
September-October 1991.
5. DBA addition under inhibited-oxidation conditions—completed in
November-December 1991.
6. DBA addition under forced-oxidation conditions—completed in August
1991.
7. Lime reagent with magnesium addition—scheduled for 1992.
Accompanying each of these test series will be an evaluation of the effects of L/G,
reaction tank pH, inlet S02 concentration, thiosulfate concentration (inhibited-
oxidation tests only), and dissolved calcium concentration on FGD system
performance.
3A-27
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Installation of a tray or packing would enhance the mass transfer characteristics
of the absorber by increasing the gas-liquid contacting area and increasing the
residence time of the lime/limestone slurry in the absorber. The costs associated
with this modification are the capital costs plus the operating costs associated
with the increased gas pressure drop across the tray or packing. Maintenance costs
may also escalate if the tray or packing tends to scale or plug frequently.
The organic acid additives, DBA and formate, boost performance by buffering the pH
of the scrubbing liquor and reducing the resistance to mass transfer. In other
words, the additives increase the capacity of the scrubbing liquor to absorb S02.
The costs associated with using additives are the cost of additive .equipment such
as a feed tank, pumps, or heating equipment; and the cost of the additive itself,
which is a function of solution and non-solution losses (degradation, coprecipita-
tion, and vaporization).
High-magnesium lime reagent increases the buffering capacity of the scrubbing
liquor by increasing the dissolved sulfite concentration. High-magnesium lime can
be used to achieve high S02 removal efficiencies without the use of additional
additives, trays, or packing. Magnesium-enhanced lime and limestone with organic
buffers should have similar effects on S02 removal, although the L/G and reagent
requirements for the two systems have not yet been compared on a single system.
Future tests will compare the benefits of magnesium-enhanced lime reagent with that
of limestone plus an additive and evaluate the economics of each method.
This paper will present the results from the series of tests completed through
September 1991. These include:
• Preliminary tray tests under inhibited-oxidation conditions;
• Formate addition under inhibited-oxidation conditions; and
• DBA addition under forced-oxidation conditions.
SYSTEM DESCRIPTION AND TEST PROCEDURES
Figure 1 is a schematic of the HSTC pilot wet FGD system as it was configured
during the High S02 Removal Efficiency tests. A detailed description of this sys-
tem and its operation have been reported previously (JJ. Two different dewatering
3A-28
-------
schemes were utilized during the testing. The horizontal centrifuge was used for
all of the inhlblted-oxidation tests and several of the forced-oxidation tests. A
10-ft2 vacuum belt filter was used for selected forced-oxidation tests to collect
washed gypsum samples for future wall board suitability tests.
The baseline operating conditions are summarized in Table 1. During these tests,
both the inlet flue gas flow rate and the inlet S02 concentration were adjusted
using automatic feedback control loops. In addition, the limestone reagent slurry
addition rate was automatically controlled to maintain a constant reaction tank pH.
The absorber feed slurry solids concentration was controlled by adjusting the waste
slurry blowdown rate. Dissolved species were controlled by the addition of chemi-
cals or by discharging clear liquor from the centrifuge, depending on the concen-
trations desired.
Two types of tests were conducted, depending on the objective of the test. If the
primary objective was to determine the S02 removal efficiency, then the test only
ran for approximately 4 to 6 hours. However, if the objective also included an
evaluation of the solids composition and dewatering properties, the test was com-
pleted over a minimum of five days. The first two days were required to reach
steady-state with respect to the solids composition (three solids residence times).
The final three days were required to collect liquid and solid samples from the
reaction tank during steady-state operation. Process data were collected continu-
ously using a data acquisition and control system.
TEST RESULTS
The results presented in this paper are from high S02 removal efficiency tests com-
pleted through September 12, 1991. These tests included:
• Preliminary tests with a tray installed in the absorber. This work
was completed during July 1990.
• Formate addition under inhibited-oxidation conditions. Sodium thio-
sulfate was added as the oxidation inhibitor.
• DBA addition under forced-oxidation conditions.
Table 2 is a summary of the test conditions for the High S02 Removal Efficiency
tests presented in this paper. The tests were designed to generate data which will
3A-29
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be useful for full-scale applications. However, caution should be exercised in
interpreting the pilot data. The pilot absorber was designed with excellent mass
transfer characteristics. Many full-scale FGD systems operate with much less effi-
cient gas-liquid contacting as a result of poor gas distribution or insufficient
spray coverage in the absorber.
One application will be to utilize these data in EPRI's computer model, FGDPRISH,
which can then be calibrated and tailored for a specific system. The model can be
used to predict performance improvements that are realized with additive addition,
increasing L/G, increasing pH, or installing a tray or packing.
The results and discussion which follow show how installation of a tray, addition
of organic acids, changing L/G, reaction tank pH, and flue gas inlet S02 concen-
tration affected S02 removal efficiency for the HSTC pilot FGD system. Factors
affecting the costs of achieving high S02 removal efficiency are also discussed.
These factors include additive consumption rates, tray pressure drop, limestone
reagent utilization, and recirculation pump power consumption (L/G).
Options for Achieving High S02 Removal Efficiency
Installation of a Trav in the Absorber. Installing a tray increases S02 removal by
providing additional slurry residence time in the absorber. (This increases the
amount of limestone which can dissolve, thus providing more alkalinity for S02
absorption.) Adding a tray may also increase the surface area available for gas-
liquid mass transfer.
Figure 2 illustrates the effect of installing a 35% open, countercurrent, perfor-
ated tray in the pilot absorber. The baseline data (i.e., no tray) are from the
limestone baseline tests completed in 1989. Results are plotted in terms of rela-
tive transfer units (RTU's). The results in Figure 2 show that the tray provided a
relatively constant increase in S02 removal efficiency over the L/G range tested.
It also shows that installation of the tray was equivalent to increasing the L/G by
about 20 gal/kacf, although this result is valid only for the pilot absorber. It
is expected that the effect of adding a tray to a full-scale system will differ
from the pilot results, but the pilot data can be used to estimate such an effect
when used in combination with FGDPRISM.
3A-30
-------
Figure 3 presents the effect of the tray location (relative to the absorber header
in service) on S02 removal efficiency. This figure also illustrates how S02 remo-
val efficiency varied as a function of the limestone loading (i.e., the concentra-
tion of solid limestone in the slurry) for three different L/G's and three dif-
ferent spray header configurations. As the results in Figure 3 show, S02 removal
increases as the distance between the header and the tray increases. This benefit
is a result of the increased distance that the spray droplets fall before hitting
the tray, which results in more surface area and reaction time for S02 absorption.
The absorber configuration also had an effect on the tray pressure drop. This
result is illustrated in Figure 4 which shows how the tray pressure drop varied as
a function of L/G for the three header configurations tested. As shown, the pres-
sure drop was higher when the lower spray header was in service. Extrapolating the
results from the tests with the lower header in service also suggests that the tray
pressure drop with two headers in service was lower than would be expected. This
result was somewhat surprising since the pressure drop across the tray should have
been constant (at constant L/G and flue gas flow rate), regardless of which spray
header was in service. It appears that the change in tray pressure drop as a
function of spray header position was the result of poor liquid distribution on the
tray surface when the upper header was operated. Apparently, the slurry which hit
the absorber walls before reaching the tray did not redistribute itself evenly on
the tray (i.e., the tray did not provide enough resistance to evenly distribute the
flood of slurry on the absorber walls). Such poor gas/slurry distribution will
cause the results from the pilot tests to underpredict the benefit of trays
installed in the absorber. An improved slurry distribution header will be used in
additional tray tests planned for December.
Organic Acid Additives. The S02 removal efficiency was evaluated for operation
with formate addition under inhibited-oxidation conditions and with DBA addition
under forced-oxidation conditions. Figure 5 illustrates the effect of formate (in-
hibited oxidation) and DBA (forced oxidation) addition on the RTU's and S02 removal
efficiency.
On a mass basis, formate and DBA provide similar performance improvements up to
approximately 1000 ppm. Above that concentration, DBA enhanced the RTU's up to 20%
more than formate. On a molar basis at an operating pH of 5.5, DBA is three times
3A-31
-------
more effective than formate at concentrations less than 1000 ppm. This is because
DBA is a dibasic acid with buffering pHs (pKJ of 4.3 and 5.5. The formate ion, on
the other hand, can only accept one proton and buffers at pH 3.75.
Previous pilot-scale tests have shown that the S02 removal efficiency (in ) was
roughly proportional to the absorber L/G. It is important to determine if this
relationship is consistent in the presence of organic acid additives. Figure 6
shows the effect of L/G on S02 removal efficiency (expressed in RTU's) for tests
with formate under inhibited-oxidation conditions and with DBA under forced-
oxidation conditions. The data show that S02 removal efficiency remained propor-
tional to the L/G with only slight variations. In other words, doubling the L/G
will approximately double the RTU's.
Figure 6 also demonstrates the trade-off between L/G and additive concentration for
achieving a desired S02 removal efficiency. For example, the same S02 removal can
be reached under inhibited-oxidation conditions with either a L/G of 132 gal/kacf
and no additive, or a L/G of 66 and about 800 ppm formate. Note that the pilot-
scale absorber L/G is not equivalent to a full-scale system L/G because of the
absorber design. The pilot absorber is smaller in diameter compared to full-scale
systems, yet is using 90-degree full-cone nozzles. Therefore, much of the spray
hits the walls within a short distance from the nozzles and is no longer available
to absorb S02. This results in a much lower "effective" L/G.
Another factor which can affect S02 removal efficiency is the inlet S02 concentra-
tion. Figure 7 illustrates how RTU's varied as a function of formate concentration
at 2000 and 4000 ppm inlet S02 (inhibited-oxidation operation). By doubling the
inlet S02 concentration, the RTU's decreased by between 0.4 and 0.8 at less than
1000 ppm formate. These tests were conducted at a constant reaction tank pH of
5.5. The limestone loading (the concentration of undissolved limestone in the
reaction tank) was nearly double at 4000 ppm compared to 2000 ppm inlet S02 (based
on limestone feed rates). Therefore, the difference in S02 removal may be greater
if evaluated at constant limestone utilization. In the presence of extremely high
liquid-phase alkalinity (formate concentration of 4000 ppm or greater), the inlet
S02 concentration will not affect the removal efficiency because there is essen-
tially no resistance to mass transfer in the liquid film at the gas/liquid inter-
face. This same effect would be expected with high concentrations of DBA.
3A-32
-------
It is important to determine the effect of organic acid addition on limestone
utilization before looking at the effect of limestone utilization on S02 removal in
the presence of these organic acids. Table 3 lists the limestone utilizations and
limestone loadings (i.e., undissolved limestone concentrations in the reaction tank
slurry) at a constant reaction tank pH and varying organic acid concentrations.
The background liquor chemistry was similar for all of these tests, resulting in
nearly constant calcium carbonate relative saturations. The tests with formate
were conducted under inhibited-oxidation conditions, whereas the tests with DBA
were with forced oxidation.
Table 3 shows that the addition of formate did not have a significant effect on
limestone utilization, whereas DBA appears to have inhibited utilization. Previous
mini-pilot tests have shown that, at low calcium concentrations, formate may actu-
ally improve limestone utilization. During the tests with DBA, the limestone load-
ing required to maintain a constant reaction tank pH doubled with 2500 ppm DBA in
the slurry liquor compared to the baseline test with no DBA present. This inhibit-
ing effect of DBA on limestone dissolution can be counteracted by simply decreasing
the reaction tank pH set point to maintain the same limestone utilization. The
accompanying decrease in S02 removal efficiency can be avoided by increasing the
DBA concentration slightly.
As mentioned above, formate did not appreciably affect limestone utilization.
Therefore, the effect of limestone utilization on S02 removal in the presence of
formate can be evaluated. Figure 8 illustrates the effect of limestone utilization
on S02 removal efficiency at low and high formate concentrations. The limestone
utilization was adjusted by changing the reaction tank pH. At the low formate con-
centration, changes in limestone utilization had a significant impact on S02 remo-
val. However, as the liquid-phase alkalinity increased, the effect of changing the
undissolved limestone concentration was lessened. The high formate concentration
test data shown in Figure 8 are from tests with an L/G of 66. At an L/G of 132,
the effect of limestone utilization on S02 removal should be even smaller. This
effect was also observed with DBA addition. At high additive concentrations, the
boost in liquid-phase alkalinity that could be acquired from additional undissolved
limestone in the slurry became insignificant. Therefore, it may be reasonable to
operate with high organic acid concentrations and low reaction tank pHs to conserve
limestone. (This will be an economic decision based on site-specific factors.)
3A-33
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No effects of DBA on the solids dewatering properties could be measured under
forced-oxidation conditions. However, there were noticeable effects of formate
under inhibited-oxidation conditions. Figure 9 shows the effect of formate on the
thickener unit area required to achieve 30 wt.% solids concentration and on the
filter cake solids concentration at the end of the form filtration tests. All of
the tests were conducted at baseline conditions and with extremely low sulfite oxi-
dation (approximately 2%). The required thickener unit area increased from about 2
ft2-day/ton without formate to about 6 ft2-day/ton with 2150 ppm formate. The fil-
ter cake solids concentration underwent corresponding changes as it decreased from
80 wt.% without formate to 62 wt.% with 2150 ppm formate. These changes in the
settling and filtering characteristics must be taken into account when considering
the addition of formate to inhibited-oxidation FGD systems.
Factors Affecting Costs of High S0: Removal Efficiency
The costs associated with installing a tray in the absorber include the cost of the
tray and installation and the increased operating cost due to higher absorber gas
pressure drop. The pressure drop across a typical countercurrent perforated tray
is approximately 2 to 3 inches of water. Some costs may be incurred for maintain-
ing the tray; however, with inhibited-oxidation systems where the gypsum relative
saturation is maintained at relatively low values or with forced-oxidation systems
that achieve nearly complete oxidation, very little scaling should be encountered.
Although the use of organic acid additives can increase S02 removal efficiency sub-
stantially, the cost of these additives must be weighed against the value of the
additional S02 removed. Additives must be continually introduced into the system
to replace losses from liquor blowdown (normally associated with the solids
byproduct), vaporization, chemical degradation, and precipitation. The first term
is commonly referred to as solution loss, while the sum of the latter three is
referred to as non-solution loss. Additive consumption was examined in the pilot
tests so that relative addition requirements for different additives could be
determined. The pilot data are site-specific and dependent on system chemistry,
system volume, slurry temperature, and S02 removal performance. However, the
results are useful for comparing relative additive consumptions between pilot
system tests.
3A-34
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Figure 10 Illustrates the effect of additive concentration on the non-solution
losses of formate and DBA. The loss rate of formate in the inhibited-oxidation
configuration was higher than for DBA in the forced-oxidation configuration. Three
reasons can be given to explain this difference. First, formate is volatile at FGD
conditions, while the DBA components are not. Second, although analysis has not
been completed on the solids for these tests, it is known that formate coprecipi-
tates in inhibited-oxidation configurations, while DBA does not coprecipitate in
forced-oxidation configurations. And third, the larger DBA components (C4-C6) are
more stable and degrade more slowly than formate (C,) in FGD slurries.
A comparison of the resulting non-solution loss rate for three additive configura-
tions is presented in Figure 11. In addition to DBA forced-oxidation and formate
inhibited-oxidation results from the pilot system, results from DBA and formate
forced-oxidation and formate inhibited-oxidation tests from the HSTC mini-pilot
system are included. This figure shows that additive consumption is highest for
the formate forced-oxidation configuration and lowest for the DBA forced-oxidation
configuration. Also, the pilot and mini-pilot DBA loss results are similar.
However, the mini-pilot and pilot inhibited-oxidation results do not agree, even
though the chemistry in these test blocks was similar. Since scaling up
consumption results from the mini-pilot to the pilot should be much easier than
scaling up to a full-scale system, this difference in consumption must be resolved
before accurate estimates of full-scale formate losses based on general HSTC data
will be possible. A complete analysis of the analytical and process data from
these two test blocks is in progress.
The results to date provide some insight into the relative additive consumption
rates for different system configurations. However, the results also suggest that,
to be able to apply the consumption results to full-scale configurations, more
testing is required. With the knowledge gained from these first tests, additional
tests will be planned that will quantify the sensitivity of additive consumption to
system parameters.
SUMMARY OF RESULTS
The results from the initial phase of the High Efficiency S02 Removal test block
from the HSTC pi lot-scale wet FGD system are summarized below:
3A-35
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• Installation of a 35% open, countercurrent, perforated tray provided
0.3 to 0.4 RTU's over a wide range of absorber L/G's. Adding a tray
was equivalent to increasing the L/G by about 20 gal/kacf.
• The S02 removal efficiency increased with the distance of the spray
nozzles from the tray. The increase in a full-scale system will be
dependent on the L/G, spray configuration, and nozzle type.
• Results from tests on the pilot-scale absorber may underpredict the
benefit of adding trays. Based on tray pressure drop data, the
slurry was unevenly distributed on the tray as a result of wall
effects.
• On a mass basis, for concentrations below 1000 ppm, formate and DBA
provided similar enhancements to S02 removal efficiency at pH 5.5.
At 2500 ppm additive, DBA (forced oxidation) provided 20% more RTU's
than formate (inhibited oxidation).
• The RTU's were proportional to the L/G in the presence of formate or
DBA. This is consistent with previous pilot-scale tests which
demonstrated similar effects of L/G on S02 removal with no additive
present.
• DBA exhibited an inhibiting effect on limestone utilization, result-
ing in an Increase in the limestone loading from 1.6 g/L with no DBA
to 3.4 g/L with 2500 ppm DBA (reaction tank pH of 5.5).
• The solids dewatering properties deteriorated with formate addition
at a constant sulfite oxidation of 2%. The thickener unit area
required to achieve 30 wt.% solids increased from 2 ft2-day/ton
without formate to 6 ft2-day/ton with 2150 ppm formate. The filter
cake solids content decreased from 80 wt.% to 62 wt.%.
• The consumption rates for the organic acid additives were highest
for formate during forced oxidation (mini-pilot data), then for
formate during inhibited oxidation, and were lowest for DBA during
forced oxidation.
ACKNOWLEDGEMENTS
The work reported in this paper is the result of research carried out at EPRI's
High Sulfur Test Center (HSTC) located near Barker, New York. We wish to acknow-
ledge the support of the HSTC cosponsors: New York State Electric and Gas, Empire
State Electric Energy Research Corporation, Electric Power Development Company,
Ltd., and the U.S. Department of Energy. The cosponsors provide valuable technical
review of the work in progress as well as funding test center operations.
3A-36
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REFERENCES
1. Moser, R.E., J.M. Burke, and S.M. Gray. "Results of Wet FGD Testing at EPRI's
High Sulfur Test Center." In Proceedings of the EPA/EPRI First Combined FGD
and Dry SQ: Control Symposium, EPRI CS-6307, RP 982-41, St. Louis, MO, October
1988.
Table 1
PILOT BASELINE TEST CONDITIONS
Inlet Gas Flow Rate (scfm)
Inlet Gas Temperature (*F)
Inlet Gas S02 (ppm)
Header #1 Flow (gpm)
Header #2 Flow (gpm)
Absorber Temperature (*F)
Reaction Tank Volume (gal)
Slurry Solids Concentration (wt.%)
Dissolved Calcium Concentration (mM)
Dissolved Magnesium Concentration (mM)
Reaction Tank pH
Reagent Type
Reagent Grind (% <325 mesh)
8,250
320
2,000 1
650
650
125
6,000
12
140
80
5.5
Beachville Limestone
90
1Inlet SO, concentration for tray tests was 2500 ppm.
3A-37
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Table 2
HPT TEST VARIABLES
Parameter Range
Reaction Tank pH 5.0 - 5.8
Inlet S02 Concentration, ppm 2,000 - 4,000
Liquid-to-Gas Ratio, gal/kacf 65 - 130
DBA Concentration, ppm 0 - 2,800
Formate Concentration, ppm 0 - 4,000
Thiosulfate Concentration, ppm 0 - 2,000
Dissolved Calcium, ppm 800 - 16,000
Dissolved Chloride, ppm 3,000 - 32,000
Table 3
EFFECT OF ORGANIC ACID ADDITIVES ON LIMESTONE UTILIZATION AT CONSTANT
REACTION TANK pH (5.5)
CaC03
Limestone
Limestone
Formate
DBA
Absorber
Relative
Utilization
Loading
(DDm)
(ppm)
dH
Saturation
m
(q/L)
0
4.8
0.11
95.2
4.5
490
--
5.0
0.09
96.2
3.6
2150
5.1
0.09
96.3
3.6
0
3.3
0.04
97.5
1.7
570
4.8
0.06
97.1
2.1
2500
5.2
0.05
95.4
3.4
3A-38
-------
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2.0
1.5
1.0
0.5
¦ No Tray
~ 35% Open Tray
0.0
40
60
140
160
80
100
120
L/G (gal/macf)
Figure 2. Effect of Installing a 35% Open Tray on
S02 Removal
-
35 % Open Tray
-
¦ L/G =45, Upper
~ L/G * 45, Lower
~ L/G > 65, Upper
O L/G> 65, Lower
d-
A L/G-122, Both
¦ ¦ i i i
*
0 5 10 15 20 25 30
Limestone Loading (gm/L)
Figure 3. Effect of Distance of Tray from Spray
Header on S02 Removal
-------
2.5
2.0
35 % Open Tray
¦ Upper Header
~ Lower Header
~ Both Headers
1.5
1.0
150
110
130
70
30
L/G (gal/macf)
Figure 4. Effect of Absorber Configuration on Tray AP
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¦ Formate, I.O.
~ DBA, F.O.
0 500 1000 1500 2000 2500 3000 3500 4000
Additive Concentration, ppm
Figure 5. Effect of Formate (inhibited oxidation) and DBA
(forced oxidation) on the S02 Removal Efficiency
Expressed in Terms of RTU
/
?~
¦ Formate, 132 L/G
~ DBA, 132 L/G
~ Formate, 66 L/G
« DBA, 66 L/G
1000 2000 3000
Additive Concentration (ppm)
4000
Figure 6. Effect of L/G on S02 Removal Efficiency with
Formate Addition (inhibitied oxidation) and DBA Addition
(forced oxidation)
6
5
4
3
2
1
0
0 500 1000 1500 2000 2500 3000 3500 4000
Formate Concentration (ppm)
B
¦
¦ ~
# ~
. D
1°
¦ Formate, 2000 ppm
~ Formate, 4000 ppm
Figure 7. Effect of Inlet S02 Concentration on S02
Removal Efficiency (as RTU) with Formate Addition
Under Inhibited Oxidation Conditions
-------
¦ L/Gx 132, 700 ppm Formate
~ UG=66, 3800 ppm Formate
94 95 96 97 98
Limestone Utilization (%)
99
100
Figure 8. Effect of Limestone Utilization on S02 Removal
Efficiency with Formate Addition (inhibited oxidation)
¦ Filter Cake
~ Thickener UA
9
8
7
6
5
4
3
2
1
500 1000 1500 2000
Formate Concentration (ppm)
2500
Figure 9. Effect of Formate Addition on Solids Dewatering
Properties Under Inhibited Oxidation Operation
5
~ Formate inhibited Oxidation
¦ DBA Forced Oxidation
4
3
2
1
0
5000
0
1000
2000
Liquor Organic Acid (ppm)
3000
4000
Figure 10. Non-Soiution Losses for Organic Acid Tests
7000
~ Pilot & Mini-Pilot — DBA Forced Oxidation
~ Mlnl-Pllot — Formate Inhibited Oxidation
O Pilot — Formate Inhibited Oxidation
¦ Mlnl-Pllot — Formate Forced Oxidation
6000
5000
4000
3000
2000
1000
0
1
2
3
5
4
Relative Non-Solution Lose
Figure 11. Comparison of Non-Solution Loss Between
HSTC Test Blocks
-------
Intentionally Blank Page
3A-42
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RESULTS OF FORMATE ION ADDITIVE TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
Miriam Stohs
Steve Sitkiewitz
Radian Corporation
8501 N. Mopac Boulevard
Austin, Texas 78759
David R. Owens
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94303
Preceding page blank
3A-43
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Intentionally Blank Page
3A-44
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RESULTS OF FORMATE ION ADDITIVE TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
ABSTRACT
This paper presents the results of a two-part test program conducted on the 0.4-MWe
mini-pilot wet limestone FGD system at the Electric Power Research Institute's
(EPRI) High Sulfur Test Center (HSTC). The primary objectives of the tests were to
evaluate the effects of the formate ion on FGD system operation and performance and
to measure the formate consumption rates for a variety of operating conditions.
Tests were run under natural-, inhibited-, and forced-oxidation conditions.
Results are presented which show how system performance varied with formate ion
concentrations up to 4500 ppm. Other independent test variables included recycle
slurry pH, process liquor chemistry, limestone grind, and reaction tank volume.
Process performance results include the effects of formate on S02 removal effi-
ciency, limestone utilization, sulfite oxidation, and waste solids properties.
These results show that significant enhancement of S02 removal efficiency can be
achieved at relatively low formate concentrations for a wide range of test condi-
tions. Total formate consumption results are presented along with estimates of the
relative losses attributable to the three primary consumption mechanisms--vapori-
zation, coprecipitation, and chemical degradation. In the mini-pilot tests, the
lowest consumption rates were measured when formate was used in combination with
the thiosulfate ion (i.e., under inhibited-oxidation conditions), while the highest
consumption rates were measured under forced-oxidation conditions.
Preceding page blank
3A-45
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RESULTS OF FORMATE ION ADDITIVE TESTS
AT EPRI'S HIGH SULFUR TEST CENTER
INTRODUCTION
The use of organic acid additives is becoming well established as a means of
improving the S02 removal efficiency in wet limestone FGD processes. For a number
of years, the Electric Power Research Institute (EPRI) has sponsored a research
program to understand the fundamental chemistry involved in additive use and to
translate this understanding into the practical application of additives to wet FGD
systems. EPRI's research is aimed at improving FGD system performance in terms of
both operating efficiency and reliability while decreasing O&M costs. The focal
point for this research program is the High Sulfur Test Center (HSTC), EPRI's
research facility for environmental control technology related to the combustion of
high-sulfur coals.
Organic additives were originally added to FGD scrubbing slurries to compensate for
underdesigned systems which could not otherwise meet emissions requirements. How-
ever, to comply with the 1990 Clean Air Act Amendments, some utilities may opt to
add an organic additive to enhance the removal efficiencies in their existing FGD
systems and thereby generate excess S02 removal credits. Furthermore, based on the
favorable economics, the use of additives may soon be incorporated into new system
designs.
Interest in the use of formate in the U.S. stems primarily from the desire to
identify alternatives to the use of dibasic acid (DBA), which is currently the most
widely used organic acid additive. Concern exists over both the long-term avail-
ability of DBA and the need to ensure that organic additive prices remain compe-
titive. Interest in formate has also increased as a result of the introduction
into the North American market of the Saarberg Holter Umwelltechnik (SHU) forced-
oxidation process, which includes the addition of formic acid as an integral part
of the process (I).
3A-46
-------
This paper presents the results of a two-part test program which evaluated the use
of the formate ion to enhance S02 removal efficiency in a wet limestone FGD system.
The tests were conducted on the 0.4-MWe mini-pilot system at the HSTC, which is
located at New York State Electric and Gas Company's Kintigh Station in Somerset,
New York. The overall goal of this research was to develop data that would allow
the utility industry to make more informed decisions about the use of this addi-
tive. The first part of the test program involved formate tests under inhibited-
and natural-oxidation test conditions, while the second phase of testing was per-
formed under forced-oxidation conditions. The detailed results from the inhibited-
and natural-oxidation tests were reported previously (2). This paper contains a
summary of these earlier test results and compares them to the forced-oxidation
test results to provide a complete review of the information assembled to date.
BACKGROUND
Formate ion is an additive which can be used in relatively low concentrations (500
to 5000 ppm) to improve the S02 removal efficiency of a limestone FGD system. At
typical slurry pHs, the formate ion functions as a source of liquid-phase alkalin-
ity, thereby lowering the liquid-film resistance to mass transfer which effectively
increases the driving force for S02 removal.
The operating costs associated with the use of formate will be largely dependent on
the addition rate required to maintain the desired additive concentration. The
required feed rate represents the total consumption of formate in the FGD system,
including both solution and non-sol.ution losses. Solution loss is simply the loss
of formate in the liquor entrained with the waste solids and in any other liquor
blowdown stream. Non-solution losses can result from vaporization of the acid into
the flue gas, from coprecipitation and/or adsorption on the waste solids, or by
chemical degradation. In the interest of assessing the relative cost-effectiveness
of the formate additive, one of the primary objectives of the mini-pilot tests was
to determine the effects of the various process conditions on the formate ion con-
sumption rate.
The formate ion can be added to FGD systems both as a 90% to 95% solution of formic
acid or as the highly soluble sodium salt. In the natural- and inhibited-oxidation
tests, formate was added as the sodium salt since this is the lowest cost source of
the additive. (On a molar basis, formic acid is approximately 1.5 times more
3A-47
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expensive than sodium formate.) Furthermore, in many F6D systems, sodium would be
a desirable additive since it serves to increase the sulfite ion concentration,
thereby providing another source of dissolved alkalinity. However, formic acid
addition is more appropriate for F6D systems where the presence of dissolved sodium
is undesirable, such as a forced-oxidation system which produces wall board-grade
gypsum. Therefore, in the forced-oxidation mini-pilot tests, formic acid was used
as the source of the formate ion.
TEST OBJECTIVES AND APPROACH
The specific objectives of the formate additive test program focused on two areas:
1) the effect of the formate ion on FGD process performance; and 2) the impact of
FGD process variables on the effectiveness and the consumption rate of formate.
The test program was divided into two phases, with natural- and inhibited-oxidation
tests conducted in the first phase and forced-oxidation tests in the second phase.
Test variables examined in both phases included formate ion concentration, pH, and
chloride concentration. Two additional variables evaluated in the forced-oxidation
test block were limestone grind and reaction tank volume. The ranges of the vari-
ables tested in each phase are presented in Table 1. Operating conditions which
remained constant in each phase included liquid-to-gas ratios of about 80 gal/macf,
a flue gas flow rate of 750 scfm, an inlet gas S02 concentration of 2500 ppm, an
inlet 02 concentration of 6% to 7% (as received), and a slurry solids concentration
of 12 weight percent.
The configuration of the mini-pilot system during the formate additive tests is
shown in Figure 1. A detailed description of this system was presented previously
(3). The general procedure for conducting each test was to establish the desired
test conditions, allow the system to operate for three solid-phase residence times,
and then collect three sets of solid- and liquid-phase samples to document process
performance under steady-state test conditions. Throughout each of the tests,
process data, such as flue gas flow rate, inlet and outlet S02 concentrations, and
reaction tank pH, were collected by an on-line data acquisition system.
3A-48
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TEST RESULTS
This section summarizes the key results from the mini-pilot formate additive tests
and presents information which can be used by utilities that are interested in
evaluating the use of formate in their own FGD systems. Effects of the formate ion
on process operation and performance are discussed first, followed by the formate
ion consumption rate results.
Effects of Formate on Process Performance
Using the process and analytical data collected for each test, the following pro-
cess performance parameters were determined for each test condition: S02 removal
efficiency, sulfite oxidation, limestone utilization, and waste solids properties.
Significant results in each of these areas are discussed below. Selected results
from individual tests are presented in Table 2 for illustration purposes.
S0: Removal Efficiency. The effect of formate concentration on S02 removal effi-
ciency in the mini-pilot absorber is shown in Figure 2. As these data represent a
wide range of test conditions, it appears that the S02 removal efficiency was
essentially a function of pH and formate ion concentration in the mini-pilot tests.
As can be seen, the benefit of increasing the formate concentration rapidly dimin-
ishes above about 1000 ppm formate. This occurs because a limit is reached where
the S02 removal rate is controlled by the gas-phase mass transfer rate, and further
increases in the liquid-phase alkalinity (i.e., formate or pH) do not have any
measurable effect on removal. It should be noted that the optimum formate concen-
tration is very dependent on the design of the absorber. However, it is currently
possible to obtain an estimate of the optimum formate concentration for a given
system with the use of EPRI's FGD PRocess Integration and Simulation Model
(FGDPRISM).
Sulfite Oxidation. Figure 3 shows the effect of formate concentration on sulfite
oxidation under natural-oxidation test conditions. As shown, formate inhibits
sulfite oxidation, and this effect appears to be directly related to the dissolved
formate concentration. However, formate should not be considered as an alternative
to sulfur (thiosulfate) for inhibiting oxidation, since sulfur is more effective
and less expensive than formate as an oxidation inhibitor. Furthermore, as dis-
cussed later in this paper, the presence of thiosulfate can significantly reduce
3A-49
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the consumption rate of the formate additive. While there was no measurable effect
of formate on the oxidation level in the inhibited-oxidation tests, it was qualita-
tively observed that a higher 0:S ratio was required in the forced-oxidation for-
mate tests relative to the baseline test. However, since the mini-pilot system is
not representative of full-scale systems with respect to oxidation air require-
ments, it is not appropriate to extrapolate this result to a full-scale system.
Limestone Utilization. The results in Table 2 show that, under different test
conditions, the limestone utilization improved, stayed the same, or declined in the
presence of formate. Therefore, no general conclusion can be made about the effect
of formate addition on limestone utilization. In all of the natural-oxidation
tests, a slight improvement in utilization was measured with formate addition. It
is unclear why the presence of formate would cause an improvement in utilization.
Because the oxidation levels also decreased significantly relative to the baseline
tests, it is possible that subtle changes in the slurry chemistry caused the im-
provement in utilization. In contrast to this result, a slight decline in utiliza-
tion was measured in both inhibited- and forced-oxidation tests (i.e., at constant
oxidation levels), although no change was detected in the coarse-grind, forced-
oxidation test. Since the average pH in the absorber is higher when an organic
buffer is used, the driving force for limestone dissolution in the absorber will be
less, and this may have caused the lower utilization in these tests.
Waste Solids Properties. As with limestone utilization, the data in Table 2 indi-
cate that formate addition can result in an improvement in or a deterioration of
waste solids settling and dewatering properties, depending on the system's oper-
ating mode. Based on these test results, it appears that the waste properties may
be affected by formate both indirectly and directly. Formate addition can indi-
rectly affect the solids by causing changes in the limestone utilization and/or
sulfite oxidation, both of which can affect the waste solids properties. Copre-
cipitation of formate may directly affect waste solids properties by changing the
calcium sulfite hemihydrate crystal structure. In terms of FGD system operation,
utilities considering the use of formate, particularly in natural- and inhibited-
oxidation systems, should adopt a cautious approach to potential changes in solids
dewatering properties.
3A-50
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Formate Consumption Results
To maintain a given formate ion concentration, formate must be fed to the FGD sys-
tem at the same rate that formate is lost from the system. As discussed earlier,
the formate loss rate includes both solution and non-solution losses. The solution
loss is simply the formate lost with the waste liquor. The non-solution loss is
the difference between the formate feed rate and the solution loss. As the solu-
tion loss rate is simply a function of the formate concentration and the solids
dewatering properties (i.e., the liquor loss rate), the emphasis in the following
discussion will be on the effects of operating conditions on the formate non-
solution loss rate.
Figure 4 shows the formate non-solution loss rate as a function of the formate ion
concentration. As can be seen, the highest loss rates were measured in the forced-
oxidation tests. These losses were about a factor of 2 higher than those measured
in the natural-oxidation tests and about a factor of 4 higher than the rates mea-
sured in the inhibited-oxidation tests. One point to consider is that the formate
solution losses were considerably lower in the forced-oxidation tests due to the
superior dewatering properties of gypsum. In the natural- and inhibited-oxidation
tests, the solution loss rate accounted for 20% to 30% of the formate feed rate,
while in the forced-oxidation tests, the solution losses represented an average of
6% of the feed rate.
In a number of the formate tests, measurements were made of the solid- and vapor-
phase formate concentrations which allowed estimates to be made of the relative
losses of formate by coprecipitation, vaporization, and chemical degradation (by
difference). These results are presented in Table 3. Included in this table are
results for another mini-pilot test block which tested formate addition under con-
ditions which simulated an FGD system for a lignite-fired boiler (4). Test condi-
tions included formate concentrations of 500 to 2000 ppm, thiosulfate concentra-
tions of 0 to 2000 ppm, an adiabatic saturation temperature of 140*F, slurry pHs of
5.9 to 6.0, an L/G of 54 gal/macf, an inlet S02 concentration of 1400 ppm, and a
flue gas 02 content of 10%. While the results of these tests will not be discussed
in this paper, the formate consumption results were included in Table 3 to illu-
strate the significant effects of process conditions on the formate consumption
mechanisms. Significant results pertaining to the effects of operating conditions
on the relative loss rates measured in the formate test block are discussed below.
3A-51
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Coprecipitation. The effect of slurry chemistry on the formate coprecipitation
rate under natural- and inhibited-oxidation conditions was discussed previously
(2). A relationship was developed which describes the normalized formate coprecip-
itation rate as a function of the calcium formate activity product. These curves
are shown in Figure 5. Several observations can be made from these data. First,
above calcium formate activity products of about 2 x 104 mM3, the formate coprecip-
itation rate is essentially independent of the calcium formate activity product.
This result implies that some factor other than the calcium or formate concentra-
tion limits the rate of coprecipitation. One possibility is that the calcium sul-
fite crystal becomes saturated with calcium formate.
Second, at low calcium formate activity product values, the coprecipitation rate
depends only on the concentrations of calcium and formate in the scrubbing liquor.
Therefore, in low-calcium systems, the consumption rate of formate will increase
with increasing formate concentration. Finally, the tests conducted with thiosul-
fate had lower coprecipitation rates than the rates observed in similar tests with-
out thiosulfate. This result implies that thiosulfate can be used in conjunction
with formate to reduce the formate coprecipitation rate, the formate consumption
rate, and the cost for using formate as an additive.
The coprecipitation results discussed above are of considerable interest to utili-
ties considering formate addition to a natural- or inhibited-oxidation FGD system.
This is because this loss mechanism can represent the majority of the non-solution
loss rate under these conditions. However, in the forced-oxidation test, coprecip-
itation was not a significant formate loss mechanism. Apparently very little, if
any, calcium formate is incorporated into the calcium sulfate crystal matrix.
Vaporization. The formate loss rate due to vaporization was also previously
discussed in considerable detail (2). Vapor-phase concentrations are shown as a
function of the liquid-phase formate ion concentration in Figure 6. The scatter in
the data is to be expected, since this rate was shown to be a relatively complex
function of the formate concentration, reaction tank pH, absorber pH, and tempera-
ture. It is significant to note then, that the results in Table 3 show that vapor-
ization losses represented approximately the same percentage of the non-solution
loss rate under a wide range of test conditions.
3A-52
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Chemical Degradation. The majority of the non-solution losses in the forced-
oxidation tests were caused by chemical reaction, or degradation, of formate at the
slurry chemistry conditions. As formate is the smallest carboxylic acid (HCOOH),
the oxidation products of formate are simply carbon dioxide and water. Therefore,
unlike the components of DBA (i.e., adipic, glutaric, and succinic acids), the
oxidation of formate does not result in the production of lower molecular weight
species which may still have buffering properties capable of enhancing the S02
removal efficiency.
In the forced-oxidation tests, there was no measurable effect of pH, chloride con-
centration, or limestone grind on the formate consumption rate. However, in the
high reaction tank volume test, the formate consumption rate did increase in direct
proportion to the reaction tank volume. In addition, liquid-phase trace metals
analyses suggested a connection between the manganese concentration (not a con-
trolled variable) and the formate non-solution loss rate. This relationship was
previously observed by Lee and Rochelle (5).
CONCLUSIONS
A number of significant results have been obtained from EPRI's continuing research
efforts to improve FGD system reliability and reduce operating costs through the
use of additives. In particular, the mini-pilot formate additive test results have
some practical uses for utilities considering the use of this additive to enhance
the S02 removal efficiencies of their FGD systems. Significant results of the
mini-pilot tests can be summarized as follows:
# The use of formic acid in a forced-oxidation system allows a high
S02 removal efficiency to be achieved at a relatively low formate
ion concentration and reaction tank pH. In addition, nearly com-
plete limestone utilization is achieved even with a coarse limestone
grind.
# The limestone utilization and waste solids properties can improve or
deteriorate as a result of formate addition. At a constant calcium
concentration, however, the magnitude of these effects should not
significantly affect process performance.
# Sulfite oxidation may be inhibited if formate is added to a natural-
oxidation system. Utilities considering the use of formate should
therefore be aware of the potential for significant changes 1n lime-
stone utilization and/or waste solids properties which may result if
the system becomes subsaturated with respect to gypsum.
3A-53
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• Higher non-solution loss rates of formate should be expected in a
forced-oxidation system, while the loss rates in an inhibited-
oxidation system will be lower than in a natural-oxidation system
at similar operating conditions.
• In natural- or inhibited-oxidation systems, formate coprecipitation
losses will be a function of the calcium formate activity product.
At high activity product values, coprecipitation losses are essen-
tially independent of the calcium and formate concentrations, while
at low activity product values, coprecipitation losses are propor-
tional to the calcium concentration and the calcium formate activity
product.
• The loss rate of formate due to vaporization represented a rela-
tively constant percentage of the total non-solution loss rate for
three significantly different operating modes. Measured vapor-phase
formate concentrations ranged from 1 to 8 ppm for a wide range of
formate concentrations and slurry chemistry conditions.
• The data presented in this paper can be used to make rough estimates
of the formate consumption rate by coprecipitation and vaporization.
Caution should be exercised, however, if data in this paper are used
to estimate formate losses by chemical degradation, because the
factors affecting this loss mechanism are complex and difficult to
quantify from the mini-pilot test data.
• Chemical degradation losses of formate under forced-oxidation con-
ditions appear to be related to the presence of trace species, in
particular manganese. This relationship will be investigated in
greater detail in future tests.
• The mini-pilot test results will be used to modify existing correla-
tions in FGDPRISM and thereby allow more accurate estimates to be
made of the costs and benefits of using formate in a full-scale
system.
ACKNOWLEDGMENTS
The work reported in this paper is the result of research carried out at EPRI's
High Sulfur Test Center (HSTC) in Somerset, New York. We wish to acknowledge the
support of the HSTC cosponsors--New York State Electric and Gas, Consol, Empire
State Electric Energy Research Corporation, Electric Power Development Company,
Ltd., and the U.S. Department of Energy. The cosponsors provide valuable technical
review of the work in progress, as well as funding HSTC operations.
3A-54
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REFERENCES
1. Glamser, J., et al. "Advanced Concepts in FGD Technology: The SHU Process
with Cooling Tower Discharge," Journal of the Air Pollution Control Associa-
tion. Vol. 39, No. 9, September 1989, pp. 1262-1267.
2. Burke, J.M., et al. "Results of Sodium Formate Addition Tests at EPRI's High
Sulfur Test Center and Associated Electric Cooperative's Thomas Hill Unit 3
FGD System," 1990 S0: Control Symposium, cosponsored by the U.S. EPA/EPRI, New
Orleans, LA, May 8-11, 1990.
3. Moser, R.E., et al. "Results of Wet FGD Testing at EPRI's High Sulfur Test
Center," Presented at the EPA/EPRI First Combined FGD and Dry S02 Control Sym-
posium, St. Louis, MO, October 25-28, 1988.
4. Hargrove, O.W., et al. "Results of an Investigation to Improve the Perfor-
mance and Reliability of HL&P's Limestone Station FGD System," prepared for
the 1991 SO, Control Symposium, cosponsored by the U.S. EPA/EPRI, Washington,
D.C., December 3-6, 1991.
5. Lee, Y.J. and G.T. Rochelle. "Oxidative Degradation of Organic Acid Conju-
gated with Sulfite Oxidation in Flue Gas Desulfurization: Products, Kinetics,
and Mechanism," Environ. Sci. Techno!., Vol. 21, No. 3, 1987, pp. 266-272.
Table 1
RANGES OF TEST CONDITIONS FOR FORMATE TESTS
Oxidation Mode
Test Condition
Natural
Inhibited
Forced
Formate Concentration (ppm)
0-4600
0-4200
0-2000
pH
5.0, 5.5
5.5
4.6, 5.0, 5.5
Dissolved Calcium Concentration (mM)
20, 140
140
75, 140, 400
Chloride Concentration (mM)
250, 600
600
400, 1000
Thiosulfate Concentration (ppm)
--
1000
--
Limestone Grind (% <325 mesh)
90
90
70, 90
Reaction Tank Volume (gal)
490
490
490, 710
3A-55
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Table 2
SELECTED PROCESS PERFORMANCE RESULTS
Oxidation
Mode
Natural
Slurry
Chemistry
Baseline^
Formate
(ppm)
0
4300
Oxidation
<*)
14
8
Limestone
Utilization
(*>
89
92
Centri fuge
Product
(wt.% solids)
57
64
Th-ickener
Unit Area
(ft /ton/day)
26
33
Baseline,
pH 5.0
Low Calcium^
0
4200
0
4500
20
8
22
7
97
98
92
97
59
58
53
62
26
24
45
22
Inhibi
ted'
Baseline^
0
1100
4200
<3
<3
<3
93
92
91
74
71
71
2
3
12
Forced
Baseline
Baseline,
pH 5.5
Baseline,
Coarse Grind^
0
1700
0
800
2000
0
800
100
100
100
100
100
100
100
99
98
97
96
95
97
97
78
79
78
77
78
78
75
Natural- and inhibited-oxidation baseline chemistry included a slurry pH of 5.5, 140 mM Ca, and a limestone grind
of 9OX <325 mesh.
^Low-calcium chemistry included a slurry pH of 5.5, 20 mM Ca, and a limestone grind of 90% <325 mesh.
^By addition of 1000 ppm thiosulfate.
i
Forced-oxidation baseline chemistry included a slurry pH of 5.0, 75 mM Ca, and a limestone grind of 90% <325 mesh.
570X <325 mesh.
3A-56
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Table 3
FORMATE ION CONSUMPTION MECHANISMS
Test Type
Natural/Inhibited
Forced Oxidation
HL&P Simulation2
Formate Loss Rate as a Percent of Non-Solution Losses
CoprecipitationVaporizationChemical Degradation1
72-100
<5
44-66
9-22
12-17
10-27
0-20
78-88
20-43
Calculated by difference.
See text for test conditions.
15,000 actm
From NYSEG s
Kintigh Station
HSTC Reverse Gas
Fabric Filter
SOi Spiking
DuPont 460
Photometric
SO! Analyzer
1
'
Flue
Gas
Heater
TRCI
Horizontal
Centrifuge
Waste
Sludge
To
Disposal
Recyded
Process
liquor
Return To
Kintigh Station
Flue Qas To
Pilot System
Flow Meter
Vanable Speed
Mini-Pilot Booster Fan
AAAAAA
w w w w w \
Flue Gas
Quench
18 Diameter
Mini-Pilot
Absorber
Additive
Feed
Tank(s)
Absorber
Feed Tank
Limestone
Slurry
Figure 1. Schematic of HSTC Mini-Pilot System
3A-57
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«j
>
o
E
v
GC
100
_ 90
CM
o
V)
80
70
60
-
Q
<
C
/m ym
or S •
/ m/A
/ /
/ /
DH 5.5
/ /
o Baseline Chemistry
/ /"
~ Inhibited Oxidation
/ /
a Forced Oxidation
~ /
/
DH5.Q
A /
• Baseline Chemistry
/
¦ Forced Oxidation
; I
a F.O., Coarse Grind
—i—i—i.. i i i , i , i , i
, 1,1,1,1,
1000 2000 3000
HCOOH (ppm)
4000
5000
Figure 2. Effect of Formate on SO, Removal Efficiency
30
25 "
^ 20
c
S 1 5
a
TJ
X
O
1 0 -
o o
J I I I I I L
o Baseline Chemistry
¦ Baseline Chemistry, pH 5.0
& Low Calcium Chemistry
-I I L.
¦o
I , I . I . I
1000 2000 3000
HCOOH (ppm)
4000
5000
Figure 3. Effect of Formate Concentration on Sulfite Oxidation
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Figure 4. Formate Non-Solution Loss Rates
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Calcium Formate Activity Product (mM3)
Figure 5. Formate Coprecipitation versus Calcium Formate Activity Product
3A-59
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-
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Figure 6. Vapor-Phase Formate Concentrations
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FGDPRISM, EPRI'S FGD PROCESS MODEL -
RECENT APPLICATIONS
J. G. Noblett, Jr.
D. P. DeKraker
Radian Corporation
8501 MoPac Boulevard
Austin, TX 78759
R. E. Moser
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94303
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Intentionally Blank Page
3A-62
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FGDPRISM, EPRI'S FGD PROCESS MODEL -
RECENT APPLICATIONS
ABSTRACT
Version 1.0 of EPRI's FGD computer simulation model, FGDPRISM (Flue Gas Desulfuri-
zation PRocess Integration and Simulation Model) was released in April 1991, and an
update, Version 1.1, was released in October 1991. This paper briefly describes
the FGDPRISM computer model and its current and potential uses. The emphasis of
the paper, however, is on two recent applications. The first is the calibration of
the model using test data from LG&E's Mill Creek Unit 3 FGD system, and the subse-
quent use for redesign of their Unit 4 FGD system absorber. The second application
is an analysis of laboratory- and pilot-scale data to examine the model's accuracy
in predicting the effects of chlorides on S02 removal. Finally, the future direc-
tion of the FGDPRISM development effort is discussed.
Preceding page blank
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FGDPRISM, EPRI'S FGD PROCESS MODEL -
RECENT APPLICATIONS
BACKGROUND & SUMMARY
The Electric Power Research Institute (EPRI) has funded the development of a state-
of-the-art process simulation model for wet lime and limestone flue gas desulfur-
ization (FGD) systems. This model is called FGDPRISM (Flue Gas Desulfurization
>
PRocess Integration and Simulation Model). FGDPRISM represents the culmination of
many years of laboratory, pilot, and full-scale experience into a tool which can be
used by utilities, vendors, architect and engineering firms, and consultants to
optimize FGD system operations. However, even with this large experience database,
there are areas of FGD chemistry which are not well understood. All users of
FGDPRISM are required to take a training course so that the full capabilities and
limitations of the model are understood before applying the model.
This paper briefly describes the FGDPRISM model, and its capabilities and limita-
tions. The bulk of the paper discusses two recent applications of the model. One
is the use to redesign the absorber of an existing full-scale wet limestone FGD
system. The other is an application of the model to pilot-scale data to ensure
that the predictions with respect to changes in chemistry accurately reflect oper-
ating data. Finally, the future direction of the FGDPRISM development effort is
briefly discussed.
Model Description
FGDPRISM was developed using fundamental engineering principles, so that extrapola-
tions from realms where operating data are available to conditions where data are
not available can be made. Extrapolations of this type are necessary in optimizing
FGD system performance and in the design of new systems. The use of fundamental
chemistry and engineering principles makes this extrapolation much more reliable
3A-64
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than using a "regression" type model, that may only reliably be used within the
range of data taken in developing the model.
F6DPRISM consists of groups of subroutines which are used to model individual unit
operations within an FGD system. There are subroutines which describe the pheno-
mena occurring in the absorber, the reaction tank, the solid/liquid separation
equipment, etc. These unit operations may be assembled in the manner necessary to
simulate different process configurations. However, this would have required a
great deal of training for users to learn the input language, how each subroutine
works, how to specify convergence loops, etc.
To remove this burden from the user, a series of "templates" were developed that
represent the majority of existing wet FGD system configurations. An interface
program was written to prompt the user for the required input data depending on the
template chosen. The interface program then assembles the input data into the
proper format for the FGDPRISM model and writes an input file that is processed by
FGDPRISM. The interface program was written in the EPRIGEMS format, which is a
software standard prepared by EPRI to allow all of the software developed by EPRI
to have the same look and feel.
Model Capabilities
Version 1.0 of FGDPRISM was released in April 1991, and included nine preconfigured
templates. Since that time, the model has been upgraded to include 12 templates,
with several more under development. The latest release, Version 1.1, was issued
in October 1991. The templates that are included in that version are:
1) Spray tower absorber simulation, limestone;
2) Tray tower absorber simulation, limestone;
3) Complete system simulation w/spray absorber, limestone;
4) Complete system simulation w/tray absorber, limestone;
5) System material balance;
6) Reaction or mix tank simulation;
7) Spray tower absorber simulation, Mg-lime;
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8) Tray tower absorber simulation, Mg-lime;
9) Dual-loop system simulation, limestone;
10) Forced-oxidation system simulation for limestone w/spray tower;
11) Forced-oxidation system simulation for limestone w/tray tower; and
12) Equilibrium calculations.
Other templates which are in development at the time of this writing include com-
plete system simulations for the magnesium-assisted lime processes (both spray and
tray towers) and a dual-loop limestone system that will allow reagent addition to
both loops.
FGDPRISM can be used to evaluate laboratory- and/or pilot-scale data, to evaluate
changes to an existing full-scale system (chemical and/or mechanical modifica-
tions), to evaluate proposed system designs, or as a design tool. The use of
FGDPRISM to evaluate pilot data and to investigate chemical or mechanical changes
to an existing system are the most validated modes of operation. For these appli-
cations, the model must first be calibrated to extract the fundamental mass trans-
fer coefficients. Then, once the model is calibrated, extrapolation to alternate
operating conditions such as using an additive (e.g., DBA or formate) or changing
L/G, adding new headers, etc. can be made.
Another application is to use FGDPRISM as a tool to aid in evaluating new system
designs. The model has only been applied to this use a few times. Typical mass
transfer coefficients must be assumed, and the evaluations can only be on a rela-
tive basis, unless adequate data from existing similar designs is provided to allow
model calibration. The application of FGDPRISM to this task should be undertaken
with extreme caution and the use of sound engineering judgement. It is recommended
only for experienced users. Finally, the use of FGDPRISM as a design tool is
envisioned.
Model Availability
FGDPRISM is available at no expense to EPRI-member utilities through the Electric
Power Software Center. Twenty-six member utilities have received FGDPRISM to date.
The model is available for licensing to organizations not eligible for EPRI
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membership, such as F6D system suppliers, architect-engineering firms, consultants,
universities, and government agencies. Eleven third-party licenses have been exe-
cuted through October, as listed below. Due to the model complexity and potential
misuse of the program, attendance at an FGDPRISM training workshop is required
prior to release of the program to any utility or licensee.
Current Licensees of FGDPRISM
Unlimited Use License: ABB Environmental Systems, Inc.
Babcock & Wilcox
G.E. Environmental Services, Inc.
Radian Corporation
30-Day Trial License: Black & Veatch
Burns & McDonnell
Dravo Lime
Gilbert/Commonwealth
Pure Air
Contractor's License: Codan Associates
(for EPRI projects) Sargent & Lundy
The next section of this paper presents the results of two recent applications of
FGDPRISM. One deals with calibration of the model and extrapolation to an alter-
nate system design. The other deals with evaluation of pilot-scale data to ensure
that FGDPRISM correctly predicts the effects of dissolved chloride concentration on
S02 removal, which is a topic of great concern with new systems being specified.
LOUISVILLE GAS AND ELECTRICS MILL CREEK UNIT 3 FGDPRISM CALIBRATION
One of the more recent applications of the FGDPRISM model has been to simulate the
performance of Louisville Gas and Electric's (LG&E) Mill Creek Unit 3 FGD system.
The primary goal of modeling the Unit 3 system has been to calibrate the model so
that it can be used to evaluate the options being considered for redesign of the
Unit 4 system. The data collected for calibration of the model have also provided
valuable information about the accuracy of the model in predicting the effect of
header height on S02 removal.
The Unit 4 scrubbers at the Mill Creek Station have been experiencing reliability
problems. Under normal operation, three pumps are in service; two pumps are mani-
folded together to provide slurry to the lower spray header, and the other pump
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provides slurry to the upper spray header. The manifolded pumps share common
suction and discharge lines. Both the lower and upper level spray pumps are mani-
folded to additional pumps which serve as spares. The manifolded suction and dis-
charge lines, along with the numerous isolation valves associated with these pumps,
contribute to the poor overall reliability.
To improve its reliability, LG&E has decided to rebuild the slurry recycle system.
Several different options for redesigning the system are being considered. These
options are being simulated using the FGDPRISM model; the results of the simula-
tions will show LG&E the S02 removals that can be achieved using each of these op-
tions. This will ultimately enable LG&E to select the most cost-effective approach
for rebuilding the Unit 4 scrubber slurry recycle system.
The data and modeling work have also provided a means to evaluate how well the
model predicts the effect of header height on S02 removal. Tests performed with
different combinations of the four spray headers on the Unit 3 scrubbers provided
information on how header height effects S02 removal. Data from these tests were
then used as a benchmark against which the results of the simulation model were
compared.
System Description
The four absorbers of the Mill Creek Unit 3 FGD system treat the flue gas generated
by a 412-MW coal-fired power plant. The flue gas enters the absorber at the bottom
of the module and is contacted with slurry from four spray levels (three operating)
as the gas rises through the tower. After passing through the spray zone, the flue
gas passes through the mist eliminators and exits the absorber module. The four
absorber modules share two reaction tanks. One reaction tank serves the A1 and A2
modules, and the other reaction tank serves the B1 and B2 modules. There are four
absorber feed pumps per reaction tank. Each of these pumps provides slurry to one
spray level in two absorber modules, i.e., the A1 pump provides slurry to the lower
spray headers in both the A1 and A2 towers.
Data Collection
The data required for calibrating the FGDPRISM model was collected by executing a
series of performance tests during August 1991. The testing focused on measuring
3A-68
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the S02 removal performance of a single module (the A1 module) as a function of
operating pH and number of headers in service. Additional tests were performed
using high concentrations of DBA. The DBA tests were designed to measure the S02
removal that could be achieved with an excess of alkalinity present in the absorber
slurry. During each of the performance tests, the inlet and outlet flue gas S02
concentrations and flue gas flow rates were measured, samples of the scrubber
slurry were collected, scrubber pH was measured and recorded, and DBA concentra-
tions were measured (during DBA tests only). The slurry flow rate of each pump was
measured once during the test period using a magnetic flow meter. The pump flows
measured were the total flow being delivered by each pump. It was not possible to
measure the flow going into an individual module. During the modeling, it was
assumed that the flow was distributed equally to each tower.
The results of the performance testing are summarized in Figure 1. The S02 removal
testing showed nothing unusual. As expected, increasing pH, header height, and L/G
all tend to increase the S02 removal in the absorber.
Calibration of the Model
To provide the most accurate results, FGDPRISM must be calibrated to the system
being simulated. The calibration entails adjusting certain model input parameters
to account for those aspects of the FGD system performance that are not predicted
by the model. Specific areas that calibration of the model addresses include gas-
liquid surface area, gas-liquid maldistribution, and limestone reactivity. A brief
discussion of each of these factors is presented below.
The model makes a prediction of the gas-liquid surface area by performing what are
called droplet trajectory calculations. In essence, these calculations plot the
trajectory of a slurry droplet as it passes through the absorber and determine the
amount of surface area contributed by the droplet. Thus, by performing these cal-
culations for the slurry being sprayed from each nozzle within the tower, the total
gas-liquid surface area can be calculated. These calculations cannot, however, be
directly verified as there is no way to actually measure the surface area of the
spray in the absorber. An effect related to gas-liquid surface area is gas-liquid
distribution within a tower. Poor distribution can affect scrubber performance,
3A-69
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but 1t is beyond the model capabilities to predict the gas-liquid distribution
within a particular spray tower.
To account for the effects of droplet surface area and gas-liquid distribution,
calibration factors are introduced into the model. The calibration factors which
account for mass transfer effects (such as gas-liquid surface area and distribu-
tion) in the FGDPRISM model are film thicknesses.
The model uses the two-film mass transfer theory to calculate mass transfer within
the absorber module. The assumption of the two-film mass transfer theory is that
the species being transferred (S02 in this case) diffuses from a well-mixed bulk
through a stagnant gas film to the gas-liquid interface, then through a stagnant
liquid film to a well-mixed liquid bulk. More information about how the model per-
forms the mass transfer calculations was provided in a 1990 FGD Symposium paper
(I). The key point to understand is that film thicknesses used by the model are
entered by the user when calibrating mass transfer characteristics of the model.
The substantial amount of performance data collected from the Hill Creek Unit 3
Station during the week of testing at the site provided enough information to allow
an especially thorough calibration of the model to be made. A key piece of infor-
mation was provided by the tests performed with high DBA concentrations. In these
cases, the DBA concentration was high enough that there was always an excess amount
of alkalinity present in the slurry. Thus, the S02 removal achieved by the scrub-
bers in the DBA tests was limited only by the mass transfer through the gas film
(the excess alkalinity meant that there was no resistance to S02 removal within the
spray droplets themselves). When mass transfer is limited by the gas film only,
the S02 removal (as measured in terms of transfer units) is proportional to the
surface area of the sprays.
Thus, the test data showing S02 removal as a function of headers in service at high
DBA concentrations provided information to adjust the surface area used by the
model to accurately reflect what actually occurred in the spray tower. Adjusting
the surface area was the first step in the calibration of the model.
The second step in the calibration of the model was to adjust the gas- and liquid-
film thicknesses and limestone rate dissolution constant to match the S02 removal
3A-70
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for the test cases in which all four headers were in service. These calibration
factors take Into account gas-liquid maldistribution and limestone reactivity. The
gas- and liquid-film thicknesses determined in the model calibration were 32 and
4.1 microns, respectively. The limestone dissolution constant was 7 moles/sec-m2
for the cases without DBA.
The results of the calibration are shown in Figure 2. In general, these results
show that it was possible to calibrate the model to provide reasonably accurate
predictions of the calibration data points.
Application of the Model Results to Mill Creek Unit 4's Redesign
Evaluation of different options for rebuilding the scrubber slurry recycle system
is currently under consideration. The basic design criterion is that the scrubbers
need to be able to achieve a minimum S02 removal of 85%. Some of the options that
have been considered are described below.
The first stage of the evaluation has been to determine the L/G necessary to
achieve the required removal. A curve showing predicted S02 removal as a function
of L/G, developed using the calibrated model, is shown in Figure 3. This curve
shows that an L/G of about 90 is required to achieve 85% removal. Since the pri-
mary goal of redesigning the scrubbers is to improve reliability, LG&E would like
to be able to achieve the required S02 removal with two pumps in service and with
one available as a spare. However, to achieve a L/G of 90 with two pumps, very
large pumps (which have not yet been proven in FGD applications) would be required.
A second option being considered is using three pumps to achieve a L/G of 90. With
this arrangement, there would not be a spare. The Mill Creek Unit 4 absorbers are
short (they were originally packed towers), and there is no room for a fourth
header. The FGDPRISM predictions for the level of DBA that would be required to
maintain compliance with only two pumps in service are shown in Figure 4. This
graph shows that it would be feasible to use DBA to keep the system in compliance
while maintenance is being performed on a pump. From 500 to just over 1,000 ppm
DBA would be required, depending on which header was out of service. This option
has the added benefit that pumps similar to those in use on other scrubbers at the
Mill Creek facility can be used.
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The evaluation of Mill Creek Unit 4's redesign is still in progress, and other
options may still be considered. The preliminary results of the modeling effort
do, however, suggest ways in which the slurry recycle system can be redesigned to
significantly improve the reliability of the Mill Creek Unit 4 FGD system.
Effect of Header Height
One of the objectives of the work at Mill Creek was to determine how well the model
predicts the effect of header height. Simulations with different headers in ser-
vice were performed to compare the predicted results (using calibration parameters
based on four-header operation) with those actually measured at Mill Creek. The
results are shown in Figures 5 and 6 for different two-header combinations. These
results show that the model does a good job of predicting the S02 removal for the
high pH and DBA cases. However, it slightly underpredicts the S02 removal at lower
pHs. Improving the ability of the model to make these predictions is an area of
ongoing development.
It should be noted that the surface areas predicted by FGDPRISM for operation with
less than four headers in service were adjusted to fit the data for operation with
DBA. The surface areas predicted by FGDPRISM were much less than the adjusted sur-
face areas. This indicates that a modification to the droplet trajectory calcula-
tions is necessary to allow FGDPRISM to accurately predict changes in S02 removal
resulting from having different combinations of headers in service. Another possi-
bility is that the film thicknesses (i.e., mass transfer coefficients) may have to
be varied with droplet residence time. Efforts to investigate these modifications
are currently underway.
Although the area adjustment approach allowed accurate prediction for high pH oper-
ation, there is still a problem at lower pHs. This is an indication that limestone
dissolution is actually occurring faster than predicted. The mechanism of lime-
stone dissolution is an area that has been under investigation by EPRI. The con-
tinued development of a refined technique for modeling limestone dissolution is in
progress.
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EFFECTS OF CHLORIDES ON S02 REMOVAL
An Important aspect of recent FGD system designs has been the concentration of
chlorides in the recirculating slurry. To ensure that FGDPRISM correctly accounts
for the effects of chlorides on S02 removal, model predictions were compared to
laboratory- and pilot-scale data. Some changes in the FGDPRISM database and in the
limestone dissolution rate form were required to match laboratory data and oper-
ating data from the Shawnee and HSTC pilot-scale wet limestone spray tower systems.
Laboratory-Scale Predictions
The first step in this analysis was to compare FGDPRISM predictions for S02 vapor
pressure as a function of sulfite and chloride concentrations. Background solu-
tions containing both calcium chloride and magnesium chloride were investigated.
High chlorides can be observed in FGD systems in two ways. First, high inlet gas
HC1 concentrations (>10 to 20 ppm) can concentrate to significant liquid-phase
chloride concentrations. Secondly, a very tight water balance can concentrate even
low levels of HC1 absorbed from the flue gas to high concentrations in the scrubber
liquid. If the limestone reagent has significant levels of available magnesium,
then the chloride will primarily be neutralized in the liquid phase by magnesium
ions. If the limestone reagent does not contain significant levels of available
magnesium, then the chloride will be neutralized in the liquid phase by calcium
ions. Therefore, the vapor pressure of S02 above solutions of both calcium chlor-
ide and magnesium chloride is important.
To measure the solubility of S02 as a function of solution composition, a gas
containing 1,770 ppm S02 was bubbled through a solution of known composition until
the outlet S02 concentration was the same as the inlet concentration, indicating
that the solution vapor pressure of S02 was equal to the gas concentration. Then
the liquor was analyzed for sulfite. This type of experiment was conducted for
solutions of CaCl2 and MgCl2 from 0 to about 130,000 ppm chloride. The observed
results, along with results predicted by FGDPRISM, are shown in Figures 7 and 8.
The predictions from FGDPRISM were generated by inputting the background concentra-
tion and specifying the S02 vapor pressure. The model then predicted the dissolved
sulfite concentration. Calculations were initially performed with the original
database, and as shown in the figures, the very low chloride areas matched well,
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but as soon as the chloride concentration increased above a few thousand ppm, the
predicted results were much higher than the observed results. This would result in
the model predicting that S02 was much more soluble at higher chloride concentra-
tions than it actually was. This in turn would result in S02 removal predictions
that were too high.
To correct the predictions, modifications were made to the CaHSO, and HgHSOj ion
pair association constants. The results of the final values are also shown in
Figures 7 and 8. For CaCl2 solutions, the adjusted database results fall almost on
top of the observed values. The adjusted database for MgCl2 solutions does not fit
quite as well as for the CaCl2 solutions, but the values are closer than for the
original database. These modifications should allow FGDPRISM to make better pre-
dictions for S02 mass transfer in the absorber, where a high S02 gas partial pres-
sure is encountered by the recirculating slurry.
Predictions for the Shawnee Pilot FGD System
Once the fundamental data were used to adjust the FGDPRISM ion pair association
constants, the model was calibrated to match low chloride data from the Shawnee
10-MW pilot unit. Then the effects of increasing chloride concentration on S02
removal were predicted by FGDPRISM and compared to operating data.
Four data series were chosen from a two-month test program conducted at the Shawnee
pilot test facility in 1983 (2). Table 1 summarizes the test conditions for each
of the test series. Inlet S02 concentrations of about 2,500 and 4,000 ppm were
tested at L/G ratios of about 40 and 80 gal/Macf. Both fine (95% -325 mesh) and
coarse (80% -200 mesh) limestone grinds were included, and two reaction tank liquid
residence times of 5.6 and 11.2 minutes were also included. For each test series,
chloride levels of less than 1,000 ppm to about 60,000 ppm were achieved by adding
calcium chloride to the scrubber slurry. All four test series held the limestone
reagent ratio at about 1.10 by allowing the pH setpoint to drop as the chloride
concentration increased. The four test series chosen were all natural oxidation.
Figures 9 through 12 show the results of the FGDPRISM model predictions as compared
to the operating data. These figures show the FGDPRISM results using the unmodi-
fied database, with the database as modified from the laboratory results discussed
3A-74
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above, and with the final model configuration including a modified limestone disso-
lution rate expression in addition to the database modifications. It should be
noted that the data points do not result in smooth curves due to slight variations
1n operating conditions, such as reagent ratio and inlet S02. However, the plots
do show the trend in S02 removal as a function of chloride concentration.
In general, the trend in the operating data were that S02 removal decreased with
Increasing chloride concentration in the scrubbing liquor. The predictions using
the unmodified database (top lines of each figure) all show a predicted increase in
S02 removal as chloride concentration increased. The modifications to the database
helped bring predicted removals closer to observed values, but the trend was still
for S02 removal to increase slightly or remain constant as chloride increased.
Further investigation of the data indicated that a decrease in limestone dissolu-
tion across the absorber would be necessary to predict the observed trend in remo-
val. A trial-and-error procedure was used for each data point to vary the lime-
stone dissolution rate constant until the observed removal was obtained. Then, the
rate constant was plotted as a function of calcium concentration and a best-fit
equation was developed. The results of those runs are shown in Figure 13, with the
solid line representing the correlation that was developed. The data could have
been fit to either the calcium or the chloride concentration, since these two
species concentrations varied proportionately. The chloride was increased in the
tests by adding calcium chloride, not by spiking the flue gas with HC1 or tighten-
ing the water balance. Calcium was chosen as the correlating variable to ensure
that the effects on removal in a magnesium chloride environment would be predicted
correctly, since the effects of magnesium chloride and calcium chloride on S02
vapor pressure are different, as noted from the laboratory data.
Model Predictions for the HSTC Pilot FGD System
Next, FGDPRISM was used to make predictions for a series of tests conducted at the
HSTC facility under forced-oxidation conditions. For these tests, the increased
chlorides resulted in increases in both calcium and magnesium concentrations, as
opposed to just calcium in the Shawnee tests. Table 2 summarizes the operating
conditions for the HSTC wet limestone spray absorber FGD system.
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Figure 14 shows the predicted results as compared to the observed S02 removal as a
function of chloride concentration. The upper line in the figure shows the results
using the modified database but without the modified limestone dissolution rate
expression. The removals predicted do not change as chlorides are increased from
about 15,000 ppm to about 80,000 ppm. The predicted results using the limestone
dissolution rate expression modified for increasing calcium concentration, however,
fall almost directly on top of the observed results. The cases were also run with
a similar correlation developed using chloride as the variable instead of calcium
concentration. The predicted removals are much lower than observed. These results
support the choice of calcium as a correlating variable for the adjustment in lime-
stone dissolution instead of chloride.
It can be concluded from these results then that the current version of FGDPRISM is
capable of accurately predicting the effects of increasing liquid-phase chloride
concentration on S02 removal. Both the effects of increased calcium ion and the
effects of increased magnesium ion resulting from higher HC1 in the flue gas or a
tightened water balance can be predicted. Furthermore, the correlation developed
applies to both forced- and natural-oxidation conditions. No data were available
to compare predictions to operation under inhibited-oxidation conditions.
FUTURE DIRECTIONS
Currently, FGDPRISM is being used in a wide variety of applications. It is used in
the reduction and evaluation of pilot data that is collected from EPRI's High Sul-
fur Test Center. It is used by consultants, architect and engineering firms, and
member utilities to evaluate methods for optimizing existing system performance.
It is being used by process vendors to evaluate data from previous designs. It is
very important that the model be used in the manner that it was intended and that
it is not stretched beyond its capabilities. To help ensure this, every organiza-
tion that licenses the model must send at least one person through the training
course which has been conducted periodically since the initial release. Six train-
ing courses were taught by Radian, the model developer, in 1991 with 67 individuals
representing 37 organizations having attended. Additional training courses will be
taught in the coming year.
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Training courses are not the only method of user support, however. A hot-line
support service is provided for licensed users. Anytime a user has a problem,
whether 1t be a simple problem with understanding a particular configuration's
Input screens, or be it a more complex problem, he/she is only a phone call away
from help. If a user's question cannot be answered directly over the phone, then a
team of experienced engineers is available to further research the problem and get
a timely answer. Also, an electronic bulletin board is being established so that
users may call in and leave messages concerning suggestions about improving the
model, additional configuration templates of interest, tips on using the model,
etc. The bulletin board may also be used as a distribution point for any updates
to existing process configurations or for release of new ones.
Technical areas of the model currently targeted for continued development include:
1) Update limestone dissolution methodology to incorporate the latest
developments from laboratory- and pilot-scale test results;
2) Refine the predictions with respect to the effects of tower height (i.e.,
the number of headers in service);
3) Expand the on-screen help facility to provide more detail where
appropriate;
4) Finish and release complete system simulation templates for magnesium-
assisted lime FGD systems;
5) Streamline model convergence techniques to speed up execution;
6) Expand existing templates to allow flexibility for different designs;
7) Refine model predictive capabilities through more comparisons to full-
scale FGD systems; and
8) Other improvements as dictated by user response.
EPRI believes that the model has a great deal of potential for use in research and
for practical applications in optimizing both the designs of new FGD systems and
the operation of existing FGD systems. FGD system designers, consultants, research
organizations, and utilities can all benefit from using the model. It is antici-
pated that the model will evolve to incorporate new research results in the FGD
chemistry area as well as to more accurately simulate problem areas. The program
has only been available for nine months and already one updated version has been
3A-77
-------
issued. With the substantial number of organizations using the program, it is
fairly certain that the model will undergo continuing refinement and improvement.
ACKNOWLEDGMENTS
The work reported in this paper is the result of research carried out in part at
EPRI's High Sulfur Test Center (HSTC) located near Barker, New York. We wish to
acknowledge the support of the HSTC cosponsors: New York State Electric and Gas,
Empire State Electric Energy Research Corporation, Electric Power Development
Company, Ltd., and the U.S. Department of Energy. The cosponsors provide valuable
technical review of the work in progress as well as funding test center operations.
REFERENCES
1. Noblett, James G., Hark J. Hebets, and Robert E. Moser. "EPRI's FGD Process
Model (FGDPRISM)," presented at the EPA/EPRI Symposium on Flue Gas Desulfuri-
zation, New Orleans, LA, May 8-11, 1990.
2. Downs, William, Dennis W. Johnson, and Robert W. Aldred. "Influence of Chlor-
ides on the Performance of Flue Gas Desulfurization," presented at the EPA/
EPRI Symposium on Flue Desulfurization, New Orleans, LA, November 1-4, 1983.
3A-78
-------
100
95
90
a
>
o
E
a>
oe
CM
o
tn
85
80
75
70
~
~
T
o
~
Without DBA
Four Header*
~ Top Two Headers
~ Bottom Two Headers
O Top Three Headers
With DBA
Four Headers
O Top Two Headers
A Bottom Two Headers
5.6 5.8 6.0 6.2 6.4
PH
DBA
Figure 1. LG&E Mill Creek #3
S02 Removal Performance Test Results (%;
OJ
3
100
a
>
o
E
a>
oe
CM
o
tn
80 90 100 110 1 20 130 140
L/G (gall 000 acf)
Figure 3. LG&E Mill Creek #4
Predicted S02 Removal
e.
¦3
>
o
E
o
E
a>
0C
CM
o
tn
100
95
90
85
80
75
70'
651
60
¦ Top Header Out |
~ Bottom Header Out 1
'
• » -1
500 1000 1500 2000
Additive Concentration (ppm DBA)
Figure 4. LG&E Mill Creek #4
Predicted SOo Removal With One
Header Out of Service
-------
>
o
E
«
DC
CI
O
tn
100
90
80
70
60
¦
~
Without DBA
R
¦ Measured
~ Predicted
¦
With DBA
•
+ Measured
~
O Predicted
.
5.6 5.8
6.0
PH
6.2 6.4
DBA
Figure 5. LG&E Mill Creek #3
Predicted vs Measured S02 Removal (%)
Top Two Headers
B
c
o
c
4)
O
c
o
o
©
+1
:&
3
0)
• Observed
Old Data Base
~ New Data
200
20 40 60 80 100 120
Chloride Concentration (1000 mg/L)
140
Figure 7. Effects of Chloride on S02 Solubility
CaCI2 Runs
100
90
>
o
E
0>
DC
CI
O
tn
80
70
60
5.6 5.8
Without DBA
¦ Measured
~ Predicted
With DBA
~ Measured
^ Predicted
6.0
PH
6.2 6.4
DBA
Figure 6. LG&E Mill Creek #3
Predicted vs Measured S02 Removal (%)
Bottom Two Headers
• Observed
¦ Old Data Base
~ New Data Base
o 350
0 20 40 60 80 100 120 140
Chloride Concentration (1000 mg/L)
Figure 8. Effects of Chloride on S02 Solubility
MgCI2 Runs
-------
CO
>
o
E
I
00
Figure 9. Shawnee Chloride Test Series 1
S02 Removal vs. Chloride Concentration
CO
>
o
E
»
cc
C4
O
W
90
85
80
75
70
65
60
55
50
45
40
¦ Observed
~ Original Data Base
- ~ Revised Data Base
O Final Correlation
~
~
11 U
~
~ ~
~
W m ¦
¦ i i
~ ~
~
a
» «
10 20 30 40
Chloride (1000 ppm)
50
60
Figure 11. Shawnee Chloride Test Series 17
S02 Removal vs. Chloride Concentration
<0
>
o
E
60
55
50
0 10 20 30 40 50 60
Chloride (1000 ppm)
¦ Observed
~ Original Data Base
~ Revised Data Base
O Final Correlation
~ ~
~
~ ~
~ ~
¦ ~
J 0 0
1 1 1
0
¦ a
1 1
Figure 12. Shawnee Chloride Test Series 18
S02 Removal vs. Chloride Concentration
-------
5
c
a
M
o
A t
a
DC
c
0
1
s
<•
o
5 10 15 20 25 30
Calcium Concentration (1000 mg/L)
35
Figure 13. Effects of Calcium Concentration
on Limestone Disolution
Table 1
SHAWNEE
TEST DATA SUMMARY
Variable
Series 1
Series 4
Series 17
Series 18
L/G, gal/Hacf
36.7-39.9
39.6-39.9
79.4-80.3
78.7-80.2
pH
4.85-5.75
5.10-5.70
4.65-5.65
4.60-5.70
Reagent Ratio
1.085-1.119
1.081-1.130
1.089-1.117
1.089-1.109
Oxidation Node
Natural
Natural
Natural
Natural
Chloride, ppm
165-58,700
1,540-56,400
404-55,600
436-57,600
Calcium, ppm
844-31,850
1,250-31,500
872-32,200
957-32,000
Magnesium, ppm
211-250
216-236
214-305
205-306
Inlet SO,, ppm
2,430-2,730
3,950-4,050
3,900-4,050
2,300-2,600
SO, Removal, X
42.1-52.7
37.9-41.4
45.8-53.1
53.2-67.0
Limestone Grind'
Fine
Fine
Coarse
Coarse
Tank Res. Time,
5.6
11.2
5.6
5.6
min.
'Fine Grind « 95X -325 mesh; Coarse Grind • SOX -200 mesh.
100
95
90
85
80
75
¦ Observed Removal
~ k » 3
~ k tram Chloride
O k tram Calcium
70
65
60
0 30 40 50 60 70 80
Chloride Concentration (1000 ppm)
10
Figure 14. HSTC Predictions for Effects of Chlorides
(Forced Oxidation Conditions)
Table 2
HSTC OPERATING DATA SUMMARY
Variable
Test 29
Test 6
Test 35
Test 31
L/G, gal/Macf
134
133
134
134
pH
6.10
5.71
5.B0
5.60
Reagent Ratio
1.0B
1.07
1.10
1.09
Oxidation Mode'
Forced
Forced
Forced
Forced
Chloride, ppm
15,200
35,500
56,800
77,400
Calcium, ppm
3,600
6,700
10,600
15,400
Magnesium, ppm
3,100
7,360
10,900
15,900
Inlet S0t, ppm
2,000
2,000
2,000
2,000
SO, Removal, X
B6.5
84.5
B1.4
78.5
'Oxidation was 99.4% or greater In all cases.
-------
ADDITIVE-ENHANCED DESULFURIZATION FOR F6D SCRUBBERS
G. W. Juip
R. B. Schabel
Northern States Power Company
13999 Industrial Blvd.
Becker, Minnesota 55308
M. L. Lin
L. Dubin
R. D. Pickens
J. A. Byron
Nalco Fuel Tech and Nalco Chemical Company
1 Nalco Center, Naperville, Illinois 60563-1198
3A-83
-------
Intentionally Blank Page
3A-84
-------
ADDITIVE-ENHANCED DESULFURIZATION FOR F6D SCRUBBERS
ABSTRACT
In an effort to get a more cost-efficient FGD scrubber operation,
NSP-SHERCO Unit 3 started using an additive catalyst in July of
1990. The dosage of the additive catalyst (NalcdB1 1243) was
continuously optimized for cost-performance. A previous
evaluation showed lime savings of 3 5% at a 3 0 ppm additive
catalyst dosage. In another evaluation, 7% lime consumption
reduction, 4% increase in SO2 removal efficiency, and 8% decrease
in stack SO2 level were associated with 12 ppm additive feed.
There was no negative impact due to the additive in the
downstream bag house particulate collector.
Dosage optimization was continued with respect to additive
generated benefits. In this evaluation, a dosage increase from 4
ppm to 8 ppm showed additional lime savings of 12-20%. Since
most of the ash is reused, reductions in lime slurry flow were
observed one to two weeks after the additive dosage was changed
back to 4 ppm. The use of additive catalyst substantially
reduces lime consumption, the largest operation cost. With
improved FGD operation, scrubbing at a higher efficiency and
removing a larger amount of SO2 have become feasible. This
allows for possible strategies involving the SO2 emissions
allowance trading posed by the 1990 Clean Air Act Amendments.
Preceding page blank
3A-85
-------
ADDITIVE-ENHANCED DESULFURIZATION FOR FGD 8CRUBBER8
INTRODUCTION
The 1990 Clean Air Act Amendments (CAAA) have set distinct
milestones in air pollution compliance. In the Acid Deposition
Control Title, specific electric utilities and co-generation
plants are required to meet deadlines of stepwise reductions in
SO2 emissions. Responding to this challenge, increasing
attention has been given to advanced technologies that remove
high amounts of SO2. Many compliance strategies not only address
the requirements of attaining lower SO2 emissions, but also the
need for "excess" SO2 removal capacity. Excess SO2 removal
capacity allows for "catch-up" from under-scrubbing situations
and it may also be offered for sales by the allowance auction in
the new emission trading system.
Of today's SO2 control technologies, cleaning of SO2 by scrubbers
is a very popular choice. In addition to scrubbing, fuel
switching and clean coal technologies are also considered. The
selection of scrubber for new or retrofitted Flue Gas
Desulfurization (FGD) systems is frequently based on the least-
cost to meet compliance. Wet FGD scrubbing using calcium
sorbents in a throw-away process is still the dominant
technology. Spray dryer or dry processes are also employed for
the benefits of better waste disposal and handling.
As an alternative to fuel switching and coal cleaning, many
plants respond to the new CAAA by evaluating new technologies
which may fit their systems. Many steps are required to achieve
the goals of higher cost-efficiency and SO2 removal. Analyses
need to be conducted on capital and operating costs for main FGD
and auxiliary systems. Performance including SO2 removal
efficiency, availability of absorbers, and operational
forgiveness, has to be evaluated. Upgrading the potential of the
current system and the impact of future legislation should also
be included in the decision-making process.
3A-86
-------
The Northern States Power Company (NSP) has been striving to
provide customers with low cost and reliable power in an
environmentally-sound manner. These efforts have been evident in
burning low sulfur coal, utilizing waste by-products, and
attaining high air quality standards. The dry scrubbing and
fabric filter-bag house system at Sherburne County Generating
Station (SHERCO) Unit 3 is the world's largest dry scrubber-air
quality system for a single power plant. Since its inception in
1987, NSP has implemented many mechanical and chemical
improvements in Unit 3's comprehensive Air Quality Control System
(AQCS). As a result, a substantial reduction in operational
costs has been achieved.1"4
Nalco Fuel Tech has developed several scrubber additives that
enhance desulfurization at very low additive dosages. For dry
scrubbers, lime usage reductions of 15-2 5% have been observed at
dosages between 5 ppm and 25 ppm.5-12 The additive catalyst does
not have a negative influence on the downstream bag house
operation. Beneficial modifications of absorber chamber solids
were observed, making by-product solids finer and more uniform in
particle size and therefore easier to remove. These encouraging
results prompted further optimization of the catalyst dosage
based on system response and economics.
FGD CHEMISTRY AND MECHANISMS OF DESULFURIZATION
ENHANCING ADDITIVES
The wet FGD chemistry (Table 1) involves many interactions
between gas (SO2), liquid (dissolved solids in the slurry), and
solids (undissolved reagent). Kinetically, the low solubility of
the limestone or CaCC>3 is the rate-limiting step. The amount of
available liquid-phase alkalinity (HCC>3~, 0H~, CO32- ) is
critical to SO2 neutralization. Solids precipitation and their
removal from the reaction tank provide the driving force for
further reagent dissolution and SO2 sorption. Also, adequate
solid dispersion and fast diffusion between liquid-liquid,
liquid-solid and gas-solids make the process more efficient.
Relative to the wet process, dry scrubbing is inherently hindered
by lower SO2 removal efficiency due to slower gas-solids
interaction and limited solid surface for SO2 absorption. To
overcome these factors, spray dryer absorbers are typically
designed with longer residence times for absorption. Also, a
more reactive and more costly reagent, lime, is used for SO2
removal. A supplemental reagent, alkali-rich western fly ash, is
frequently used. The absorption process is once-through?
however, the ash is generally recycled to use the available
alkali. For a dry scrubber using lime, the cost of lime is
normally the largest expense.
3A-87
-------
The value of Nalco Fuel Tech's additives is their ability to
increase desulfurization at a minimal use dosage. The additives
are environmentally safe and do not negatively affect FGD
auxiliary system operations and long-term by-product stability.
From a chemical viewpoint, the mechanism of the additive must be
involved in the removal of rate-limiting steps in the
desulfurization process.
Specific additives were developed to accelerate the dissolution
rate of limestone, lime and fly ash.5-7 Certain additives act to
remove dissolution-blocking alumina and iron oxides on the fly
ash surface and expose normally hidden and unused alkali.® Other
additives improve the wetting properties of the hydrophobic
reagent solids, thereby increasing the mass transfer of the solid
dissolution at the interphase. Also, alkalinity at the interface
is preserved with additional buffering capacity produced by the
additive to ensure constant SO2 absorption. The use of a surface
active agent also reduces the resistance of the slurry to flow.
By-product solids are precipitated at a lower gypsum saturation
ratio in the reaction tank. The removal of the solids increases
further reagent dissolution and SO2 sorption.
USE OF ADDITIVE CATALYST AT NSP-SHERCO
The Desulfurization System
SHERCO Unit 3 is equipped with a spray-dryer/fabric filter air
quality control system (AQCS). The AQCS system is considered one
of the best available technologies. Coal burned by SHERCO 3 is
low sulfur western sub-bituminous coal from the Westmoreland
mine. A typical coal analysis is shown below:
% S % Na % Ash % Moisture BTU/lb lbs SO9/MMBTU
0.56 1.99 9.86 24.44 8600 1.45
The spray dryer absorption (SDA) system consists of eight spray
dryer reactors (including two spares) and three 16 compartment
reverse air fabric filters. Each reactor is equipped with a
single 900 horsepower rotary atomizer. The SDA system has a
bypass reheat system to control fabric filter inlet temperature,
two reagent preparation systems, and a concomitant ash handling
and process control system. The ash collected by the bag house
is recycled to make up the fly ash slurry. The reactor ash is
mostly recycled. The AQCS for Unit 3 is illustrated in Figure 1.
3A-88
-------
Unit 3 has a net power output of 860 MW. It utilizes two alkali
slurry sources, lime and fly ash, to remove SO2 in the flue gas.
The fly ash slurry is fed at a much higher flow rate than the
lime slurry, usually at a ratio higher than 15:1. The solids
level of the slurry is under very careful control: 45-50% for the
fly ash and 25-30% for the lime slurry.
The control scheme using adiabatic saturation chamber outlet
temperature was modified to eliminate solid deposition on the
chamber walls. Vertically placed dry bulb thermocouples at a
location near the outer chamber walls directly across from the
atomization wheel provide reliable sensing of gas temperature for
spray down control. The temperature probes stay sufficiently
clean due to the high gas turbulence in the outer wall area of
the chambers. This allows reliable spray down control within
twenty degrees of the chamber adiabatic approach temperature.
Experience of Additive Catalyst Use
While the lime reagent usage has decreased because of
improvements in the scrubber operation, cost of the reagent is
still the largest operational cost at NSP-SHERCO. The initial
goal of using an additive was simply to reduce the lime cost.
NalcdS> 1243 (N-1243) is a surfactant-based additive which is
believed to function by increasing liquid-S02 gas and solids-gas
sorption at the interface. Laboratory studies show that N-1243
improves slurry flow and possibly atomization. Nozzle wear due
to erosion may be reduced due to decreased solids particle size
and lower restriction of slurry flow. For these reasons, N-1243
was selected as the additive evaluated at SHERCO Unit 3.
The additive was fed continuously to the additive feed tank where
the recycle ash slurry is mixed with lime slurry (Figure 2). The
additive dosage was typically below 30 ppm, based on the total
flow rate of fly ash slurry and lime slurry.
The results of the first evaluation showed a 3 5% reduction in
lime usage at an additive catalyst dosage of 30 ppm.1 Due to the
impressive results, Unit 3 scrubber has been using N-1243 program
since July 16, 1990. Further quantification of scrubber
performance with respect to additive catalyst dosage was started
in July of 1990.13 The results indicated that, at a dosage of 12
ppm, higher SO2 removal was achieved. Operation with the
additive catalyst was also associated with lower stack SO2
emissions and lower lime consumption. During the additive use,
power generation of 10% higher MW (779 MW) than the baseline
average (7 08 MW) was also observed. There was no negative impact
to the downstream bag house operation attributable to the
additive catalyst. Beneficial modification of absorber chamber
solids was also observed. The modification made the solids more
uniform and finer in particle size and easier to remove.
3A-89
-------
To further optimize savings with N-1243 treatment, dosage was
varied with benefits quantified in February of 1991.
Dosage Optimization
In the test performed in February of 1991, the additive catalyst
(N-1243) dosage was doubled from 4 to 8 ppm for 10 hours.
Subsequently, the dosage was changed back to 4 ppm. Hourly
average data, before and after the dosage increase from 4 to 8
ppm, was analyzed and compared.
Unit operation was held constant throughout the testing period of
11 hours prior to doubling the dosage and the 10 hours that the
dosage was doubled. SDA chamber outlet temperature was held at a
constant 20° F above saturation. SDA chamber differential
temperature was held at a constant 13 0° F, and SO2 removal rate
was held at 72%. SDA chamber inlet SO2 loading was held at a
constant 9,3 00 lbs/hr. The lime stoichiometric ratio decreased
14.4% during the time the dosage was doubled. The reduction in
stoichiometric ratio or reduction in lime consumption after the
dosage increase is shown in Figure 3 and Table 2.
Some beneficial residual effects from doubling the N-1243 feed
were observed three to five days after the dosage was doubled.
After two and a half days (64 hours comparison), lime savings
still averaged 12-20% lower (Figure 4 and Table 3). Lacking
other obvious reasons, the lowered rate of lime usage is
attributed to reuse of the ash containing a residual amount of N-
1243. The effect lasted approximately 1 to 2 weeks and
diminished with time after the N-1243 dosage was changed back to
4 ppm. Figure 5 and Table 4 show the 110 hours comparison data.
As previously stated, no interference of bag house operation was
observed.
In this evaluation, the use of additive catalyst substantially
reduces the lime cost. Costs associated with lime preparation
and waste disposal are proportionally reduced as well. As shown
in the previous results, the value of the additive catalyst is
not only in reagent cost reduction, but also in its capability of
removing a higher amount of SO2• In special cases, the operation
at a high SO2 removal efficiency may allow for higher power
production. Process optimization is now continued at SHERCO to
take advantage of the benefits that have the maximum total value.
New strategies such as SO2 emissions allowance auction posed by
the 1990 Clean Air Act Amendments have become feasible.
3A-90
-------
CONCLUSION
The process of optimizing the additive catalyst dosage showed
that increasing the dosage of N-1243 from 4 to 8 ppm increased
lime savings by 12-20%. Residual beneficial effect due to
recycling of the additive catalyst lasted one to two weeks of
operation.
REFERENCES
1. G. W. Juip, Northern States Power Company Sherburne County
Unit 3 Air Quality Control System Operating Experience and
Design Improvements. Paper Presented at the 1990 SO2 Control
Symposium, New Orleans, Louisiana, May, 1990.
2. G. W. Juip, Experience with Spray Drver Absorber Flue Gas
Desulfurization at Northern States Power Company. Presented
at State and Territorial Pollution Program Administrators
and the Association of Local Air Pollution Control Officials
Technical Workshop, New Orleans, Louisiana, October, 1989.
3. J. R. Donnelly, S. H. Wolf, and G. A. Fosher, Update of
Jov/Niro U. S. Utility Spray drver FGD Systems. Paper
Presented at the EPA/EPRI First Combined FGD and Dry SO2
Control Symposium, St. Louis, Missouri, October, 1988.
4. A. L. Cannell, and M. L. Meadows, Effects of Recent
Operating Experience on the Design of Sprav Drver FGD
Systems. Paper Presented at Air Pollution Control
Association, Detroit, Michigan, June, 1985.
5. M. L. Lin and E. W. Ekis, Jr., Use of Nitrite to Enhance SOg
Removal in Flue Gas Desulfurization Wet Scrubbers. U. S.
Patent 4,793,982.
6. M. L. Lin and R. J. Mouche', Use of Oil-Soluble Surfactants
in Flue Gas Desulfurization Systems. U. S. Patent 4,869,885.
7. M. L. Lin, Synergistic Effect of Dibasic Acid and
Surfactants in Enhancing SO? Removal in Wet Scrubbers. U. S.
Patent 4, 891,195.
8. R. J. Mouche7 and M. L. Lin, Flv Ash Alkali Utilization
Enhancement in Flue Gas Desulfurization. U. S. Patent
4,869,846.
3A-91
-------
9. M. L. Lin, R. J. Mouche' and R. W. Shiely, Alternative
Chemical Technology to Improve FGD Scrubber Performance.
Paper Presented at the 15th Biennial Low-Rank Fuels
Symposium, Minneapolis, Minnesota, May 22-24, 1989.
10. M. L. Lin, E. W., Ekis, Jr., and M. T. Meyerkord, Chemical
Additives for Drv FGD Scrubbers. Paper Presented at the
First Combined FGD and Dry SO2 Control Symposium, St. Louis,
Missouri, October 25-28, 1988.
11. M. L. Lin, R. J., Mouche', E. W. Ekis, Jr. and P. A. Nassos,
Improvement of Flv Ash Utilization in FGD Systems. Paper
Presented at the American Power Conference, Chicago,
Illinois, April 27-29, 1987.
12. M. L. Lin, D. V. Diep, J. E. Mincy, and V. M. Albanese,
Enhanced Desulfurization Using Chemical Additive Options.
Paper Presented at the Seventh Pittsburgh Coal Conference,
Pittsburgh, Pennsylvania, September 10-14, 1990.
13. G. W. Juip, R. B. Schabel, M. L. Lin, L. Dubin, R. D.
Pickens, and J. A. Byron, Achieving Higher Desulfurization
Using Low Amounts of Chemical Additives - Experience at
SHERCO Unit 3. Paper Presented at IGCI Forum 91', Washington
D. C., September 11-13, 1991.
3A-92
-------
Air Quality Control System (AQCS) for
SHERCO-Unit 3
Head
Tank
Bypass
Boiler
ID
Fan
Spray
Dryer
Absorber
Air
Heater
Bag House
Service.
Water
Stack
Scrub
ber
Makeup
Tank
Solids
Storage
Silo
Recycle
Silo
CollectrioiT*
Trough
Classifier
"Ball1
.Mill
Lime L
Premixer
To
Disposal
Lime
Slurry
Storage
Tank
(Ash)
Additive
Feed
Tank
Recycle
Tank
Lime
Slurry
Tank
Figure 1. Air Quality Control System (AQCS) at SHERCO Unit 3.
-------
Additive Feed and Recycle System
Lime
Slurry
Additive
Feed Tank
Spray Dryer
Reactor
Exit
N-1243
Additive
Feed
Flue Gas In
Recycle
Tank
Recycle
Ash
wwvw
Baghouse
Figure 2. Additive catalyst feed and recycle system.
3A-94
-------
% LIME SAVINGS AFTER DOSAGE INCREASE
FROM 4 PPM TO 8 PPM
O
p
Q
§
30
25 -
20 -
15 -
10 -
•*r
z:
LIME STOI-
CHIOMETRY
GPHLIME
SLURRYFLOW
Figure 3. % Lime savings after dosage increase (34
hours at 4 ppm before dosage increase vs. 10 Hours at
8 ppm after dosage increase).
3A-95
-------
% LIME SAVINGS AFTER DOSAGE INCREASE
FROM 4 PPM TO 8 PPM
£
O
HH
H
£
Q
§
*
¦'/////sz/
7/4'///,,
LIMESTOI-
CfflOMETRY
GPHLJME
SLURRY FLOW
Figure 4. % Lime savings after dosage increase
(First bar: 34 hours at 4 ppm before dosage increase
vs. 10 Hours at 8 ppm after dosage increase. Second
bar: 56 hours at 4 ppm before dosage increase vs. 64
hours after dosage increase that included 10 Hours at
8 ppm and 54 Hours at 4 ppm).
3A-96
-------
% LIME SAVINGS AFTER DOSAGE INCREASE
FROM 4 PPM TO 8 PPM
O
e
o
p
Q
§
LIMESTOI-
CfflOMETRY
GPHLIME
SLURRYFLOW
Figure 5. % Lime savings after dosage increase
(First bar: 34 hours at 4 ppm before dosage increase
vs. 10 Hours at 8 ppm after dosage increase. Second
bar: 56 hours at 4 ppm before dosage increase vs. 64
hours after dosage increase that included 10 Hours at
8 ppm and 54 Hours at 4 ppm. Third bar: 106 hours at
4 ppm before dosage increase vs. 110 hours after
dosage increase that included 10 hours at 8 ppm and
then 100 hours at 4 ppm).
3A-97
-------
Table 1
PRINCIPAL FGD CHEMISTRY
Gas (SOo)
Solids Liquid (water
(reagent solids, fly ash) phase in reagent slurry)
Type of Reactions
Solids-Liquid
Dissolution of limestone
Gas-Liquid and Liquid-Liquid
Sorption- Liquid phase alkalinity (HCO3-) and SO32
SO2 on solid reagent
Solids
Precipitation, Scaling
Dispersion
Gas-Liquid, Gas-Solids, and Liquid-Liquid
Diffusion
Principal Chemical Reactions
Dissolution
CaC03 (s) - CaC03 (1)
CaC03 (1) - Ca2+ + C032-
C032- + H+ - HC03-
Sorption
SO2 (g) + H20 - hso3- + h+
Solids Formation and Precipitation
Ca2+ + SO42- + 2 H20 - CaS04-2H20 (s)
(or HSO4-) gypsum
Ca2+ + S032- + 0.5 H20 - CaS03•0.5H20 (s)
(or HS03~) calcium sulfite hemihydrate
3A-98
-------
Table 2
COMPARISON OF SCRUBBER PERFORMANCE
N-1243 DOSAGE EFFECT
11 Hours at 4 ppm Before Dosage Increase vs.
10 Hours at 8 ppm After Dosage Increase
N-1243 Dosage 4 ppm 8 ppm
Parameter
lbs/hr S02 in 9335 9394
SO2 Removal 72% 72%
SDA Differential
Temperature 131° F 130" F
SDA Outlet ADSAT*
Temperature 20.4° F 19.8° F
Stoichiometric Ratio
of Lime 0.8 0.7 (12.5% reduction)
* ADSAT = Adiabatic Saturation
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Table 3
COMPARISON OF SCRUBBER PERFORMANCE
N-1243 DOSAGE EFFECT
56 Hours at 4 ppm Before Dosage Increase vs.
64 Hours After Dosage Increase,
Including 10 Hours at 8 ppm and 54 Hours at 4 ppm
Hours Before/After
Doubling Dosage
Parameter
Before
After
(%Chanae)
Hours
56
64
S02 In
548.4
544.5
( 0.0)
S02 Out
161.8
154.3
(-4.6)
% SO2 Removal
70.59
71.71
(+1.6)
MW Load
808.8
794 . 9
(-1.7)
Lime
Stoichiometry
0.9239
0.7964
(-13.8)
gph Lime Slurry
3072.4
2481.4
(-19.2)
gpm Recycle Ash
736.9
759.2
(+3.3)
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Table 4
COMPARISON OF SCRUBBER PERFORMANCE
N-1243 DOSAGE EFFECT
106 Hours at 4 ppm Before Dosage Increase
vs. 110 Hours After Dosage Increase, Including first
10 Hours at 8 ppm and then 100 Hours at 4 ppm
Hours Before/After
Doubling Dosage
SC>2 In
SC>2 Out
% SC>2 Removal
lbs Lime/MW
Lime
Stoichiometry
Before
After
(%Chancre)
106
110
542.8
544.4
(+0.3)
156.7
154.4
(-1.4)
70. 55
71. 68
(+1.6)
8.962
8.013
(
-10.6)
0.8865
0.7945
(
-10.4)
2758.3
2431.5
(
-11.9)
709.0
763.9
(+7.7)
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3A-102
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Techniques for Evaluating Alternative Reagent
Supplies
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TECHNIQUES FOR EVALUATING
ALTERNATIVE REAGENT SUPPLIES
C. V. Weilert
D. H. Stous
P. N. Dyer
Burns & McDonnell Engineering Co.
4800 E. 63rd Street
Kansas City, Missouri 64130-4696
ABSTRACT
This paper provides an overview of Burns & McDonnell's Reagent Evaluation Progran
(REP). This paper explains in some detail the calculation procedure and basic
techniques necessary to compare different reagent offerings on an equivalent basis.
Also contained within the paper are suggestions and recommendations on laboratory
analysis procedures and sources of information for use in conducting a reagent supply
study.
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TECHNIQUES FOR EVALUATING
ALTERNATIVE REAGENT SUPPLIES
INTRODUCTION
This paper deals with techniques for evaluating alternative reagent supplies for flue
gas desulfurization (FGD) systems.
FGD systems require the addition of chemicals to remove sulfur dioxide (S02) from the
flue gas. These chemicals are referred to as reagents. The principle reagents in use
in the United States are lime, limestone, magnesium-enhanced lime and sodium carbonate.
Other chemicals may be used in combination with reagents to either enhance S02 removal
performance or limit formation of certain reaction products. These chemicals are
referred to as additives. Some of the more common additives in use are carboxylic
acids, dicarboxylic acids and elemental sulfur.
While the approach stated in this paper is applicable to all reagents and additives,
the primary focus and discussion is based on a conventional wet limestone system.
EVALUATION METHODOLOGY
Along with the technological advances and our increased knowledge of FGD systems and
their operations has come increased awareness of the importance of the quality of
reagents to be used in the FGD system. Our understanding of the FGD process and FGD
systems has reached a level at which it is now prudent, and possible, to develop a
"total cost" of utilization for each potential reagent source. This total cost
analysis should include the factors of acquisition, transportation, storage, handling,
utilization and disposal of by-products.
These and other factors combine to complicate the assessment process and obscure the
most suitable reagent choice. Obviously, no single parameter can be measured to
determine a reagents suitability. For example, in evaluating two different limestones
for use in an FGD system, the first stone considered is a highly- reactive, high purity
stone. Upon closer examination, it is found extremely expensive to buy and transport
the material to the plant site. The second stone is much closer to the plant but of
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lesser purity and reactivity. This generally means increased handling and disposal
costs are required. To be able to determine the best choice, a method of reagent
evaluation that considers all of the economic and environmental variables and provides
ranked alternatives should be formulated.
A variety of computer models have been developed to assist in the total cost evaluation
process. Computer models can be used to analyze transportation and utilization costs,
and a comprehensive model can be developed to perform an economic analysis of the
various reagent supply alternatives. The comprehensive model can be set up to analyze
cost at the source, cost of transportation, and the cost of utilization, which would
include reagent quality, coal quality, plant load factors, FGD system efficiencies, and
by-product disposal cost.
We must keep in mind that different sets of criteria are considered for evaluation if
the FGD system is existing, as opposed to selection of a reagent supply at the time of
initial system operation. An existing FGD system that has been in operation for a
period of time has available operating data using a specified type and quality reagent.
All factors that must be considered in the analysis have already been developed through
normal unit operation. The evaluation criteria to be used when selecting a reagent for
a new FGD system will most likely be based on information in the absorber
specification. The difference between these two sets of evaluation criteria is that
actual operating costs may be known for the existing FGD system and unknown for the new
FGD system. Since the actual costs are unknown for the new FGD system, they must be
estimated.
The total cost evaluation process can best be performed in two phases. The first
phase, known as the Macro Study, uses a general computer model which simulates the FGD
system under various operating conditions. The simulation model is, by necessity,
extremely flexible, responding to reagent quality differences which dictate FGD system
efficiencies, various levels of sulfur content in the fuel and waste disposal
requirements unique to each reagent considered. These data are integrated with
transportation alternatives available from each source and the f.o.b. reagent cost.
The resulting economic analysis identifies those options that are truly cost-effective
as opposed to those which are only apparently so.
The second phase, known as the Detailed Analysis, involves upgrading the cost
assumptions of the Macro Study to include site specific cost impacts of reagent use.
Data is also compiled on reagent reactivity, as reagent supplier site visits are made
and reactivity tests are performed.
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The following paragraphs discuss a methodology that can assist in making the best
overall choice of reagent to be used in the specified FGD system.
Phase I - Macro Study
To examine in greater detail the data required to complete Phase I of the analysis, one
must develop the quality and quantity of reagent that will be used for the analysis.
For new units, quality requirements are generally obtained from the FGD system
specifications; however, the manufacturer may have special requirements that also need
to be included in the quality specifications. If reagent supplies for existing units
are being evaluated, the quality requirements can be developed from several sources:
1. Original specifications.
2. Review of operating data and existing contracts.
3. Performance adjustments and quality based on either an analysis of
operating records or an overall efficiency testing program.
The quantity of reagent required is based on the capacity of the plant, load factor,
percent sulfur in the fuel, and the degree of reagent utilization in the system. The
quantities for this evaluation can be determined by a computer simulation of the FGD
system compiled on an annual basis.
The next step is to define the financial characteristics of the project. This is done
by estimating the FGD system capital requirements, establishing the method of
financing, determining the cost of capital and selecting a depreciation method. Price
escalation and discount rates may be established to project future expenses and express
them in current dollars through a present-worth analysis, or an analysis on a constant-
dollar basis may be structured.
Reagent Suppliers' Initial Offers. After the quality and general quantity requirements
have been developed, a list of potential suppliers should be determined. It is good
practice to contact all companies that represent potential suppliers. Results could
be biased or their validity questionable if potential suppliers were overlooked or
arbitrarily eliminated from consideration. Therefore, a comprehensive survey should
be undertaken to identify all companies that appear to be in a position to supply the
reagent. The potential suppliers will be identified on the basis of:
1. Type of product required.
2. Distance from the point of utilization.
3. Modes of transportation available.
4. General quality of reagent.
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Several sources are available that can be used to identify the potential sources of
reagent.
1. Current suppliers.
2. Previous bidders.
3. Direct contacts from suppliers.
4. Past projects.
5. Producer associations such as:
--National Lime Association
--National Crushed Stone Association
--State mineral associations
6. U.S. and State Bureau of Mines.
7. U.S. and State geological surveys.
Each of the suppliers identified as potential sources are then sent a request for an
"Expression of Interest." The expression of interest is not a request for proposal,
but is issued to collect information from which a preliminary economic analysis can be
made. Information requested in the expression of interest should include:
1. Location of source or shipping location.
2. Transportation modes available.
3. Production capacity.
4. Product quality.
5. Reserves.
6. Current price.
To assist the suppliers in developing their response, each company should be given the
following information:
1. Location of the facility
2. Estimate of quantity required
3. Beginning date of the requirement
4. Quality constraints
Tight restrictions placed on reagent quality should be avoided when possible. This
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will allow each company to evaluate all resources and holdings to submit the best
package.
Three major points should be stressed in the request for the expression of interest.
1. Information collected from the expression of interest will be evaluated to
determine who will receive a request for proposal. A response to the
expression of interest is required to be considered for a request for
proposal.
2. Response to the expression of interest does not guarantee a request for
proposal.
3. Large or unusual variations between data contained in the expression of
interest and the request for proposal can be a basis for rejection.
Evaluation of Offers. Upon receipt of the expression of interest responses, a
preliminary economic evaluation can be made of the potential suppliers meeting the base
requirements. The data furnished by each company is compiled and the FGD system model
is modified to respond to the properties of each reagent offer submitted. This
evaluation is a multidisciplinary effort based on information contained in the response
to the expression of interest, utilization costs such as reagent storage and
preparation, disposal costs, and the addition of any new facilities that may be
required.
While the reagent-dependent systems are being defined, other analyses that evaluate the
transportation alternatives from each source to the plant site should be completed.
The modes most commonly encountered include truck, barge and various forms of rail,
such as single-car and multiple-car service.
Several approaches to estimating costs of transportation alternatives can be used.
Published rates or tariffs for the specific movement or similar movements usually
provide a valuable guideline in the evaluation of probable rates. When these rates
cannot be obtained, it is often possible to acquire working estimates from the various
transportation companies involved. They are usually cooperative and will provide
information for the comparative purposes when asked to assist in evaluations of this
type. A third alternative is to generate generic rates using a transportation
simulation model.
It is important that the cost estimates covering the FGD and transportation systems are
developed by specialists who are actively engaged in equipment specification, bid
evaluation and transportation rate development for similar systems on comparable
proj ects.
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This process, in essence, duplicates the technical specification, operating conditions,
and financial considerations of the FGD system unique to each reagent offer unde:
consideration. To perform the preliminary economic analysis, a computer program thai
approximates power plant operations should be used. These programs typically includ(
detailed fuel burn equations, plant load factors and scrubber reactions to give i
detailed analysis of amount of each reagent required, the waste products from eacl
reagent and other operational data. From the amounts calculated by the simulation, tht
cost for each phase of the operation can be estimated including depreciation, taxes,
escalation, etc. In this manner the actual costs of the reagents of different
qualities requiring different volumes can be easily compared. Also, the effects oi
operational adjustments can be compared as well as changes in fuel quality.
Phase II - Detailed Analysis
The results of the Macro Study are used to identify the more favorable sources to whicl
a request for proposal (RFP) for the reagent supply will be sent. A sample request
form is included as Figure 1. Detailed and guaranteed quality data are requested ir
the RFP and evaluated to determine their impact on utilization cost. In the RFP, t
sample contract may also be requested of each selected potential supplier. Tht
contract provisions could be used to project different escalation rates for the sources
offered.
After the RFP has been returned, the evaluators should set up an appointment to visit
the supplier's facilities. These site visits have two objectives. The first objective
is to gain first hand knowledge of the capabilities and resources of the potential
supplier. The second objective is to take representative samples of stone for chemical
and reactivity analysis.
Laboratory Analysis. Samples collected during the site visit should be tested foi
purity to verify information received in the RFP. Two methods are recommended tc
determine the various reagent quality parameters. First, a standard limestone analysis
(method AOAC 14 E 1.004 and 2.156) will provide data on the Ca^, fig"1"1" and neutralizing
value of the stone. Secondly, an induction coupled argon plasma (ICAP) analysis using
HF digestion can be used to provide information on the metals present. High
temperature preparations such as lithium borate fusion are not recommended because of
the potential loss of the more volatile metals. These two tests can be performed bj
most of the larger full service laboratories for approximately $175.00 (1991) pel
sample.
In addition, reactivity testing should also be performed. Burns & McDonnell has used
3A-111
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the Combustion Engineering reactivity test for a number of years. This test is a
volumetric neutralization of limestone under fixed Ph, temperature and agitation
conditions. This procedure has proven to be stable and repeatable over a wide range
of limestone qualities.
The final laboratory work done on the samples is a petrographic analysis. This
analysis requires that the stone be cut into thin sections and impregnated with high
pressure epoxy dye. The thin sections are then photographed for later use.
The thin section work has given us some additional insights on what contributes to the
reactivity of a limestone. Our experience with over 100 samples has allowed us to
conclude that the limestones which contain a large number of allochems composed of
fossils and/or pellets supported in a matrix of lime mud or calcite tend to have
excellent reactivity. Figure 2 shows the reactivity curve of Marblewhite 200 (a
primary reactivity standard) and a limestone rich in fossils. Figure 3 shows the
reactivity curve of Marblewhite 200 and a limestone with a much lower fossil count.
Comparison of Alternatives. The comprehensive model developed for the Macro Study is
used with the updated inputs to determine the effect of each reagent on the simulated
FGD system. The model must generate certain information that is necessary to support
a decision-making process. As a minimum, the model should provide the following:
1. Reagent Quality Analysis: The model should compile all of the quality data
submitted for each reagent considered. It should present a complete
chemical analysis and the results of reactivity tests. Size of delivered
reagent should also be included when available.
If limestone is the reagent being considered, the range of values present
in the reserve is desirable as well as the mean or expected contract
quality.
2. Reagent Cost and Quantity: A forecast of reagent requirements and expenses
should be generated for each year of the evaluation. Total annual
quantity in tons and total annual cost in thousands of dollars should be
developed. These expenses should be further reduced to the cost at
source, cost of transportation, and delivered cost in dollars per ton.
Other information germane to the assessment of reagent expenses should
also be presented with the results. Included are the net unit capacity,
net heat rate, and the heating value of the fuel in Btu per pound. The
reagent-to-fuel ratio necessary to affect the required level of sulfur
dioxide removal should also be available.
3. Investments and Expenses: These items are the culmination of the efforts
to simulate the FGD system utilizing a specific reagent from a specific
source. All of the information needed to address the three primary
components of the total cost are presented here (the cost of reagent at
the source, cost of transporting the reagent, and utilization costs
3A-112
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directly attributed to the reagent). The combined investment and the
expense totals are applied to estimate annual costs.
These three categories provide the basic information for economic comparisons. The}
contain the data directly related to the economic differences among the reagents. Twc
comparisons that are especially useful are a capital investment table to compare the
costs of reagent-dependent systems, and a summary of reagent quality data comparing the
more critical determinants of reagent efficiency and by-product treatment or disposal.
Ranking Alternatives. To determine which reagent offers are economically preferable,
it is necessary to develop a ranking based upon the present value of all cash expenses.
The reagents are ordered from lowest cost to highest cost and are presented with the
percentage deviation from the most economic reagent to bring the significance of the
ranking into perspective. The components of this ranking are the reagent expenses ir
dollars per ton and capital investments.
OTHER CONSIDERATIONS
As stated, the ranking is the final step in reducing the reagent sources to a fev
discrete economic choices and provides the foundation upon which reagent source
decisions are based. At this point, it would be nice to say the work is done.
Unfortunately, the decisions that will be made subsequent to the evaluation must
consider factors which cannot be neatly arranged in columns of a computer printout.
Regardless of how elegantly designed it may be, no computer model is competent tc
assess the intangibles that govern the business affairs of the reagent suppliers.
The work would be of little value if the choices selected do not lead to a viable
reagent contract. Therefore, each of the more economically attractive offers must be
reviewed in the light of the supplier's willingness and ability to deliver the reagent
in the specified quantities at the specified price. This effort requires research intc
a supplier's financial stability, past performance, available resources, leasing
arrangements, environmental posture, and even labor relations, to assure the buyer of
an uninterruptible and adequate reagent supply. It is not until this process has beer
completed that the "total cost" approach has effectively served its purpose.
3A-113
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FIRM INFORMATION
'
A yv < , ^
A A * «¦ s
wiMaOTam
Company
Address
Contact
Quarry Location
Phone
REAGENT INFORMATION
^ V*< / / ^ t, '
vt MMSM +• ** %SV ^ V/ «SV * MKA * Vt A ~ M Aw A/
Formation fl Surface
>x*:«w:WvX<*3'X*!
*/<•»./ <~ * />*¦ w/M'A'/
f] Underground
Present Capacity
Potential Capacity
Current Production
Estimated Reserves (tons)
Current Cost
Hardness
Method
Screening Sizes Available
Chemical Analysis
% CaC03
% MgC03
% Inerts
Dedicated Pile for FGD Reagent
M Yes
fl No
fl Potential
Chemical Analysis Frequency
REAGENT HANDLING
-
Rail
Barge
Truck
Current Shipping Modes
Delivery Cost
Loading Point
Transloading Required
Loading Capacity (T/Hr)
Queuing Capacity (Units)
' 5
DELIVERY EQUIPMENT
,
'
Owned/Leased/Subcontracted
Capacity (Tons)
Unloading Rates
Distance to Plant
Expected Tolls and/or Taxes
Route-Rail [
Route-Truck
Route-Barge |
Figure 1. Sample Request For Proposal Form
3A-114
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OJ
>
U1
~o
0
H—»
o
CO
0
cc
120
100
*
%
100 150 200 250
Elapsed Time (Minutes)
300
350 400
Typical Limestone —Marblewhite 200
Figure 2. Sulfuric Acid Reactivity Test. Reactivity Profile - High Quality Stone.
-------
OJ
>
-------
FACTORS INVOLVED IN THE SELECTION OF LIMESTONE REAGENTS
FOR USE IN WET FGD SYSTEMS
J. B. Jarvis
E. S. Roothaan
F. B. Meserole
Radian Corporation
8501 N. Mopac Boulevard
Austin, Texas 78759
D. R. Owens
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, California 94303
3A-117
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3 A-118
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FACTORS INVOLVED IN THE SELECTION OF LIMESTONE REAGENTS
FOR USE IN WET FGD SYSTEMS
ABSTRACT
With recent activity in the design and construction of retrofit flue gas desulfur-
ization (FGD) systems, many utilities are faced with the task of selecting lime-
stones which will allow FGD systems to function as designed, and at the same time,
provide cost-effective operation. The Electric Power Research Institute (EPRI) has
sponsored research to identify factors which should be considered in the reagent
selection process. A set of capabilities has been developed which is currently
being employed to assist six utilities in selecting cost-effective reagent sources.
The major elements in the selection package consist of an analytical characteriza-
tion of candidate limestones; grindability, reactivity, and magnesium availability
testing; and performance modeling utilizing EPRI's FGD £Rocess Integration and
Simulation Model (FGDPRISM). The results from these measurements are used to
perform a site-specific economic analysis which can be used to rank the candidate
limestones and quantify the impact of various limestone properties on plant oper-
ating costs.
This paper includes a description of each element in the selection package along
with a review of current research activities aimed at improving predictions of
limestone reactivity and magnesium availability. An example is presented which
illustrates how reactivity and magnesium availability affect both the performance
of an FGD system and plant operating costs.
Preceding page blank
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FACTORS INVOLVED IN THE SELECTION OF LIMESTONE REAGENTS
FOR USE IN WET FGD SYSTEMS
INTRODUCTION
Phase 1 acid rain control legislation may require construction of up to 30 flue gas
desulfurization (FGD) systems by the year 1995. It is anticipated that many of
these systems will be conventional wet limestone FGD systems. Consequently, many
utilities are in the position of evaluating and selecting limestone reagents for
use in these systems.
Selecting the optimum limestone for an FGD system is not a straightforward process.
The optimum reagent for a particular FGD system will depend both on the properties
of the limestone and the FGD system design and chemistry.
Historically, limestone selection for wet FGD systems has been somewhat qualita-
tive. A variety of reactivity test procedures have been developed and employed by
FGD system vendors and engineering firms in an effort to identify limestones suita-
ble for use in FGD systems. However, no universally accepted procedures are avail-
able to quantify the properties of this natural reagent. Often, the only criteria
considered when selecting limestones are the delivered reagent cost, the limestone
hardness, and the calcium carbonate content. Thus, utilities face a difficult task
in selecting reagents which will maximize the performance of their particular FGD
system and provide the lowest total operating costs.
Utilities with existing FGD systems may also wish to consider alternative reagents
to optimize system performance and reduce operating costs. However, the utility
may be forced to use a trial-and-error approach involving relatively costly full-
scale tests to quantify changes in performance.
Limestone reagent constitutes a major operating cost in FGD systems and represents
an area where significant cost savings can be realized. In addition, limestone
3A-120
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properties such as reactivity and magnesium availability can have a significant
effect on FGD performance indicators such as S02 removal and limestone utilization.
Therefore, EPRI has developed an integrated approach to assist utilities with
reagent selection for both new and existing FGD systems. The approach consists of
a series of tests and evaluations developed under several EPRI wet FGD programs and
includes:
• Analytical characterization of the limestone composition;
• Measurements of hardness (grindability);
• Reactivity measurements;
• Measurements to allow predictions of magnesium availability;
• Performance modeling using EPRI's FGD £Rocess Integration and
Simulation Model (FGDPRISM); and
• Economic analysis of performance changes and ranking of candidate
1imestones.
A schematic diagram showing how these elements are arranged to form an integrated
approach for limestone selection is presented in Figure 1.
The remainder of this paper is divided into two sections. The first describes the
elements of the selection package and shows how they are employed to provide the
utility industry with an integrated approach for selecting optimum reagent sources.
The second includes a review of recent laboratory test results which support the
procedures utilized in the selection package. This section focuses on the devel-
opment of procedures to measure limestone reactivity and magnesium availability.
ELEMENTS OF THE LIMESTONE SELECTION PACKAGE
The elements of the limestone selection package consist of tests designed to
measure various limestone properties, process simulation modeling to quantify the
effect of limestone properties on FGD system performance, and economic analyses to
quantify operating costs for each candidate reagent. A summary of the selection
package elements and their significance is shown in Table 1. Some of the important
considerations for each of these elements are discussed in the following sections.
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Analytical Characterization
The first step in the reagent evaluation involves measurements to determine the
chemical and physical properties of candidate limestones. To conduct a meaningful
analysis, it is extremely important that limestones be sampled representatively
from the material which is actually to be supplied for the FGD system. Since lime-
stone is a natural reagent, its composition may vary considerably within a quarry.
Utilities should therefore consider obtaining multiple samples from each supplier.
The analytical characterization includes the following measurements:
• The concentrations of calcium and magnesium carbonate, and acid
insolubles (inerts);
• The concentration of dolomite in the limestone; and
• The limestone hardness.
Measurements of the chemical composition are performed to quantify the concentra-
tions of major species present in the limestone. Limestones with lower concentra-
tions of carbonate may be less desirable for several reasons. First, they have a
higher effective cost per unit of carbonate and contribute to additional transpor-
tation and waste disposal costs. Second, low-quality limestones, having higher
concentrations of species such as iron, silicon, and aluminum, can adversely affect
scrubber operation under some circumstances. The concentrations of these species
should be measured directly if the utility is considering the use of lower-quality
1imestones.
Magnesium carbonate is present in limestones in two distinct crystalline forms--as
dolomite and as a solid solution with calcium carbonate. Dolomite is an equimolar
mixture of calcium and magnesium carbonate and, to a first approximation, can be
considered inert under normal FGD system operating conditions. Techniques in-
cluding X-ray diffraction (XRD) and infrared spectroscopy (IR) have been developed
under this program to quantify the amount of dolomite present in limestone samples.
Measuring the quantity of dolomite in candidate limestones is important for several
reasons. First, if the dolomite concentration is high, the overall carbonate util-
ization will decrease. Second, in forced-oxidation systems, high concentrations of
3A-122
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dolomite in the limestone may render the gypsum byproduct unsuitable for wallboard
production. Third, solid solution magnesium (magnesium not present in the dolo-
mite) is much more soluble under FGD conditions than dolomite. Magnesium provided
by the dissolving limestone generally improves FGD system performance. For the
above reasons, it is important to quantify not only the total magnesium carbonate
present in the limestone, but also the fractions of magnesium present in the dolo-
mitic and solid solution forms.
The final analytical test performed on candidate limestones is the EPRI grindabil-
ity test. This test procedure is described in the EPRI FGD Chemistry and Analyti-
cal Methods Handbook Q). The results can be used to estimate the Bond Work Index,
which in turn can be used to estimate the specific energy input needed to produce a
limestone grind with a given particle size distribution. Techniques which can be
used to estimate the specific energy input for grinding limestone are described in
detail in another EPRI report (2).
Limestone Reactivity
Limestone reactivity is a measure of how quickly a limestone dissolves under FGD
scrubber conditions. Limestone reactivity influences the operating pH of the FGD
system and can therefore affect overall limestone utilization, the alkalinity of
the scrubbing solution, and the S02 removal rate. A more reactive limestone
requires less reagent to maintain a constant S02 removal rate, or alternately,
maintains a higher S02 removal rate at a constant utilization.
EPRI has developed a licensable procedure to measure limestone reactivity. Con-
siderable testing of this procedure has been conducted to characterize the effect
of solution pH and composition on the limestone dissolution rate. One of the key
findings of this work is that certain chemical species can inhibit limestone disso-
lution. These species include dissolved sulfite, magnesium, and aluminum fluoride
complexes.
The inhibiting effect of sulfite is important because sulfite causes changes in a
limestone's reactivity. In the absence of sulfite, most limestones dissolve at
about the same rate (3). When sulfite is present, limestones dissolve at rates
which can vary by as much as a factor of five or more at the conditions employed in
the reactivity test. Consequently, meaningful measurements of limestone reactivity
3A-123
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can only be conducted in the presence of sulfite. The EPRI reactivity procedure
allows limestone dissolution tests to be performed at sulfite concentrations nor-
mally found in FGD systems (i.e., calcium sulfite relative saturation levels up to
5.0).
Magnesium is a relatively mild inhibitor, but it may be important for systems in
which the dissolved magnesium concentration is high. Aluminum fluoride complexes
can cause significant deterioration in the performance of wet scrubbers, even at
aluminum concentrations as low as a few ppm (4). Fortunately, severe aluminum
fluoride "blinding" is encountered only rarely and is generally associated with
upsets in the particulate control system which allow high amounts of fly ash (the
source of aluminum) to enter the scrubbing liquor.
Experimental test results have been used to produce a model which predicts the
limestone dissolution rate as a function of solution composition and pH. This
model has been incorporated into a developmental version of EPRI's FGDPRISM which
allows the effects of limestone reactivity to be quantified for systems having
different designs and chemistries. An example illustrating the use of FGDPRISM for
evaluating limestones with different reactivities is presented later in this paper.
Magnesium Availability
The amount of soluble magnesium which can be obtained from a dissolving limestone--
the magnesium avai1abi1ity--is another important characteristic to consider when
selecting limestones for use in FGD systems. The effect of magnesium on system
performance is generally beneficial. However, in some cases, it may have rela-
tively little effect or may be detrimental.
In low-chloride systems (systems operating on boilers burning low-chloride coal),
soluble magnesium can enhance S02 removal by increasing the level of dissolved
alkalinity. Similar improvements are noted in high-chloride systems. These sys-
tems normally operate with high concentrations of dissolved calcium and chloride,
which reduce the operating pH and S02 removal relative to lower chloride systems.
Magnesium has been found to offset these detrimental effects by replacing calcium
ions and reducing the dissolved calcium concentration. S02 enhancement by
dissolved magnesium is normally associated with natural oxidation systems.
3A-124
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However, magnesium can enhance S02 removal in both low and high chloride forced
oxidation systems as well (5).
On the other hand, magnesium may be of little benefit in systems already containing
high concentrations of magnesium. This situation might be encountered in systems
which utilize cooling tower blowdown containing magnesium as the source of F6D sys-
tem makeup water. Adverse effects from elevated magnesium levels have also been
observed and include reduced limestone utilization and degradation of the settling
properties of the waste solids (2). Thus, the benefits associated with available
magnesium vary depending on system chemistry.
The amount of magnesium in a limestone that is soluble in F6D systems will depend,
in part, on the form of magnesium present in the limestone. Dolomite dissolves
very slowly under scrubber conditions, whereas magnesium present as the solid solu-
tion dissolves at a rate comparable to that of calcium carbonate. (Experimental
results pertaining to the dissolution rates of dolomite and solid solution magne-
sium are presented in the experimental section of this paper.)
A measure of the form of the magnesium carbonate can be obtained, as discussed
previously, using XRD and IR methods. One limitation of these procedures, however,
is that they have a dolomite detection limit of about 1%. Many limestones being
considered for use in F6D systems have dolomite concentrations lower than this.
Therefore, an additional experimental technique for measuring dolomite has been
developed. This procedure is conducted in conjunction with the EPRI reactivity
test described in the previous section.
Since magnesium is usually beneficial in FGD systems, it is desirable to select
limestones that will provide at least some soluble magnesium. In general, however,
the level of dolomite in a limestone increases as the total amount of magnesium
carbonate increases. Since dolomite may adversely affect scrubber performance,
ideal limestones are those which contain higher proportions of soluble magnesium.
The laboratory procedures described in this section are designed to distinguish
between the two forms of magnesium and are therefore useful in identifying
limestones which are better suited for use in FGD systems.
3A-125
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Performance Modeling with FGDPRISM
EPRI has developed a comprehensive computer model (FGDPRISM) which simulates many
of the physical and chemical phenomena which are important to the operation of wet
FGD systems. For a typical application, the model is configured for FGD system
design parameters such as absorber height, nozzle header configuration, liquid-to-
gas ratio, reaction tank size, etc, specific to the FGD system being simulated.
Additional information on FGDPRISM, along with details on the techniques used to
perform FGD process simulations, are described in a separate paper (6).
The current version of FGDPRISM (Release 1.1) contains a relatively simple model
for estimating limestone dissolution and is suitable for obtaining simulation
results over a moderate range of operating conditions. A more rigorous limestone
dissolution model has been developed under this program which more accurately simu-
lates the physical and chemical phenomena controlling limestone dissolution in FGD
systems. This model has recently been incorporated into a developmental version of
FGDPRISM. This allows reactivity measurements obtained through the EPRI reactivity
procedure to be used directly as inputs to FGDPRISM.
Case Study - FGDPRISM Modeling. An example is described below showing how FGDPRISM
simulation techniques are used to determine the effects of alternative limestone
reagents on FGD system performance. The example shows the results of FGDPRISM
simulations for four hypothetical limestones having different reactivities and
magnesium availabilities.
Simulations were conducted for both "low" and "high" reactivity limestones. The
reactivity parameters used in this example represent a factor of three difference
in reactivity as measured by the EPRI procedure and represent a range in reactivity
that incorporates most of the limestones evaluated to date. Similarly, simulations
were conducted at two levels of available magnesium. For the low and high magne-
sium cases, magnesium carbonate levels in the limestone were set at 0.6 and 3.0
weight percent. In each case, it was assumed that 50% of this magnesium would
dissolve into the scrubbing liquor. The four hypothetical limestones selected for
this example consist of the four possible high/low combinations of reactivity and
magnesium availability.
3A-126
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FGDPRISM was used to simulate a "generic" natural-oxidation FGD system treating
flue gas from the combustion of a high-sulfur (4.1%), high-chloride (0.22%) coal.
Other important design factors used in this Illustration are summarized in Table 2.
The results of the FGDPRISM simulation are presented in Figure 2. The figure shows
predicted S02 removal versus limestone utilization for each of the four hypotheti-
cal limestones. The results illustrate several important aspects regarding the
relative effects of reactivity and magnesium availability. First, consider the
effect of limestone reactivity. For the two limestones having lower magnesium
availability, 85% S02 removal is predicted at limestone utilizations of 95% for the
higher reactivity limestone and 92% for the lower reactivity limestone. Given the
relatively large difference in reactivities used in the example, the predicted
difference in limestone utilization is rather small.
More significant effects of limestone reactivity on limestone utilization are pre-
dicted at lower utilization levels. For the two limestones having lower magnesium
availability, 90% S02 removal is predicted at limestone utilizations of 89% and 82%
for the high and low reactivity limestones, respectively. Here, the difference in
the total limestone consumption becomes a more important economic factor. In
addition, lower limestone utilization has been associated with increased mist
eliminator scaling rates (7). In this situation, maintenance costs associated with
an increased mist eliminator cleaning frequency could easily justify selecting the
more reactive reagent.
Figure 2 also shows the effect of selecting a limestone which can provide higher
levels of dissolved magnesium in the scrubbing liquor. For the high-chloride,
natural-oxidation case considered here, magnesium helps offset the reduced FGD
system performance associated with high dissolved calcium chloride concentrations.
The results show that increasing the level of available magnesium carbonate from
0.3% to 1.5% of the limestone can have a significant effect on S02 removal at a
given limestone utilization.
The results for the specific case presented 1n Figure 2 indicate that significant
improvements in process performance could be realized by selecting a limestone with
higher reactivity and/or magnesium availability. There are, of course, other
methods that can be employed to improve S02 removal or obtain higher limestone
3A-127
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utilizations. These might include operation at higher liquid-to-gas ratios, the
use of additives, or finer grinding of the limestone reagent. All of these alter-
natives, however, result in some increase in operating costs. In general, there is
little if any correlation between the cost of a limestone and its reactivity or
magnesium availability. For the specific example presented here, reduced operating
costs could be realized by simply selecting limestones with higher reactivities and
magnesium availabilities.
Economic Analyses
The impact of alternative limestones on process performance can be quantified using
the FGDPRISM simulation techniques described in the previous section. With this
information, it is possible to perform economic analyses quantifying changes in
operating costs associated with alternative reagents. A case study illustrating
the approach is described below.
Case Study - Economic Analysis. The most straightforward way to compare candidate
limestones is to simply evaluate costs at equivalent S02 removal levels. This
approach considers the effect of limestone utilization differences on total reagent
consumption, grinding energy requirements, and incremental differences in waste
disposal costs.
An example cost comparison utilizing this approach is presented in Table 3. This
example considers the effect on operating costs for the four hypothetical lime-
stones considered previously during the FGDPRISM simulations. The results of the
cost analysis include incremental differences in operating costs for each of these
limestones. In addition, a break-even reagent cost is calculated for which total
operating costs are equivalent.
For the specific case used in this example, the results in Table 3 show that the
changes in operating costs due to differences in reactivity can range as high as
$250,000 per year (comparing limestones A and B or limestones C and D), amounting
to changes in the effective value of up to $1.60 per ton of limestone consumed.
Costs associated with increased magnesium availability are slightly greater (com-
paring limestones A and C or limestones B and D), amounting to nearly $2.00 per ton
of limestone consumed.
3A-128
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Alternatively, the candidate limestones can be compared at a constant limestone
utilization. This type of analysis can be conducted when incremental changes in
S02 removal can be employed to generate S02 allowances. The results of this
analysis are presented in Table 4. This table includes a comparison of the four
hypothetical limestones at a constant limestone utilization of 90%. The results of
this analysis show more substantial cost differentials between the candidate
limestones for the value of S02 allowances ($300 per ton of S02 removed) assumed in
the analysis. Specifically, differences in the effective values of the alternative
limestones are as high as $4,00 per ton for different reactivities and $5.00 per
ton for different magnesium availabilities.
Other approaches for comparing candidate limestones may be employed depending on
the specific situation of the utility. Alternatives might include changing the
particle size distribution of the limestone or reducing or increasing the liquid-
to-gas ratio. If additives are to be employed, costs for alternative limestones
can consider the impact of limestone properties on the required additive concentra-
tion and/or the additive consumption rate.
EXPERIMENTAL TEST RESULTS
Experimental testing has been conducted to support various elements of the lime-
stone selection package. Selected test results are presented here to illustrate
some of the more important results. Information is provided in the following
areas:
• Improvements in the mass transfer/surface reaction rate limestone
dissolution model used in FGDPRISM to simulate sulfite and magnesium
inhibition; and
• The results of laboratory tests showing the relative dissolution
rates of solid solution magnesium and magnesium in dolomite.
Reactivity Testing
Reactivity testing is accomplished in a specially designed reactor. The reactor
operates in a batch sol1ds/flow-through liquid mode and is capable of providing
unambiguous dissolution data over a wide range of conditions. The reactor is
designed to operate at a constant solution composition as the limestone charge
dissolves. Essentially any solution composition can be tested, including solutions
3A-129
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with calcium sulfite relative saturations up to 5.0. Testing in the presence of
dissolved sulfite is essential for characterizing limestone reactivity in wet FGD
systems.
Over 200 experiments have been conducted to characterize the dissolution rates of a
number of limestones over a wide range of conditions. Based on the results of
these tests, Radian, along with researchers at the University of Texas at Austin,
developed a rate model which empirically modeled the effects of sulfite inhibition
on the limestone dissolution rate (3). The rate model correlates the limestone
surface reaction rate with the relative saturations of calcium sulfite and calcium
carbonate at the limestone surface:
K (l - CaCO, RS)°-5
Surface Reaction Rate = —- — (1)
(caS03 RsjfcaCOj Rs)
where relative saturation (RS) is defined as the product of the activities of Ca~
and CO3 (or SO3) divided by the Ksp of CaC03 (or CaS03). Solutions which are
saturated to a particular solid have a relative saturation of 1.0. Note that the
relative saturation of calcium sulfite appears in the denominator of Eq. 1. As the
calcium sulfite relative saturation increases, the surface reaction rate decreases.
The limestone dissolution process involves series resistances including the surface
reaction rate described by Eq. 1 and mass transfer of ionic species through a
diffusion film surrounding the limestone particle. A computer program is used to
solve for the solution composition at the limestone surface at which the diffusion
rate of the reaction products through the film around the limestone particle is
equal to the surface reaction rate. The value of the proportionality constant, K,
must be determined experimentally and can vary by up to a factor of 10 for dif-
ferent limestones.
During the development of this model, it was recognized that the model failed to
account for the inhibiting effect of magnesium. Additional experimental testing
was conducted at higher magnesium concentrations (up to 150 mM), and a modified
surface reaction rate expression was developed which gave improved predictions of
3A-130
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dissolution rates 1n the presence of elevated magnesium concentrations. The modi-
fied expression for calculating the surface reaction rate is:
Surface Reaction Rate =
K (l - CaC03 RS /)3*°
(2)
(CaC03 RS^CaSOj Rs)
The calcium carbonate relative saturation term in Eq. 2 has the form:
CaC03 RS
(aCa + 0 • 1 aMg)(acOj)
Kp CaC°5)
(3)
where "a" represents the ionic activities of dissolved species at the limestone
surface.
Data comparing the predictive capabilities of the original and modified rate
expressions are shown in Figures 3 and 4, respectively. Note that the modified
model does a much better job of predicting dissolution rates when elevated magne-
sium concentrations are present. The rate model expressed through Eqs. 2 and 3 is
currently being used to evaluate solution composition effects on limestone reac-
tivity and is included in a developmental version of FGDPRISM to model the effect
of limestone reactivity on FGD process performance. However, alternative rate
forms are also under evaluation.
Magnesium Availability Testing
Magnesium released from dissolving limestone can significantly enhance the perfor-
mance of both natural- and forced-oxidation FGD systems. To evaluate the relative
benefits of alternative limestones, however, some measure is required of the amount
of magnesium which is "available" for dissolution.
Magnesium in limestone is present in two forms--relatively soluble solid solution
magnesium and relatively insoluble dolomite. Therefore, estimates for magnesium
availability must consider the dissolution rate of the solid solution magnesium
3A-131
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carbonate relative to solid solution carbonate, and the potential for magnesium
release from the dolomite.
As part of the limestone selection methodology, experimental tests have been devel-
oped to quantify some of these factors. An example of the results from a typical
experimental test is shown in Figure 5. This figure shows the fraction of the mag-
nesium dissolved from the test limestone as a function of time. The result shows a
distinct breakpoint in the curve where the rate of magnesium dissolution (the slope
of the curve) drops sharply. Chemical analyses of solids obtained near the break-
point show that the magnesium-to-calcium ratio is approaching 1.0, an indication
that the solids at this point contain mostly dolomite.
The results 1n Figure 5 can be used to extract information on the dissolution rates
of both solid solution and dolomitic magnesium. The slope of the curve after the
breakpoint is a measure of the dissolution rate of the magnesium fraction of the
dolomite. This rate has been measured for several limestones with dolomite con-
tents ranging from 0.6% to 29%. The dissolution rates of dolomitic magnesium for
these limestones vary somewhat but average about 50 times lower than that for the
calcium/magnesium solid solution (on a fraction per minute basis). Some variation
in the dolomite dissolution rate between different limestones is expected because
the manner in which dolomite is distributed within limestone particles can vary.
The dolomite dissolution rate prior to the breakpoint cannot be measured directly
against the background of the faster-dissolving solid solution magnesium. However,
one can postulate that the initial dissolution rate is very low since little dolo-
mite surface area is initially exposed. The rate most likely rises as the solid
solution matrix dissolves, reaching a maximum level at the breakpoint. Then, the
dolomite dissolution rate decreases as the dolomite itself dissolves and its re-
maining surface area drops off. Based on material balances, along with results of
analytical measurements of the dolomite content of the limestone, it appears that
very little of the dolomite in the limestone dissolves prior to the breakpoint.
One conclusion from the above discussion is that the laboratory procedure can be
used to obtain a measure of the relative amounts of dolomite and solid solution
magnesium present in the limestone. To supplement this estimate, analytical mea-
surements using X-ray diffraction (XRD) and infrared spectroscopy (IR) are being
3A-132
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developed to measure the dolomite concentration directly. So far, these analytical
procedures appear to offer promise as alternative means of measuring the dolomite
concentration. One limitation of these procedures, however, is that accuracy is
limited at dolomite concentrations below about 1%. Many limestones being consid-
ered for use in FGD systems contain dolomite concentrations lower than this.
Laboratory dissolution test data similar to that shown in Figure 5 can also be used
to characterize the dissolution rate of solid solution magnesium. Samples from the
reactor are analyzed for calcium and magnesium to determine the magnesium-to-
calcium ratio as a function of the fraction of the limestone which has dissolved.
Since very little of the dolomite dissolves during the relatively fast period of
solid solution dissolution, the portion of the calcium and magnesium present as
dolomite in the sample can be calculated and subtracted from the actual calcium and
magnesium concentrations. This procedure provides the magnesium-to-calcium ratio
in the solid solution.
Examples of typical results from this analysis are presented in Figures 6 and 7.
These results are for two limestones containing significantly different quantities
of dolomite. Each figure contains two curves. The higher curve represents the
actual ratio of magnesium and calcium in the solid samples. This ratio rises
sharply as the limestone dissolves and ultimately approaches a value of 1.0 (when
only dolomite remains in the solids). The lower curve represents the ratio of
magnesium to calcium in the solid solution after the magnesium and calcium
contributions of the dolomite have been removed. This curve is relatively flat,
which indicates that the solid solution magnesium and calcium are dissolving at
about the same rate. This trend has been observed in samples containing widely
varying dolomite concentrations.
The results described above have practical significance. Since the magnesium in
the solid solution dissolves at about the same rate as the calcium, the availabil-
ity of the solid solution magnesium should be about equal to the overall limestone
utilization.
The experimental results described above provide information on the dissolution
rates of both solid solution and dolomitic magnesium. Based on these results, a
simple model can be used to predict magnesium availability as a function of overall
3A-133
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limestone utilization. The model considers the relative release rates of dolomite
and solid solution magnesium and the residence times of solids within the FGD sys-
tem. The model, however, includes a number of simplifications and is therefore a
rough approximation of the amount of magnesium expected to enter the scrubbing
solution.
Results based on the simple availability model are presented in Figure 8. This
figure shows the fraction of the magnesium which should be available, based on the
laboratory results, as a function of limestone utilization. Curves are presented
for limestones in which the dolomitic fraction of magnesium ranges from 30% to 70%
of the total magnesium concentration (the total magnesium carbonate concentration
used for this example was 1.5%). The model results suggest that the percentage of
the magnesium which is available varies with the fraction of the magnesium present
as dolomite, and should decrease with decreasing limestone utilization at a
constant dolomite concentration.
Figure 8 also contains data obtained during baseline limestone testing on the wet
scrubber pilot unit at EPRI's High Sulfur Test Center (HSTC). These data, which
were obtained under natural-oxidation conditions, show a slight decrease in the
fraction of available magnesium with decreasing utilization. However, the magne-
sium availability in the pilot wet scrubber tests is lower than expected. Based on
laboratory measurements, the magnesium in the dolomite represents about 40% of the
total magnesium for the limestone used in the HSTC pilot unit tests. Therefore,
the expected fraction of available magnesium at, for example, 90% limestone utili-
zation, should be about 60% according to the simple model. Actual available magne-
sium in the pilot unit tests was lower, averaging about 40%. Thus, only about two-
thirds of the expected solid solution magnesium in the HSTC pilot system tests was
actually realized as soluble magnesium.
This trend has also been observed during bench-scale testing of different lime-
stones at the HSTC. Preliminary results from these tests indicate that the amount
of dissolved magnesium actually obtained during tests with several different lime-
stones was somewhat lower than expected, based on the concentration of solid solu-
tion magnesium in the limestone.
3A-134
-------
The specific reason for these differences between the expected and observed mag-
nesium availabilities is not known. However, there are several possibilities.
First, the laboratory tests performed to date have been conducted at pH levels
somewhat lower than those which would occur in actual F6D system reaction tanks.
This was done to allow simultaneous measurements of both the solid solution and
dolomitic magnesium dissolution rates. It is possible that dissolution of solid
solution magnesium may be depressed at conditions closer to those present in FGD
system reaction tanks. Additional experimental testing is in progress to evaluate
this possibility.
Second, the laboratory tests are performed at high calcium sulfite relative satura-
tions; however, calcium sulfite does not actually precipitate during these tests.
In contrast, calcium sulfite precipitation occurs continuously in actual FGD
systems (including the HSTC pilot and bench-scale systems). It is conceivable that
magnesium may coprecipitate in the precipitating calcium sulfite crystal matrix.
Coprecipitation of foreign ions within the calcium sulfite crystal matrix is well
documented and is a significant consumption mechanism for FGD additives such as
dibasic acid (DBA) and formate. Coprecipitation of magnesium ions, if it occurs,
could result in lower apparent magnesium availabilities.
The objective of the laboratory tests, as currently employed, is to obtain a mea-
sure of the relative amounts of dolomite and solid solution magnesium in limestone.
Differences in these values between alternative limestones should provide at least
a relative indicator of the amount of magnesium which will be available under FGD
conditions. However, additional testing will be required to refine predictions of
the actual amount of magnesium which will enter the scrubbing liquor.
CONCLUSIONS
• A package of capabilities has been assembled to assist utilities in
the selection of limestones for use in wet FGD systems. The package
can be used for utilities constructing new FGD systems or as a cost-
effective means for considering alternative limestones in existing
FGD systems.
• The package consists of analytical measurements, reactivity testing,
magnesium availability testing, process simulations using FGDPRISM,
and economic analyses. The result is a comparison or ranking of the
relative costs associated with alternative reagent sources which
3A-135
-------
considers both the properties of the reagent as well as design,
chemistry, and operating requirements of the F6D system.
• The results of economic analyses show that reagent properties can
affect overall operating costs. This provides utilities with the
opportunity to select reagents which will maximize the performance
of the FGD system, and at the same time, minimize operating costs.
ACKNOWLEDGMENTS
The work reported in this paper is the result of research carried out in part at
EPRI's High Sulfur Test Center (HSTC) located near Barker, New York. We wish to
acknowledge the support of the HSTC cosponsors: New York State Electric and Gas,
Empire State Electric Energy Research Corporation, Electric Power Development
Company, Ltd., and the U.S. Department of Energy. The cosponsors provide valuable
technical review of the work in progress as well as funding test center operations.
REFERENCES
1. FGD Chemistry and Analytical Methods Handbook, Volume 2: Chemical and Physi-
cal Test Methods. Revision 1, CS-3612, RP 1031-4, TOL No. 5, Electric Power
Research Institute, Palo Alto, California, November 1988.
2. EPRI High Sulfur Test Center Test Report: Guidelines for Selecting Limestone
Reagents for Wet FGD Systems, Draft Report, RP 1877, Electric Power Research
Institute, Palo Alto, California, February 1991.
3. Jarvis, J.B., et al. "Development of a Predictive Model for Limestone Disso-
lution in Wet FGD Systems," prepared for the EPA/EPRI First Combined FGD and
Dry S02 Control Symposium, St. Louis, Missouri, October 25-28, 1988.
4. Farmer, R.W., J.B. Jarvis, and D.A. Stewart. "Effects of Aluminum/Fluoride
Chemistry on Wet Limestone Flue Gas Desulfurization," 1987 Spring National
AIChE Meeting, Houston, Texas, March 29-April 2, 1987.
5. Jarvis, J.B., T.W. Trofe, and D.A. Stewart. "Effect of High Dissolved Solids
on Bench-Scale FGD Performance," prepared for the EPA/EPRI Symposium on Flue
Gas Desulfurization, New Orleans, November 1-4, 1983.
6. Noblett, J.G., D.P. DeKraker, and R.E. Moser. "FGDPRISM, EPRI's FGD Process
Model--Recent Applications," prepared for the EPA/EPRI 1991 S02 Control Sympo-
sium, Washington, D.C., December 3-6, 1991.
7. Colley, J.D., et al. "Process Troubleshooting at a Utility Limestone FGD
System," Proceedings: Eighth Symposium on Flue Gas Desulfurization. Vol. 2.
CS-3706, Electric Power Research Institute, Palo Alto, CA, November 1984.
3A-136
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Umwtone Properties
Composition
Hardness
Magnesium AvaifabiMy
Reactivity
•^|-(?!^i|4'.|npu|iigX'
Coal Composition
SO? Production
Type 0! Waste Product
Limestone PSD
FGD System Design
Makeup Wafer Composition
Cost Input
Delivered Reagent Cost
Energy Cost
Waste Disposal Cost
Value of SO? Allowances
FGOPRISM Modeling
Cost Analysis
». -* ¦ PT0C8M OilMiaSli
SO2 Removal
Limestone Utilization
Operating pH
Byprcxfuct Gypsum Composition
tot Impad cm Operating Costs
Breakeven Reagent Costs
limestone Ranking
Figure 1. Limestone Selection Flow Chart
OJ
>
¦
OJ
¦vi
6.0
SB
f 54
l "
| 50
4.8
S
7 4.8
Q-
4.4
~ Low Mfl (0 -15 mM/L)
« MkJ Wg (50 mM/L)
a High Wg (100-150 mM/L)
~ 9
4.0
3.8
- Log (Experimental Flux)
Figure 3. Comparison of Predicted and Experimental
Fluxes for the Original Dissolution Model
limestone D
Limestone C
Limestone B
Limestone A
Limestone
fteacMvttv
Ma Availability
A
Low
Low
B
High
Low
C
Low
High
D
High
High
78 80 84 88
Percent Limestone Utilization
92
96
100
Figure 2. FGDPRISM Simulation Results for the
Effect of Limestone Reactivity and Magnesium Avail-
ability on Limestone Utilization and S02 Removal
5.8
5.6
5,4
5.2
4.8
4.4
~ Low Mfl (0-15 mM/L)
n Mid Mg (50 mM/U
m High Mg (100 -150 mM/L)
36
3.8
- Log (Expeflmental Flux)
Figure 4. Comparison of Predicted and Experimental
Fluxes for the Modified Dissolution Model
-------
1.0
0.9
Breakpoint
0.7
0.6
i 05
| 0.4
|
5 0.3
0.2
II.
0.1
0.0
200 400 600 800 1000 1200 1400 1600 1800
Time, minutes
Figure 5. Typical Experimental Results Showing
the Fraction of MgC03 Dissolved as a Function of
Time
1.0
0.9
| o.e
3
£ 0.7
Overall Composition
(Measured)
i 0.5
c
0.4
Solid Solution Composition
(Calculated)
0.3
0.2
0.1
0.0
0.9 1.0
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Fraction Dissolved of the Total or Solid Solution Carbonate
Figure 7. Comparison of the Magnesium-to-Calcium
Ratio vs. Fraction Dissolved for Brassfield Limestone
(19.9% HgC03 with 61% of MgC03 present as Dolomite)
0.20
0.16
0.16
0.14
0.12
Overall Composition
(Measured)
0.10
i
c
0.06
0.06
3
I
0.04
SaNd SaMkm CompoaWon
(Calculated)
0.02
0.00
0.0 0.1 02 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Fraction Dtssolvsd o< the Total or So#d Solution Carbonate
Figure 6. Comparison of the Magnesium-to-Calcium
Ratio vs. Fraction Dissolved for Murphy Limestone
(3.3% MgCOj with 20% of MgCOj present as Dolomite)
100
- 30 percent
E
1
I
I
I
SO percent dolomite
- 70 percent
¦ - HSTC pilot (yttam
100
Limestone uWtzetton, percent
Figure 8. Comparison of Modeling Results for
Magnesium Availability and Test Results from
Baseline Limestone Testing at the HSTC
-------
Table 1
SUMMARY OF INFORMATION OBTAINED AND OBJECTIVES OF EACH ELEMENT
IN THE LIMESTONE SELECTION PACKAGE
Selection Element
Information Obtained
Objective
Limestone Supply Survey
Delivered costs
Limestone availability
Preliminary screening to
identify candidate
1imestones
Chemical Analyses
Calcium carbonate, wt.%
Magnesium carbonate
(total), wt.%
Dolomite, wt.%
Inerts
Preliminary estimate of
reagent and disposal costs
Impact of inerts and dolo-
mite on gypsum byproduct
composition
Preliminary estimate of
magnesium availability
j Grindability Test
Grindability Index
Bond Work Index estimate
Estimate of grinding
energy costs and limestone
particle size distribution
| Reactivity Measurement
Limestone dissolution
rate constant
Input to FGDPRISM
1 Magnesium Availability
| Measurement
Available magnesium
Total available carbonate
Final estimate of magne-
sium availability
Input to FGDPRISM
| FGDPRISM Modeling
S02 removal
Limestone utilization
(consumption)
Solids composition
Quantify process
performance
Input for cost analysis
1 Economic Analyses
Impact of limestone prop-
erties on operating costs
Final limestone ranking
3A-139
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Table 2
SYSTEM DESIGN PARAMETERS USED FOR FGDPRISM SIMULATIONS
Parameter
LIMESTONE PROPERTIES
CaC03, wt.%
MgC03, wt.%
Inerts, wt.%
Available Magnesium, %
Particle Size Distribution
(% <325 mesh)
FLUE GAS PROPERTIES
S02, ppmv
HC1, ppmv
FGD SYSTEM
Oxidation Mode
Waste Solids Content, %
Absorber Design
S02 Oxidation, %
Recycle Solids Content, %
L/G Ratio, gal/macf
Specifications
Low Mq Limestone
96.4
0.6
3.0
50
90
High Mq Limestone
94.0
3.0
3.0
50
90
2500 (4.15% S coal)
120 (0.22% CI coal)
Natural
65
Spray Tower - Countercurrent
20
12
115
3A-140
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Table 3
SCENARIO 1 COST ANALYSIS
Scenario: Use the increase in reactivity and soluble magnesium to increase the
limestone utilization at a constant S02 removal rate.
Limestone A
Available Magnesium Low
Reactivity Low
S02 Efficiency (%) 90
Limestone Utilization 82.4
(*)
Limestone Consumption 170,500
(tons/yr)
Limestone B Limestone C Limestone D
Low High High
High Low High
90 90 90
88.5 90 92.2
158,700 156,300 152,600
Limestone Cost1 2,557,000 2,381,000 2,345,000 2,289,000
($/yr @ $15/ton)
Grinding Energy 132,800 123,700 121,800 118,900
Costs (S/yr)5
Waste Disposal Costs 171,700 104,500 89,470 68,120
(S/yr)3
SO, Removal Credit 0 0 0 0
(S/yr @ $300/ton)
Limestone-Related 2,862,000 2,609,000 2,556,000 2,476,000
Operating Costs
(S/yr)
Operating Cost 0 252,700 305,600 385,800
Savings (S/yr
Relative to
Limestone A)
Breakeven Limestone 15.00 16.59 16.93 17.43
Cost (S/ton
Relative to
Limestone A)4
1500 MW boiler, 65 percent capacity factor.
zEnergy cost of $0.05/kWh. Bond Work Index of 10. Methodology in Reference 2.
3Waste disposal costs for unused limestone and inerts only. Disposal cost of
$3.72/ton of wet solids (0 65% solids).
Alternative limestone cost which would give total operating costs equal to the
baseline (Limestone A).
3A-141
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Table 4
SCENARIO 2 COST ANALYSIS
Scenario: Use the Increase 1n reactivity and magnesium availability to increase
the S02 removal efficiency at a constant limestone utilization.
Limestone A Limestone B Limestone C Limestone D
Available Magnesium Low Low High High
Reactivity Low High Low High
S02 Efficiency {%) 87 89.4 90 91.7
Limestone Utilization 90 90 90 90
(*)
Limestone Consumption 150,900 155,000 156,300 159,300
(tons/yr)
Limestone Cost1 2,263,000 2,326,000 2,345,000 2,389,000
(S/yr 0 $15/ton)
Grinding Energy 117,500 120,800 121,800 124,100
Costs (S/yr)
Waste Disposal Costs 86,350 88,730 89,470 91,160
(S/yr)3
SO, Removal Credit 0 702,800 878,500 1,376,000
(S/yr 0 S300/ton)
Limestone-Related 2,467,000 1,832,000 1,678,000 1,228,000
Operating Costs
(S/yr)
Operating Cost 0 634,700 789,500 1,239,000
Savings (S/yr
Relative to
Limestone A)
Breakeven Limestone 15.00 19.09 20.05 22.78
Cost (S/ton
Relative to
Limestone A)4
1500 MW boiler, 65 percent capacity factor
2Energy cost of S0.05/kWh. Bond WOrk Index of 10. Methodology in Reference 2.
3Waste disposal costs for unused limestone and inerts only. Disposal cost of
S3.72/ton of wet solids (0 65% solids).
^Alternative limestone cost which would give total operating costs equal to the
baseline (Limestone A).
3A-142
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)
MAGNESIUM-ENHANCED LIME FGD REACTION
TANK DESIGN TESTS AT EPRI'S HSTC
James H. Wilhelm
Codan Associates
2394 Charros Rd.
Sandy, Utah 84092
Miriam Stohs
Steve Sitkiewitz
Radian Corp.
8501 Mo-Pac Blvd
Austin, TX 78720-1088
Robert E. Moser
EPRI
3412 Hillview Ave.
Palo Alto, CA 94303
HSTC COSPONSORS
The work reported in this paper is the result of research carried out at EPRI's High Sulfur Test
Center (HSTC) in Barker, New York. We wish to acknowledge the support of the HSTC
cosponsors, New York State Electric and Gas, Empire State Electric Energy Research Corp., New
York State Energy Research and Development Authority, Consol, Electric Power Development
Corporation (Japan) and the U.S. Department of Energy. The cosponsors provide valuable
technical review of the work in progress, as well as funding test center operations.
3A-143
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Intentionally Blank Page
3A-144
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MAGNESIUM-ENHANCED LIME FGD REACTION
TANK DESIGN TESTS AT EPRI'S HSTC
ABSTRACT
A novel reaction tank design was developed and tested at EPRI's High Sulfur Test Center. The
goal of the program was to improve dewatering characteristics of crystals from magnesium-
enhanced lime scrubbing systems. The reaction tank design combines crystallization, clarification
and thickening into a single process reactor known as the CCRT (Classifying Crystallizer Reaction
Tank). The best performance results were achieved with the addition of a high-pH reaction stage
known as a premix slurry tank (PMST) to the CCRT flowsheet. The resulting system achieves
improved dewatering characteristics by producing conditions that improve crystal growth while
minimizing the creation of fine particles.
Results of the testing at the HSTC indicate that the CCRT/PMST combination produces crystals
which settle at higher rates to higher underflow concentrations than crystals from conventional
magnesium-enhanced lime scrubbing systems. Filtration rates and cake solids concentrations are
also significantly higher. Performance results suggest that savings in capital costs may be achieved
due to smaller dewatering equipment sizes in new systems, and that operating costs may be lower
due to the reduction in moisture content of the byproduct solids. The PMST was also shown to
improve crystal dewatering properties when used with a conventional Mg-lime slurry scrubbing
process. Retrofit of the reactor and/or premix tank to existing systems is also possible to improve
sludge dewatering properties and to lower disposal costs.
Preceding page blank
3A-145
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MAGNESIUM-ENHANCED LIME FGD REACTION
TANK DESIGN TESTS AT EPRI'S HSTC
INTRODUCTION
Magnesium-enhanced lime (Mg-lime) scrubbing systems have a history of reliable performance
along with high sulfur dioxide removal efficiencies. However, the byproduct solids from these
processes are typically wetter than solids from processes that do not use magnesium. For
example, thickeners in conventional Mg-lime service are typically sized for 2 to 4 times the unit
areas of thickeners in processes that do not use magnesium, and thickener underflow
concentrations are usually 25 to 30 wt.% solids compared to 35 to 45 wt.% in unoxidized
limestone scrubbing systems. Consequently, larger thickeners and filters are required in Mg-lime
systems, and higher disposal costs are incurred than would be possible with solids having better
dewatering characteristics.
The poor dewatering characteristics of Mg-lime solids are a result of their shape and relatively
small particle size. It is thought that the high concentrations of soluble magnesium, sulfite and
sulfate result in high relative saturations for calcium solids around the dissolving lime particles.
These high relative saturations result in the formation of small particles with high surface area. In
addition, the calcium sulfite crystal lattice contains magnesium and sulfate solids precipitated in a
solid solution. The presence of these impurities in the sulfite crystals apparently makes the crystals
more sensitive to shear from pumps and agitators1-2. Consequently, larger crystals have been
produced in full-scale systems by lowering the suspended solids concentrations in scrubbing
slurries, which lowers the average number of passes the particles make through the recirculation
pumps and reduces the amount of panicle to panicle attrition.
As a result of the need for improved dewatering characteristics in magnesium-enhanced lime
scrubbing systems, EPRI developed the classifying crystallizer reaction tank (CCRT) design. The
CCRT was designed for operation at the High Sulfur Test Center (HSTC) on the mini-pilot plant
(0.4 mw) at New York State Electric and Gas Corporation's (NYSEG) Kintigh Station. The goal
3A-146
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of the test work was to improve the settling and dewatering properties of waste solids from Mg-
lime FGD systems. The improved dewatering properties would result in reduced costs and
improved performance of Mg-lime scrubbing systems.
CCRT DESIGN
The full-scale design concept for the CCRT is similar to a solids-contact clarifier as illustrated in
Figure 1. A clear liquor is recirculated in the scrubber to eliminate production of fine particles due
to pump and agitator contact/shear. The liquor from the scrubbers flows to the crystallization zone
of the CCRT where lime is added in a controlled environment to produce the best conditions of
chemistry, agitation and residence time for large crystals. The reacted slurry is then clarified before
being returned to the scrubber. The solids are thickened and sent to final dewatering.
The CCRT is intended to replace the thickener and recirculation tank in existing Mg-lime systems.
One of the goals of the design was to produce crystals with a high enough settling rate that the size
of the CCRT would be similar to existing recirculation tanks in full-scale systems.
To test the concept the CCRT was designed for the 18-inch diameter mini-pilot absorber, which
processes flue gas at a rate of 750 scfm. The S02 concentration in the flue gas is controlled by
spiking. The absorber consists of a single spray header and a tray. Slurry or liquor is pumped to
the spray header with a centrifugal pump.
The pilot-scale design concept for the CCRT in the mini-pilot is shown in Figure 2. The idea was
to take a rectangular slice of the full-scale CCRT tank, because of the difficulty of installing a
circular tank with thickener-type rakes on such a small scale. The crystallization zone of the CCRT
was designed with a low-shear agitator and with flexibility to vary pH, suspended solids
concentration, feed location, and residence time to optimize crystal growth. A sloped bottom was
used in the thickening zone to simplify the design. The clarification zone was designed with the
capability of using inclined plates to improve the removal of solids from the recirculating liquor.
The unit could be operated with or without the inclined plates and with or without polymer addition
to improve settling rates.
3A-147
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A premix slurry tank (PMST) was later added to improve chemical conditions for crystal growth.
A simplified illustration of the CCRT with the PMST is shown in Figure 3. Scrubbing is
accomplished with a clear liquor. The liquor returns from the absorber to the crystallization zone
where the pH is increased to about 6.5 by reaction with effluent from the PMST. The resulting
slurry flows to the thickening section of the CCRT where the solids progress downward, and the
liquor rises upward and is clarified to be returned to the scrubber.
A portion of the thickened underflow is pumped to the premix tank where lime is added. The pH
in the PMST is kept at 10 to 11 to insure that all of the magnesium is precipitated. Most of the
soluble sulfites and sulfates in the CCRT underflow are also precipitated in this tank. The
objective is to precipitate the crystals in the PMST in an environment with little or no soluble
magnesium. The PMST also contains a high concentration of seed crystals, which reduces the
relative saturation of the precipitating solids and enhances crystal growth. These same crystals
then serve as seed crystals as the PMST effluent flows to the crystallization zone of the CCRT to
complete the precipitation reactions and to redissolve the magnesium. Waste solids are fed to a
centrifuge for final dewatering.
TEST PROGRAM DESCRIPTION
The mini-pilot plant was first tested in a typical Mg-lime flowsheet to compare results with
performance of full-scale systems. Following these baseline tests, the CCRT was installed and
evaluated in shakedown tests. Parametric tests then followed to measure the influence of the major
variables. The PMST was added, and tests were conducted to evaluate the critical variables that
govern its performance. A final set of tests was conducted to investigate the addition of the PMST
to the conventional Mg-lime slurry process.
Testing involved establishing the equipment configurations, starting the system with specified
operating parameters, adjusting the chemistry, operating for three solid-phase residence times, and
sampling the product slurry and process streams for analysis. Process data, such as temperatures,
pressures, flow rates, and S02 removal efficiencies, were collected by the Westinghouse data
acquisition system and hourly averages were downloaded to a PC. Data taken during upsets were
ignored.
3A-148
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Liquor, solid, and slurry samples were collected and analyzed for major chemical species. Ideally,
three full sets of steady-state samples were to be analyzed for each test, but some tests consisted of
a single set of samples so that the effects of many variables could be evaluated in the allotted time.
Solids properties were evaluated using three characterization tests: a settling test, a filter leaf test,
and a centrifuge product solids concentration test. The settling test was established to compare the
amount of thickener area (unit area in ft-/t/d) required to reach a fixed underflow concentration of
30 wt.% solids. The ultimate settled underflow concentration after 24-hours of settling was also
determined.
The filter leaf test was conducted to compare form filtration rate, which is the rate at which the filter
cake is formed under preset testing conditions. Cake solids concentrations were also measured
after pulling air through the cake under fixed conditions designed to simulate full-scale vacuum
filter operation.
The centrifuge product from the mini-pilot centrifuge was sampled, and the suspended solids
concentration was measured. The centrifuge was operated at constant conditions of bowl speed
and scroll to bowl differential. Since the feed rate and concentration of solids fed to the centrifuge
varied with the test conditions in the CCRT, the results of the centrifuge product measurements are
not presented here.
TEST RESULTS
The early screening tests established levels of the variables that gave most favorable operating
results. The pilot plant was then operated with these established parameters while conducting the
major, long-term tests. An example of these early decisions include the decision to operate with
thiosulfate addition in all tests to eliminate the varying sulfate concentrations that occurred without
thiosulfate. If left unchecked, the impact of the variable sulfate concentration had the potential for
masking the influence of other variables. Consequently the thiosulfate concentration was
maintained at 10(X) ppm in the liquor for most of the test program.
Early testing also showed that polymer would not be required under most test conditions.
Consequently the use of polymer was abandoned except in some special tests.
3A-149
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The performance of the system was also evaluated with and without the inclined plates in the
clarification zone. It was found that the inclined plates provided only marginal benefits, and the
plates were eliminated in subsequent testing.
Baseline CCRT Results
The following is a list of the significant process variables used for baseline testing of the CCRT:
Chemistry: 5600 ppm sulfite
2900 ppm magnesium
1000 ppm thiosulfate
pH 6.5 at scrubber recirculation pump
L/G of 21
Inlet sulfur dioxide = 2500 ppm
When the CCRT is employed, a clear scrubbing liquor is recirculated in the absorber.
There is an improvement in solids dewatering characteristics associated with the use of clear liquor
for scrubbing, because the crystals are not recirculated through the centrifugal pump and spray
header. In addition, the conditions in the crystallization zone (mixing, points of addition, residence
time and suspended solids concentration) may be controlled to give optimum results. The
improvement provided by the baseline CCRT over the conventional Mg-lime slurry process is
illustrated in Figure 4. The use of the CCRT reduces the thickener unit area from about 24
ft2/t/d to about 16 ft2/t/d, a reduction of about 33%. Both processes produce solids that filter
rapidly with form filtration rates of about 600 lb/hr/ft2. These rates would correspond to full-scale
filtration rates of about 160 lb/hr/ft2. The filter cake solids concentration is improved by about 2
percentage points in the CCRT process.
3A-150
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Results with the PMST
The most dramatic improvements in dewatering characteristics were achieved with the combination
of the PMST and the CCRT. During most of the tests approximately one third of the calcium
sulfite crystallization occurred in the PMST. The remaining solids were precipitated in the CCRT
as the PMST effluent was mixed with the return liquor from the absorber.
Figure 5 illustrates the improvement in dewatering characteristics that were achieved with the
combination of the PMST and the CCRT. The thickener unit area dropped to about 3 ft2/t/d at 30
wt.% solids, and at higher unit areas the thickener underflow was able to be thickened to 45 wt.%
solids. Form filtration rates were increased to about 1800 lb/hr/ft2, which could result in full-scale
filtration rates as high as 480 lb/hr/ft2 with higher than normal vacuum filter speeds. The filter
cake solids concentration increased from 45 to 50 wt.%.
Chemical Concentration Effects
Increasing the liquor magnesium and sulfite concentrations caused a decline in solids dewatering
properties in the CCRT tests. With the addition of the PMST the solids produced in the CCRT
flowsheet are much less sensitive to changes in sulfite and magnesium concentrations as illustrated
in Figures 6 thru 9, which compare the changes in dewatering characteristics for the CCRT as a
function of magnesium and sulfite concentrations with and without the PMST.
The improved results and lower sensitivity of the system with the PMST has to do with the
elimination of liquid phase magnesium and sulfite at the high pH that exists in the PMST. As
discussed earlier, the presence of high concentrations of seed crystals in the PMST may also
improve crystal growth. It is thought that these seed crystals, and the low liquid-phase sulfite,
sulfate and magnesium concentrations that exist when the PMST effluent is added to the CCRT,
may also contribute to the dramatic improvements in dewatering characteristics under certain
conditions. Changes in sulfite and magnesium concentrations were made independent of each
other by using sodium in place of magnesium for the sulfite series, and by using chloride in place
of sulfite in the magnesium series.
3A-151
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Results with the PMST in the Mg-lime Slurry Process
Because of the dramatic results achieved with the PMST in combination with the CCRT, tests were
made with the PMST added to the Mg-lime slurry process. In this case a portion of the recirculated
slurry was sent to the PMST where lime was added. The pH was controlled at 10 - 11 in the
PMST as in previous tests. The overflow from the PMST was returned to the recirculation tank
for the absorber.
Figure 10 summarizes the improvements in dewatering characteristics for the baseline process with
the PMST compared to the results without the PMST. The results indicate that the addition of the
PMST cuts the thickener unit area requirement in half and increases the filter cake solids
concentration by 2 percentage points under baseline conditions. The form filtration rate increases
by about 10% with the addition of the PMST.
Process Configuration Summary
Figure 11 summarizes the impact of process configuration on waste solids properties.
Improvements in thickener unit area, filter cake solids concentration, and filtration rate were all
observed with addition of the CCRT and the PMST to the standard Mg-lime process as shown.
Results indicate that the combination of the PMST with the CCRT can lower the thickener unit area
required to achieve 30 wt.% solids from about 24 to about 3 ft2/t/d. The form filtration rate also
improves from about 550 to about 1800 lb./hr./ft2, and filter cake solids concentration improves
from about 43 wt.% to about 50 wt.%.
Another significant improvement is the increase in thickener underflow concentration that
may be achieved. The thickener unit areas reported here are those required to produce 30 wt.%
solids in the underflow. However, the CCRT/PMST combination produces solids that will settle
to 45 wt.% solids at unit areas around 5 ft2/t/d without polymer. This concentration is higher than
the filter cake solids concentration from many full-scale Mg-lime systems, which ranges from 35 to
45 wt.% at the various existing FGD systems. One full-scale option could be to eliminate the final
dewatering step by application of the CCRT/PMST process.
3A-152
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FUTURE TESTING
The encouraging results in these tests at the High Sulfur Test Center have resulted in additional
plans for testing. EPRI will be participating with Dravo Lime Co. and Cincinnati Gas and Electric
Company (CG&E) in further testing of the CCRT / PMST concept at the Miami Fort pilot plant in a
project co-funded by the Ohio Coal Development Office. This program is expected to give further
scale-up and design information on a larger scale and under a different set of flue gas conditions.
Other work is proceeding with application of the PMST alone to existing full-scale scrubbing
systems to improve waste handling characteristics. It is expected that the PMST will be added to
one absorber module of CG&E's East Bend Station in the Spring of 1992. Testing is currently
under way at EPRI's HSTC mini-pilot to predict the effects of the PMST for the specific chemistry
at the East Bend Station.
CONCLUSIONS
The testing of the CCRT and PMST at the HSTC has resulted in several options for improving the
dewatering characteristics of the solids from magnesium-enhanced lime scrubbing systems. The
dramatic improvements, especially the improvements in settling characteristics, will result in
reduced capital and operating costs if used for design of new scrubbing systems. All or part of the
improvements may also be achieved through modification of existing full-scale Mg-lime systems.
In particular the application of the PMST to full-scale systems may be accomplished economically
with significant improvements in settling and filtration characteristics. Further testing is planned
on both pilot and full-scale systems.
EPRI has applied for patents for the PMST/CCRT clear liquor FGD process and for the use of a
PMST with a conventional Mg-lime slurry FGD system. Four utilities, two lime suppliers, and
two FGD system suppliers have signed confidentiality agreements and have been following this
research.
3A-153
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REFERENCES
1. L. B. Benson, A. Randolf, and J. Wilhelm. "Improving Sludge Dewatering in Magnesium-
Enhanced Lime FGD Systems." Presented at the First Combined FGD and Dry S02 Control
Symposium, October 25-28, 1988.
2. A.D. Randolph, S. Mukhopadhyay, B.C. Sutradhar and R. Kendall. "The Double Draw-Off
Crystallizer: A Major Player in the Acid Rain Game?" Department of Chemical Engineering,
University of Arizona, Tucson, Arizona 85721.
3A-154
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From Scrubber
I Return
To
Scrubber
Lime
Bed of Solids
To Dewatering
Figure 1. CCRT Schematic of Full-Scale Design Concept
3A-155
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Absorber Effluent
Crystallization
Zone
Clear Liquor to Scrubber
Clarifier
Zone
Settling Hopper
To Centrifuge
Underflow Recycle
Figure 2. CCRT Schematic
3A-156
-------
Reagent
Absorber
PMST
Recycle
~
Centrifuge
Figure 3. PMST /CCRT Configuration
3A-157
-------
25 t
V/%\k
S 1°-
Baseline
Slurry
CCRT
CD
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oJ=
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iT =S
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1000
800
600
400
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iT
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Figure 4. Comparison of CCRT and Slurry Process Solids
3A-158
-------
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1800
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Figure 5. Comparison of CCRT and CCRT/PMST Solids
3A-159
-------
cs
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20
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100
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Figure 6. Effect of Dissolved Sulfite on Thickener Unit Area
3A-160
-------
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Figure 7. Effect of Dissolved Sulfite on Fitter Cake Solids
3A-161
-------
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Figure 8. Effect of Dissolved Magnesium on Thickener Unit Area
3A-162
-------
60
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Figure 9. Effect of Dissolved Magnesium on Filter Cake Solids
3A-163
-------
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3A-164
-------
~ s: 20
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Figure 11. Process Configuration Effects on Solids Properties
3A-165
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Intentionally Blank Page
3 A-166
-------
Model Description
ity of 2, the rate constant (K) given in Table 1, and the reaction order indicated by (EQ 4) yields a
Thiele modulus of 1.4 and an effectiveness factor of roughly 0.4 (Carberry, 1976). To achieve an
effectiveness of roughly 1 at these conditions requires that the particle diameter be reduced to about 1
|im. Particle size effects are neglected here because their inclusion makes the model so complicated
that coupling with jet mixing calculations would yield an intractable combination.
A rate expression which excludes the diffusional resistances at the particle surface can be obtained
based on a Langmuir-Hinshelwood type analysis (Smith, 1981) of a six-step mechanism for the SO2-
lime reaction. The complete rate expression, based on this mechanism is (Silcox et al., 1987):
[S02] [02]l/2
R°= a + b (EQ1)
where
{l + tfjiscy ^k^[02]1/2+k61}2
A = - ^ - — (EQ 2)
and
B = - r ' (EQ 3)
where the K's and D' are constants and I represents an inert species concentration.
(EQ 1) suggests an empirical power law expression of the form:
dr _ MCa0
Jt ~ ~P^
1 r2 1 1
(EQ4)
where the reaction order, n, is 0.55. This value of n is based on an analysis of the data of Borgwardt
and Bruce (1986). (EQ 4) includes the effects of grain growth due to sulfation in the term rg':
r', = lar3t+(l-a)r3]1/3 (EQ5)
where a=2.72 is the ratio of the molar volumes of CaO and CaSC>4. The data of Gullett et al. (1990)
and Milne et al. (1990) can not be fit with (EQ 4) alone because this expression does not include a
mechanism whereby the reaction rate dramatically decreases after about 40 ms.
One mechanism which can account for the observed decrease in reactivity is surface area loss, i.e., the
interfacial area available for reaction decreases with time, possibly due to grain overlap. Borgwardt
(1989) used the model of German and Munir (1976) to correlate his CaO sintering data:
3B-3
-------
Model Description
rS.-S>
(EQ6)
Pr)-"
jp
where S0 is the initial surface area. When put in differential form, (EQ 6) is inconvenient because —
becomes infinite at t = 0. The empirical rate expression (Silcox et al., 1989),
^ = -k(S-Sa)2 (EQ7)
where Sa is an asymptotic surface area, is more useful for this application. At t = 0, the initial surface
area is Sj. Integrating (EQ 7) and introducing the dimensionless parameters a = S/Sj and aa = Sa/Si
gives:
l -1
o = o.+ (y^- + Si*0 • (E08)
a
The parameter a can be used to correct (EQ 4) for the effects of surface interface loss:
dXc dX 3 Or 2dr
-T = o=? = (-) T- (EQ 9)
dt dt rf rf dl
where Xc is a corrected conversion. Hence, the extent of sulfation of a single grain of CaO is obtained
by integrating (EQ 4), (EQ 7) or (EQ 8), and (EQ 9) in parallel.
2.2 The Particle Dispersion Model
The description of particle transport in turbulent flow has been based on an extension of stochastic
process modeling and turbulence theory (Baxter, 1989). Although sorbent particles are small and
might be expected to follow fluid streamlines, the dilute nature of the injected particle cloud precludes
enough random particle-particle collisions to render them a continuum. Thus, traditional Eulerian
models are not adequate to account for dilute sorbent particle dispersion and history effects. At the
same time Lagrangian Monte Carlo methods (such as the Stochastic Separated Flow model, Shuen,
Chen, and Faeth, 1983) require too many realizations of individual particle trajectories to be tractable
in full-scale simulations with simultaneous reaction for utility boilers. The approach used here is a
Lagrangian particle turbulent dispersion model that tracks the statistics of ensembles or clouds of par-
ticles.
The mean or expected value for the cloud position, {*(/) >, can be computed from the average particle
velocity .-
t
<*(»)> = J = Jix. (EQ 10)
o
3B-4
-------
Session 3B
FURNACE SORBENT INJECTION
Computer Simulations of Reacting Particle-Laden Jet
Mixing Applied to SO2 Control by Dry Sorbent
Injection
Philip J. Smith and Geoffrey D. Silcox
Department of Chemical Engineering
University of Utah
A particle-laden turbulent reacting flow model is described and applied to in-furnace,
dry S02 control in boilers. Sulfur capture by calcium-based sorbents is represented by
a shrinking core model which accounts for surface area loss and product layer diffu-
sion. Sorbent particle trajectories and dispersion are followed with cloud statistics in a
Lagrangian framework. The turbulent fluid mechanics and chemical reactions are
coupled, and solutions obtained for mean and fluctuating velocity, composition, and
particle position. Comparisons are made with data from an U.S. EPA laboratory reac-
tor. Practical implications for S02 control are examined including the effects of jet
velocity, sorbent injection location, boiler load and thermal profiles.
1.0 Background
A significant amount of laboratory and process data have been collected on sulfur capture by calcium-
based sorbent injection. However, the most promising method for extrapolating these data to deter-
mine performance in any one specific boiler seems to be through the application of a predictive com-
puter model. Sulfur capture by sorbent injection involves many physical and chemical processes
whose fundamentals are not yet completely understood. Because of this lack of fundamental knowl-
edge and because computational constraints limit the level of fundamental sophistication that could
be realistically included in any computer model, these computational simulations necessarily incorpo-
rate engineering approximations to some of the subprocesses involved. The controlling mechanisms
in the sorbent injection problem seem to involve the turbulent mixing of the particle-laden jet in vari-
ous geometries (dependent on injection location and boiler configuration) and the sulfate diffusion-
limited heterogeneous reactions of SO2 with CaO. In this paper we explore the potential for applying
computational simulation tools to sorbent injection for sulfur removal. Particular attention is focused
on incorporating an appropriately fundamental mechanism for each of the controlling processes.
3B-1
-------
Model Description
The development of the computational simulations presented in this paper was based on the identifi
cation of controlling mechanisms, developing appropriate engineering descriptions of these individua
subprocesses, evaluating each subprocess model as independently as possible, coupling each subpro
cess in a predictive model and evaluating the coupled simulation. The evaluation was performed fo
simple systems first and then applied to more realistic and complex systems. This paper addresses th
middle stage of the overall simulation process; namely, evaluating the coupled simulation in a rela
tively simple system. The development of each of the key submodels for the controlling processes i
sorbent injection has been done previously. A brief description of these key submodels is given ne>
with reference to where the fundamental work supporting the development can be found. For thi
work we have coupled these submodels into a demonstration simulation model and applied it to a lat
oratory reactor operated by the U.S. EPA (Gullett et al., 1990). This application is presented in Sec
tion 3.0. The extension of this simulation model to full scale systems is briefly presented at the end c
that section.
2.0 Model Description
2.1 The Sulfation Grain Model
A simplified shrinking grain model with a CaS04 "ash" layer was developed, based on the earli<
work by Silcox et al. (1987), and used to analyze recent sulfation data in order to obtain short-tin:
sulfation reaction kinetics for use in a grain model for sulfation. Additional key parameters govemin
the rate of sulfation include the product layer diffusion coefficient, the sintering rate constant, and tl
initial CaO surface area. This sulfation model was developed because other models appear to have di
ficulty predicting short time (35 ms) results.
The short-time sulfation results of Milne et al. (1990) and Gullett et al. (1990) shown in Fig. 1 and
suggest that during the first 40 ms after sorbent injection, the rate of sulfation is very rapid. Subs*
quently, the rate of sulfation declines markedly. The rapid decline in reactivity is usually attributed
surface area loss or sintering of the CaO (Borgwardt, 1989). The approach taken here assumes that tl
initial rapid reaction results from the high surface area of the flash calcined sorbent, acting in comt
nation with rapid intrinsic kinetics. The possibility that the reaction rate is controlled by the rate ¦
diffusion to the particle surface was also examined and found not to be important. It was furth
assumed that the subsequent decline in the reaction rate is due to the accumulation of a CaS04 pro
uct layer and to the loss of available CaO surface area.
The model adopted here assumes that the injected particles are small enough (2 |im) that pore diff
sion through the particle does not control the rate of reaction. This assumption is made for practic
reasons rather than technical reasons. The data of Milne et al. (1990) actually indicate that partic
size may be important at diameters smaller than 2 |im, which is the smallest size they considere
Because of the nonlinear dependence of the sulfation reaction on SO2 concentration, see (EQ 4), ai
due to the product layer diffusion resistance, the calculation of an effectiveness factor in terms ol
Thiele modulus is difficult. Assuming there is no product layer, an initial surface area of 100 m2/g.
temperature of 1050 Celsius, 3000 ppm SO2, a particle diameter of 2 (im, a porosity of 0.5, a tortuc
3B-2
-------
Model Description
The mean particle velocity is related to the mean gas velocity and since for sorbent applications the
only significant forces on the particle are the steady state aerodynamic drag and the weight. In the
Stokes regime (EQ 10) becomes:
= P«l/>- = 2j(«-T)*f/T)rfT. (EQ 13)
0
Further discussion of the derivation and the methodology to obtain 7?£(t) can be found elsewhere
(Smith, 1990).
The model requires no adjustable parameters beyond specification of the turbulent flowfield itself and
is independent of any particular turbulence model. The description of the turbulent flowfield required
by the model is in terms of the mean square velocities and Lagrangian correlation functions. These
are rarely available, especially for the particle phase. In this application approximations for these gas
phase turbulence properties are computed in terms of parameters from the K-e gas turbulence model.
Particle properties have been determined from other application that have been shown to yield reason-
able results.
This particle dispersion submodel, reveals several important characteristics about particle dispersion
in turbulent flow. The dispersion rate does not lend itself to description by Fickian diffusion laws. The
required diffusion coefficient is dependent on the residence time of the particles over significant
regions of the reactor and could be negative valued. In the case of an initially concentrated group of
panicles, the diffusion coefficient has an initial value of 0 and attains a constant value after a particle
residence time which is long compared to particle reaction time scales.
This submodel has been evaluated by comparison to exact solutions, the most accurate alternative
models, and experimental data. It reproduced the exact solutions both numerically and as analytical
functions. These analytical solutions have been used as calibrations for some of the most accurate
models of particle transport in turbulent flows. In a comparison to turbulent dispersion data collected
3B-5
-------
Application
under nine different flow conditions, the model predicted the experimental data of all nine cases
within the experimental error.
2.3 The S02 Corrective Transport and Reaction Model
The mean sulfur dioxide mass fraction, aSOj, in the gas-phase is transported with the local turbulent
continuum. Turbulent mixing of the SO2 must be modelled with an appropriate turbulent mixing
model. In this case differential diffusion of SO2 is not a significant mechanism for variability in local
SO2 concentrations. A gradient diffusion model seems adequate for mean SO2 concentration; thus the
convection, turbulent mixing and reaction of SO2 is described by:
v* (Pva>so2~Dso2v aso2) = sP,so2 (EQ14)
where Dso includes the contribution from a *-e turbulence model, and sp so is the mean SO2 reac-
tion rate by the sorbent.
The mean SO2 reaction rate comes from the grain model described in Section 2.1. The effect of local
fluctuations in the particle number density, nlorb, and corrected conversion, xc, are included through
the stochastic particle dispersion model itself. The contribution of particles with a specific residence
time to the mean reaction rate at a given Eulerian control volume is evaluated by integrating the prod-
uct of the instantaneous values of the Lagrangian particle number flowrate, particle reaction rate, and
a weighting term, w (*., t), based on the positional pdf between the limits of the control volume:
Sp,S02,ijk = J—» Jv(ijk) irp,so2w(xi>')dVdt
where ijk represent the coordinates of the Eulerian cell, the time integral is with respect to residence
time, and q represents the number flowrate of particles. The rp so term in (EQ 15) represents the total
rate of consumption of SO2 by an average sorbent particle within the discretized cloud as a function
of time:
'P,S02 = j,l (1 ~XC)* orb(Ms02/M,orb)) (EQ16)
where atgrb is the mass of the sorbent particle. The dv term in (EQ 15) represents a volume inte-
gral between the boundaries of the Eulerian cell with coordinates ijk.
3.0 Application
3.1 1-D Sorbent Modeling
The sulfation submodel described in Section 2.1 was best evaluated independently of coupling with
the fluid mechanical aspects of the simulations. Additionally, this submodel requires reaction coeffi-
cients that must be obtained from an independent fundamental set of experiments. The approach for
fitting and evaluating this submodel was as follows.
3B-6
-------
Application
l
The long-time, differential reactor data of Borgwardt and Bruce (1986) were analyzed to obtain prod-
uct layer diffusion coefficients. This analysis assumed that the 3 m2/g CaO used in these tests did not
sinter and that the intrinsic chemical kinetic rates were essentially infinitely fast. The isothermal flow
reactor data of Milne et al. (1990) were then used to estimate the initial sorbent surface area and the
surface area loss rate constant. This analysis again assumed that the intrinsic chemical kinetic rates
were infinitely fast. Finally, the complete correlation was compared with the data of Borgwardt and
Bruce (1986), Milne et al. (1990), and Gullett et al.(1990).
Comparisons of the model fit with the entrained flow, isothermal reactor data of Milne et al. (1990),
for 2 |im Linwood hydrate, are shown in Figure 1. The key model parameters obtained by fitting the
model to these data, and to the data of Borgwardt and Bruce (1986), (to obtain Ds) are summarized in
Table 1. Note that the intrinsic reaction rate constant, K, is not a function of temperature and that the
value chosen is so high that, at the conditions examined in this report, the capture levels are unaf-
fected by further increases in K. The predictions shown in Figure 1 assume an initial surface area of
100 m2/g. The model correlates the initial rapid reaction rate and subsequent decline in reactivity
quite well.
The entrained flow, isothermal reactor data of Gullett et al. (1990), for 2 |im Linwood hydrate, are
compared with model predictions in Figure 2. These predictions also assume an initial surface area of
100 m2/g. The model tends to overpredict the measured conversion levels although the disagreement
is less at a slightly higher reactor gas flow rate, 100 versus 80 1pm. Model results also correlate with
the data of Borgwardt and Bruce (1986).
Figure 1 Comparison of Sulfation Submodel Fit with Isothermal Reactor Data of Milne et al. (1990).
Time, s
3B-7
-------
Application
Table 1
Key Sulfation Model Parameters Used in Making All Predictions
• Reaction Rate ^ =
dt PcaO
1 r . 1 1 ,
¦p. + 7T ( -)
* D* r rt
n = 0.55
K = Akexp(-EkA")
Afc = l.xlO^, kmol^"n«m3n_2/s *
Ei-=0.,K
Ds = AppxpK-En/T)
Ad = 4.27x10*', kmol^"n»m^n"Vs
Ed =1.833x104^
• Surface Area Loss — = -k(S- Sa)2
n = 2
Sa = 5000 m^/kg **
kg = Ajex^-E^T)
Aj = 403.1, (ni^/kg)l"n/s
Es = 1.814x104,K
~The value of Ak is set sufficiently high that it is not controlling at any of the conditions examined.
**For predicting Borgwardt's precalcine data, Sa = 3000 m^/kg and dS/dt = 0.
Figure 2 Comparison of Sulfation Submodel Predictions for Isothermal Reactor Data of Gullett et al. (1990).
0.3
c
o
¦<0
©
>
C
O
O
«
c
o
ts
CD
3000 ppm
Ca/S - 0
1050°C
~ Measured. 100 Ipm
A Measured, 80 Ipm
• Predicted
0.0&-
u.O
0.1
Time, s
0.2
3B-8
-------
Application
3.2 2-D Coupled Sorbent Dispersion and Reaction Modeling
The sulfation submodel described in Section 2.1 was coupled with the dispersion and reaction sub-
models of Section 2.2 and Section 2.3 and integrated into an existing turbulent reacting flow model.
Predictions were made for the reactor of Gullett et al. (1990) under two different feedrates (100 1pm
and 30 1pm). No rate constants or other coefficients were adjusted to fit the Gullett et al. (1990) data
but were used as given by other authors (in the case of turbulence parameters) or as determined from
the Milne et al. (1990) data (for sulfation rate parameters). The predicted and measured conversions
for these cases is shown in Figure 3. The significant impact of mixing rate on conversion versus resi-
dence time as measured and discussed by Gullett et al. (1990) is predicted in the simulation. This fig-
ure also shows the predicted particle and gas temperature profile for a given cloud (which in this case
is imperceptibly close) and the normalized surface area (a) as a function of residence time.
The resulting SO2 mole fraction removed from the gas stream for the 1001pm case as predicted by the
simulation is shown in Figure 4. Here the mixing rate of the sorbent with the gas is apparent. The low
values are due to the low calcium to sulfur ratio in these experiments. The importance of jet mixing is
significant even in this case where the laboratory experiment has been tuned as much as possible to
reduce this effect. In real systems this turbulent mixing effect is expected to be one of the dominant
controlling mechanisms.
The model simultaneously predicts local turbulent fluctuations (variance) in all predicted variables
including such things as particle number density, particle residence time, conversion efficiency, spe-
cies concentration, etc. For this case these values are low and no data is available for comparison. Fig-
ure 5 shows the predicted envelope for the particle cloud dispersion for the 1001pm case.
3B-9
-------
Application
Figure 3 Predicted (solid lines) and Measured (symbols) Sorbent Conversion (Xc) as a Function of Residence Time for
Both the 100 Ipm and 30 Ipm Cases of Gullett (1990). This figure also shows the predicted temperature and
normalized surface area for these two cases.
1-
< 0.9-
0.8-
0.7-
0.6-
0.5-
0.4
0.3-
0.2
0.1-
0
CD
9
©
O
CD
t
3
CO
X3
©
N
E
w_
o
o
c
o
'{2
©
>
C
o
O
100 Ip
n tempi
rature
A V
te
3U ipm
nperati
re
h\
V
\
\ 30 Ip
\ surfs
m
ce ares
\
100 Ibr
surfa\
i \
^100 l|
>m conv
srsion
area'
o
30 Ipm
inversic
n
• ;
(/
-1-1200 ^
£
3
s
©
Q.
E
©
1400
= -1000
--800
--600
400
-I-200
0
©
o
tr
CD
D_
"O
c
CD
8
CD
0.1 0.2 0.3 0.4 0.5 0.6 0.7
Residence Time (s)
Figure 4 Mole Fraction of S02 Removed from the Gas Stream for 100 Ipm Case.
2.5 cm
center
line
2.5 cm
0.0
axial location (m)
Parts Per Million of S02 Removed
by Sorbent
0 75 150
3B-10
-------
Application
Figure 5 Predicted Envelope for Particle Cloud Dispersion for 100 Ipm Case. The lines near the centerline show the
mean path for the indicated cloud, the lines near the wall show the location of one standard deviation from the
mean position.
0.014
0.012
— 0.01
o
| 0.008
o5
5 0.006
gj
^ 0.004
Cc
0.002
0
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
Axial Distance (m)
3.3 Boiler Simulation
The sulfation simulation model described in this paper has potential for using controlling mechanisms
derived from more easily controlled small-scale experiments and extrapolating them to full-scale
boiler applications. This model could potentially explore variations in operating situations within one
boiler or between boilers. Full sulfation modelling in such systems has not yet been accomplished;
however, this potential is illustrated by the computational results in Figure 6 which show a mean tra-
jectory for a 2 |im cloud of particles in a commercial wall-fired utility boiler.This computational prob-
lem involves discretization of the partial differential equation set using a non-uniformly spaced three-
dimensional Cartesian grid of 1.3X105 nodes to resolve important features of the combustion process.
Around 60 variables (representing, e.g., components of velocity of the gas, gas pressure, and concen-
tration of various chemical species) are tracked at each node. The trajectories of both coal and sorbent
particles are followed by introducing them into the flowfield induced by the mixing and reaction pro-
cess. Their position in turn influences the velocity, composition, temperature and other fields of the
combustion process. The overall strategy is the same as that illustrated with two-dimensional compu-
tations in Section 3.2. This simulation is illustrative of the concept that the approach taken in this
paper can be applied to full-scale systems.
3B-11
-------
Application
Figure 6 Simulation of a utility boiler showing predicted temperature and velocity vectors at several
computed planes in the three-dimensional combustion chamber. Also note the mean path of a
representative cloud of fine dust particles in the boiler.
Velocity
Vectors
200 m/s
0 m/s
Gas
Temperature
1800 K
300 K
3B-12
-------
Conclusion
4.0 Conclusion
The controlling mechanisms for SO2 removal by dry sorbent injection are assumed to be: the turbu-
lent dispersion rate of the particle-laden jet, and the sulfate layer diffusion controlled heterogeneous
rate of reaction. These two mechanisms have been modelled and coupled with a turbulent reacting
flow simulation code. The submodels have been independently evaluated and the coupled model
(with predetermined coefficients) has been compared to measured data. The comparison demon-
strates that a reasonable description of these two mechanisms explains observed behavior under vari-
ous operating conditions.
The methodology is more universal than this evaluation of bench-scale results. Full combustion sim-
ulations of utility boilers have been questioned by skeptical observers since many of the important
mechanisms are not yet undersood. Sulfur capture by dry sorbent injection involves fewer controlling
mechanisms; and as such, represents an application where computer simulation may contribute to
engineering applications. The approach demonstrated in this paper is intended to illustrate this poten-
tial.
5.0 References
Baxter, L.L. (1989). "Turbulent Transport of Particles," Ph.D Dissertation, Dept. of Chemical Engi-
neering, Brigham Young University, Provo, Utah.
Borgwardt, R. H. (1989). "Calcium Oxide Sintering in Atmospheres Containing Water and Carbon
Dioxide," I&EC Research, 28, 4,493.
Borgwardt, R. H. and Bruce, K. R. (1986). "Effect of Specific Surface Area on the Reactivity of CaO
with S02," AIChE J., 32, 239.
Carberry, J. J. (1976). Chemical and Catalytic Reaction Engineering, McGraw-Hill, New York.
German, R. M. and Munir, Z. A. (1976). "Surface Area Reduction During Isothermal Sintering,"/.
Amer. Ceram. Soc., 59, 379.
Gullett, B. K., Groff, P. W., and Bruce, K. R. (1990). "The Effect of Rapid Mixing and Turbulence on
the Sorbent/S02 Reaction," presented at the 1990 SO2 Control Symposium, New Orleans, LA.
Milne, C. R., Silcox, G. D., Pershing, D. W„ and Kirchgessner, D. A. (1990). "High-Temperature,
Short-Time Sulfation of Calcium-Based Sorbents: II. Experimental Data and Theoretical Model Pre-
dictions," I&EC Research, 29, 2201.
Shuen, J.S., Chen, L.D. and Faeth, G.M. (1983). "Evaluation of a Stochasitc Model of Particle Dis-
persion in a Turbulent Round Jet," AIChE Journal, 29, 167.
3B-13
-------
References
Silcox, G. D., Kramlich, J. C., and Pershing, D. W.,(1989). "A Mathematical Model for the Flash Cal-
cination of Dispersed CaCC>3 and CA(OH)2 Particles," l&EC Research, 28,155.
Silcox, G. D., Chen, S. L., Clark, W. D., Kramlich, J. C., Lafond, J. F., McCarthy, J. M., Pershing, D.
W., and Seeker, W. R. (1987) "Status and Evaluation of Calcitic SO2 Capture: Analysis of Facilities
Performance," EPA-600/7-87-014 (NTIS PB87-194783).
Smith, J. M. (1981). Chemical Engineering Kinetics, 3r<^ Ed., McGraw-Hill, New York.
Smith, P.J. (1990). "3-D Turbulent Particle Dispersion Submodel Development," 1st and 2nd Quarterly
Reports. U.S. DOE Contract #DE-FG22-90PC90094, Pittsburgh Energy Technology Center, Pitts-
burgh, Pennsylvania.
3B-14
-------
STUDIES OF THE INITIAL STAGE
OF THE HIGH TEMPERATURE CaO-S02 REACTION
Ingemar Bjerle
Zhicheng Ye*
Fuming Xu**
Department of Chemical Engineering II
Lund University
S-221 00 Lund , SWEDEN
* Visiting researcher from Dept. of Chem. Eng., East China Institute of Technology, Nanjing 210014, P. R.
of China
" Present address: Dept. of Chem. Eng., East China Institute of Technology, Nanjing 210014, P. R. of
China
3B-15
-------
3B-16
-------
STUDIES OF THE INITIAL STAGE
OF THE HIGH TEMPERATURE CaO-S02 REACTION
ABSTRACT
The initial stage of the high temperature Ca0/S02 reaction has been investigated in a
TGA reactor, a volumetric reactor and an entrained flow reactor. The gas film resistance
and most of the pore diffusion resistance were eliminated by using very fine limestone
particles (<5^m) and measuring the sulfation at low pressure and with stoichiometricaly
premixed reactants. A two-stage reaction mechanism for the sulfation, first with a very
fast surface reaction and followed by a product layer diffusion controlled reaction, was
confirmed in the TGA apparatus. Based on an equivalent Ca/S ratio, it was found the
results from the TGA fit the SO2 removal from the entrained flow reactor well, implying
that the TGA technique is an appropriate laboratary equipment to simulate the furnace
dry injection process. The volumetric reactor shows a different initial reaction rate when
compared with both the TGA and the entrained flow reactor. This is attributed to the
slow increase (about 1 s) of the SO2 partial pressure in the volumetric reactor
compared to the TGA reactor where the SO2 increase is instantaneously. However, for
the sulfation taking place at high SO2 partial pressure in the volumetric reactor the SO2
removal is very close to that obtained in the TGA or the entrained flow reactor. The
optimum operation temperature range, the potentials of increasing the CaO utilization,
and the ideal spreading device for injecting lime powder are also discussed.
Receding page blank
3B-17
-------
STUDIES OF THE INITIAL STAGE
OF THE HIGH TEMPERATURE CaO-S02 REACTION
INTRODUCTION
The high temperature Ca0-S02 reaction is very important to the furnace dry injection
process. There are many papers in the literature addressing the reaction kinetics, the
effectiveness factors that affect the CaO reactivity, the mathematical modelling of the
reaction and the dry injection demonstrations in pilot scale or in full scale. Several
laborary approaches such as TGA technique, fixed bed, entrained bed, and differential
reactor were used to study this complicated heterogeneous reaction.
Borgwardt (1970, 1972) found in his early work conducted in a differential reactor that
between 540 °C and 1100 'C a first order chemical reaction with respect to SO2
concentration was the predominant resistance limiting the rate of sorption of SO2 by
small particles. The apparent activation energy was ranging from 8.1 to 18.1 kcal/mol.
Reaction occurs initially throughout the particle volume under the isothermal reaction
condition and the internal diffusion resistances become limiting only after conversion of
at least 20%.
For a calcined dolomite with particle size of 96 urn a CaO conversion of 21% was
observed after 2 min sulfation at 870 *C. They also reported that the rate of reaction,
which took place throughout the internal pore structure of particles smaller than 100
H.m, was directly proportional to the BET surface area. They further reported in later
studies (Borgwardt, 1986) that both initial reactivity and ultimate capacity of calcined
limestones, at conditions eliminating all resistances not associated with the CaO grain
surface, increased with the square of increasing BET surface area.
Chan (1970) conducted the S02/CaO reaction in a thermogravimetric analysis (TGA)
using the samples with 70 - 80% of the particles between 74 p.m and 149 ^.m at 745 'C
and the CaO ultimate capacity was about 80% after 1 h absorption. Gullett (1987)
3B-18
-------
proposed an inverse relation between CaO conversion and particle diameter to the
0.22 - 0.32 power based on experiments in a 1100 'C drop-tube furnace.
Hartman (1974, 1976) concluded from his experimental measurement in a differential
reactor that the optimum temperature for the reaction of raw limestone with SO2 is near
850 - 900 "C. During the first minutes of exposure the sulfation occurs almost entirely in
the outer parts of the particle, then the reaction zone gradually moves to the center of
the particle. Carbonate rocks and their calcines having large pore volume and small
grains are best suited as sorbents for removal of SO2 from flue gases. The reaction is
strongly affected by reduction of porosity caused by the sulfation reaction. The pores
with radius larger than 4000 A are probably responsible for the high capacity of
limestone to react with SO2.
Stouffer (1989) conducted a laboratary differential reactor study at temperatures of 975
- 1275 K to investigate CaO sulfation mechanisms with limestone particles ranging
from 8 to 115 urn in size. They found that both initial reaction rate and saturation
utilization were limited by the SO2 pore diffusion rate and by premature pore mouth
plugging by CaS04 product.
McClellan (1970) treated the calcitic limestone and Iceland spar with a gas containing
4 percent sulfur dioxide at 750, 1050 and 1200 °C. The degree and manner of sulfation
were examed by electro microscopy and X-ray diffraction. It was found that the sulfation
occurs in two stages: a general surface reaction of the SO2 and O2 with CaO, and a
subsequent diffusion controlled reaction when the SO2 has to diffuse through the
product layer.
As reviewed above, it has been generally accepted:
1. The diffusion of SO2 through the gas phase, the pores and the CaS04
product layer can provide resistances to sulfation depending on the
real situation.
2. Pore closure, due to the build-up of CaS04 at the pore entrance, and
the loss of active surface area caused by sintering, will slow down the
sulfation.
3B-19
-------
3. Besides temperature and SO2 level, limestone type, particle size and
the surface area also can affect the sulfation and thus the utilization of
the sorbent.
This useful knowledge of the SCte/CaO reaction has been extended to pilot scale and
full scale processes.
Milne et al (1988) reported the extensive, high-temperature, time-resolved sulfation
measurements obtained in a 30 kW isothermal dispersed-phase reactor with raw
Linwood carbonate, they found that the overall sulfation rate of particles less than 5 |xm
in mean diameter is not limited by calcination. The optimum isothermal injection
temperature was found approximately to be 1400 K.
Chughtai (1990) et al reported a desulfurization efficiency of about 65% with lime
injection alone based on the measurement conducted in a 65 MWth stoker-fired boiler
with flue gas humidification in the polishing reactor. It resulted in an overall sulfur
capture of better than 90% at high boiler load and Ca/S stoichiometry of around 2.
Nolan (1990) presented the full scale demonstration of limestone injection conducted
on a coal fired 105 MWe boiler. SO2 removal of 55-72% was achieved when a
Limestone Injection Multistage Boiler ( LIMB ) was operated at a Ca/S ratio of 2.0.
Gullett (1990) in his recent work tested the SCVCaO reactivities under a variety of
reactor flow conditions and injector throat geometries. It was concluded that both
reactor Reynolds number and throat geometry strongly affected reactivity results
through enhancing flow turbulence and reducing the intensity of sorbent/S02
segregation.
The research work conducted during the past years has revealed many details on the
limestone sulfation reaction. However, because of the complexity of the heterogeneous
reaction some results provided by different investigators are somewhat confusing and
even contrary. Clearly the knowledge of this reaction is still incomplete.
In this report, the TGA technique and a newly designed volumetric reactor were used to
investigate the initial stage of CaO/S02 reaction at high temperatures. The
3B-20
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measurements were conducted under such conditions that the gas phase resistances
and most of the pore diffusion resistances were eliminated. The results obtained from
TGA and volumetric reactors were compared with those from an entrained flow reactor.
Based on the laboratary reactor measurement, the modification of the full scale process
was discussed.
LABORATARY EXPERIMENT METHODS
Vacuum-TGA Measurement
A thermo gravimetric analysis ( TGA ) system was used to study the sulfation kinetics.
The experimental set up of it has been described elsewhere (Xu, F. and Bjerle, I. 1989).
A Pt-wired basket replaced the sample pan which was used by other researchers. The
sample in the pan acted as a single large particle and the mass transfer was restricted
by gas film diffusion. In this study the basket was evenly covered with a very thin layer
of limestone. To eliminate the gas film resistance and most of the pore diffusion
resistance, very fine particles ( < 5 |im ) were used. Reactant gas, SO2 and O2, was
premixed according to the stoichiometry. Sulfation was conducted in this reactor
around a base condition: 1000 *C and 1 mbar. This corresponds to a SO2
concentration of 670 ppm.
Volumetric Reactor Measurement
The volumetric reactor has three main parts: a mixing chamber, a diffusion chamber
and a quarz reaction chamber. With the valves in between it is possible to connect the
reactor volume with the two other chambers, and to create a thermo circulation and/or a
volumetric flow. Figure 1 shows the connection of every part in detail. A commercial
limestone, Forsby limestone, which is considered the best one of eight previously used
limestone sources (Xu, F. and Bjerle, I. 1989), was used to supply fresh CaO. The
limestone sample is prepared in the same way as in the TGA measurement.
In the volumetric reactor the sample is calcined at vacuum in the reaction chamber and
right after calcining the reactor is connected with both ends to the mixing chamber
containing the stoichiomtric reactant gas. The pressure is equalized in less than one
second and during this period the pressure around the sample increases from zero to
the equalized pressure. After that the pressure decreases continuously when the
reaction takes place.
3B-21
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A blank run was always made before or after the sample run to take into account the
effect of system leakage. A PC and a recorder were connected to the pressure sensor
for monitoring the pressure change and controlling the start and the end points of the
reaction.
Results and Disscussion
Figure 2 shows the CaO conversion vs. time results obtained from both the TGA and
the volumetric reactor at 1000 'C and 1 mbar. Under almost the same conditions the
curves from these two reactors look different. In TGA sulfation took place at an
extremely high rate at the very beginning, and then shifted to a much lower rate. The
first period lasted only about 1-2 s. This is very similar to that observed by McClellan
(1970) and can be described as a two stage reaction. First a surface reaction of SO2
and O2 with CaO that is controlled by the chemical reaction itself. Then, a subsequent
diffusion controlled reaction through the covered outer surface to the unreacted lime
core. The CaO conversion after 1 s surface sulfation for Forsby at 1000 'C and 1 mbar
was 52%, which was the highest of the previously tested samples. After 15 min 95%
CaO conversion was achieved. The intial conversion is in good agreement with the
50% conversion limit predicted by the theoretical assumption of the void volume of
particle.
Other details about the reaction kinetics of the eight tested samples, including initial
reactivity and ultimate capacity, reaction rate constant and activation energy, and the
effect of SO2 partial pressure on the different periods of sulfation, can be found in
another paper (Xu, F. and Bjerle, 1.1989).
Compared to the TGA, the volumetric reactor seems to function in a different way. It is
reasonable to say that the sulfation took place in the volumetric reactor at a high
reaction rate during the first minutes and then was followed by a slow product layer
diffusion controlled mechanism. Compared to the TGA, however, the first period was
about 2 min and could not be considered as a surface reaction. After 60 s the CaO
conversion was only 40%.
The reason for this difference between the TGA and the volumetric reactor can be that
in the TGA the SO2 partial pressure increases almost instantly from zero to the full
pressure and therefore during the initial period the sample is exposed to the final SO2-
partial pressure from the beginning. This gives a higher initial conversion in the TGA
3B-22
-------
than in the volumetric reactor where the final pressure is reached after about one
second. At the very beginning the reaction took place at low S02-partial pressure ( only
a fraction of 1 mbar) and reacted with CaO at the outer surface , in other words, at the
place around the pore entrance of the particles. The formed CaS04 narrowed the pore
mouth before the pressure reached the final level, and the further reaction was
reduced. Figure 3 shows the times needed for the pressure to reach the prefixed level
at different prefixed pressures. It is the differences in the initial pressure profile
compared to the constant pressure in the TGA that result in the different initial reaction
rate and CaO-conversion in the two reactors. On the following stage of sulfation almost
the same reaction rates were obtained in the two reactors, ( see Figure 2 b), implying
that during the second period of sulfation the reaction mechanism is the same for both
the equipments.
Figure 4 shows the CaO conversion vs. time curves of sulfation reaction at 1000 °C in
the volumetric reactor. The pressure ranged from 1 to 10 mbar. Both the initial reactivity
and the ultimate capacity were dependent on the SO2 partial pressure. The CaO
conversion increased with increasing pressure. When reactant pressure was set at 10
mbar, the CaO conversion after 2 s reaction reached 45%, which is close to that in the
TGA. The results demonstrate the importance of the SO2 partial pressure, especially
during the initial period. A high pressure during the whole of the initial period promotes
the penetration of the reactant gas deep into the pores before pore mouth blocking
takes place after about 1 s. After pore blocking has taken place the reaction rate is
dramatically reduced. In the volumetric reactor the reactant gas pressure is gradually
increased as shown in Figure 3 and less gas will penetrate into the pores before pore
blocking takes place.
The large difference between the CaO conversions in the two reactors could perhaps
be explained by assuming a shorter initial reaction period than what we earlier have
assumed by analyzing the TGA results. If it is assumed that the pore closure reaction is
zero order and independent of pressure, the duration of the initial period is the same
for the two reactors. As discussed above, the pressure in the TGA almost keeps
constant at prefixed level from the beginning while the pressure in the volumetric
reactor increases up to the full pressure, within 0.6 s. Figure 2 shows that the CaO-
conversion stays very low during the whole experiments in the volumetric reactor. This
suggests that the pore closure had taken place before 0.6 s was reached, otherwise
the conversion should start to increase sharply after 0.6 s when 1 mbar pressure was
reached. Therefore one very important conclusion is that the length of the initial period
is less than 0.6 s.
3B-23
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ENTRAINED BED MEASUREMENT
Entrained Flow Equipment
The experimental set up of entrained bed has two main parts: a fluidized sand bed
dryer and a drop tube entrained flow reactor. Figure 5 shows the schematic
arrangement of this equipment. The fluidized sand bed is used to dry and to disperse
the limestone slurry in the carrier gas at 300 *C. The drop tube reactor is electrically
heated by two units of furnaces. To ensure the Ca/S ratio to be constant during sample
collection, the entrained flow reactor and the dryer were run seperately for about 3 min
before limestone was introduced from the fluidized dryer into the entrained flow reactor.
The Ca/S ratio was determined by analysing the contents of Ca++ and S04= in the
collected particles after reaction and according to the following equation:
Ca/S = [S02-removal] • ^
L m°l SJ analyzed
Four limestones were tested in this reactor and the SO2 removal was determined at
1000 ppm SO2 concentration, 2 s residence time, 1000 'C and Ca/S ratio 0.4-1.4. The
effect of residence time on SO2 removal was investigated only with Forsby limestone.
The residence time was set to 0.4, 0.8 and 2 s, respectively. The SO2 concentration
was 680 ppm and the Ca/S ratio was varied from 0.9-2.1. In all the experiments a laser
sizer was used to determine the particle size distribution at the outlet of the fluidized
bed dryer.
Results and Discussion
Figure 6 shows the results obtained from the entrained flow reactor tests for the four
limestones at 1000 ppm SO2 concentration and 2 s residence time. It is shown that for
Malmo chalk the effectiveness for SO2 removal is somewhat low, about the same as for
Limhamn, and 20% lower than for Forsby stone at Ca/S = 1. It seems that the SO2
removal is less sensitive to Ca/S ratio for Malmo chalk than it is for Forsby stone.
Figure 7 shows the effect of residence time on SO2 removal for Forsby at 1000 'C. It is
shown that in the whole Ca/S range tested the SO2 removal increases with increasing
residence time. The results also can give some characteristics of the global kinetics of
this gas - solid reaction: the reaction is very fast and about 42% of SO2 removal was
3B-24
-------
achieved at Ca/S = 1 during the first 0.4 s; the reaction then slows down during the
later 1.6 s, but still substantially increases the SO2 removal in the order of 20%. It
shows that although the first half second is extremely important to the furnace injection
process, the 2 s residence time is still necessary to achieve a reasonable SO2 removal
level.
From the volumetric reactor experiments it was obvious that the length of the initial
period was less than 0.6 s. The experiments in the entrained flow reactor show a high
conversion even at 0.4 s. Within this time frame the calcining also takes place and the
time available for the sulfation reaction therefore is less than 0.4 s. Based on all
available information we believe that the length of the initial period is in the range from
0.1 to 0.4 s.
To compare the results obtained from the entrained flow reactor with those from the
TGA and the volumetric reactor an equivalent Ca/S ratio must be taken as a basis. For
the TGA and the volumetric reactor the amount of SO2 entering the reactor within 2 s
was taken into consideration. Table 1 lists the Ca/S ratio and SO2 removal for the TGA
and the volumetric reactor after 2 s reaction period.
Figure 8 shows the SO2 removal of three laboratary equipments as the function of
Ca/S ratio. It is very interesting that the SO2 removals in the TGA fit the curve of
entrained flow reactor well, implying that the conditions in both systems are similar.
Therefore it can be concluded that the TGA apparatus is suitable to simulate the dry
injection process in entrained flow reactor and further in a boiler, because the
entrained flow reactor has been considered an appropriate equipment to simulate the
performance in a boiler.
The SO2 removal in the volumetric reactor seems insensitive to Ca/S ratio. This
difference between the TGA and the volumetric reactor is also attributed to the different
reaction mechanism at the first period of the sulaftion. In TGA the sulfation takes place
as a surface reaction, the reaction rate is mainly dependent on the activated surface
area instead of the SO2 partial pressure, while in the volumetric reactor, as it has been
discussed above, about 1 s is needed for the reactant pressure around the sample to
go up from zero to a prefixed level. This causes a lack of reactant gas at the beginning
and the transfer of reactant deeply into pores of particles becomes the limiting step.
Therefore the sulfation is strongly affected by the SO2 partial pressure. When pressure
is increased ( Ca/S decreased ), the sulfation rate is promoted to a level at which the
3B-25
-------
S02 removal is constant independent of the Ca/S ratio. The higher the SO2 partial
pressure is, the closer the sulfation in the volumetric reactor becomes to that in the TGA
or the entrained flow reactor. This is shown in Figure 8 where the SO2 removal in the
volumetric reactor gives a rather good fit to the curve from the entrained flow reactor for
a Ca/S ratio of 0.5.
MODIFICATION OF THE FULL SCALE PROCESS
Temperature Range
The sulfation of Ca0/S02 is a reversible heterogeneous reaction. The equilibrium
constant can be expressed as:
KP = 1
0 5
Pscv(Po2)
From the equilibrium data ( Barin, I. and Knacke, O. 1973 )
log Kp = 29.03- 0.0178 T
For a flue gas containing 2% of O2, the relation between equilibrium SO2 partial
pressure and the sulfation temperature is shown in Figure 9.
Burning low sulphur coal the content of SO2 in the flue gas is about 500 - 1000 ppm or
0.5 - 1 mbar. If we want a SO2 removal of 90%, the SO2 concentration will be 50-100
ppm in the boiler outlet. Figure 9 shows the optimum temperature range for these
conditions.
In practice the effect of temperature becomes more complicated. The results reported
by different researchers are confusing, but it has been generally realized that for small
particles the sulfation reaction rate will increases with increasing temperature until
eqilibrium restriction become evident. In addition, the temperature also will affect the
calcining process, thus the pore structure and surface area of nascent CaO will be
influenced. The overall temperature effect will be a combination of these two opposing
mechanisms.
Particle Size
Many researchers have reported the importance of particle size to SO2 removal. The
smaller the particle size is, the larger the SO2 removal is. Small particles give less pore
3B-26
-------
diffusion resistance, and thus the mass transfer of SO2 through the pore structure could
be reduced to a large extent.
Up till now the limestone particle sizes used in pilot scale or full scale furnace injection
have been in the order of 5 - 100 and the SO2 removal efficiency was about 50%.
The large particle size could be the main obstacle to high limestone utilization. It can
be expected that the CaO utilization can be increased in the furnace limestone
injection process by reducing the limestone particle size down to 1 - 2 jim and in
addition eliminating any agglomoration during injection.
Particle Distribution in the Furnace
To obtain a high conversion in a practical situation the particles must be exposed to a
high SO2 partial pressure during the initial period. Normally the particles are injected
from the side walls in the furnace and passes through the SO2 containing gas at high
stoichiometry before it reaches the center of the furnace. The particles have the highest
reactivity just after having left the nozzles where the stoichiometry also is high and so
the SO2 partial pressure will be reduced and full utilization of the initial period will not
be possible.
The fresh particles have to be evenly spread across the furnace to take full advantage
of the initial period. The used spreading procedure, injection from the walls, is therefore
no ideal solution because the particles meant for the center of the furnace already have
lost their reactivity when they pass through the gas close to the walls.
CONCLUSIONS
Sulfation reactions conducted in the TGA, the volumetric reactor and the entrained flow
reactor have resulted in the following better understanding of the kinetics of the
heterogeneous reaction:
1. A two-stage reaction, first with a very fast surface reaction and
followed by product layer diffusion controlled reaction, was
confirmed in the TGA apparatus. In this equipment the SO2 partial
pressure is constant, giving a fast initial reaction rate. The length of
the initial period was estimated to be in the range of 0.1 to 0.4 s.
3B-27
-------
2. Based on an equivalent Ca/S ratio, the TGA test results matched
closely to the results from the entrained flow reactor. This implies that
the TGA technique is suitable to simulate the furnace dry injection
process.
3. The volumetric reactor shows a different initial reaction rate when
compared with both the TGA and the entrained flow reactor. This is
attributed to slow increase in pressure during the initial period.
However, for the sulfation taking place at high SO2 partial pressure,
e.g. 10 mbar, in the volumetric reactor the SO2 removal is very close to
that in the TGA or in the entrained flow reactor.
4. From the viewpoint of reaction equilibrium, the optimum operation
temperature ranges are related to the content of SO2 in flue gas and
expected SO2 removal. For a flue gas containing 2% SO2 and 500 -
1000 ppm SO2 the appropriate temperature is in the range of 1050 -
1100 *C.
5. The potential of increasing the CaO utilization is possible by using
limestone particles about 1 - 2 p.m and avoiding any agglomoration
during injection.
6. An ideal spreading device for injecting lime powder must be designed
and placed so that the fresh particles are spread evenly across the
furnace to take full advantage of the fast initial sulfation period.
ACKNOWLEDGMENTS
This work has been supported by the Swedish Energy Administration ( STEV ) to which
the authors are grateful. The authors also appriciate the continuous help from Mr.
Mikael Carlsson and Mr. Samuel Kiuru.
REFERENCES
1. Barin, I. and Knacke, O. Thermochemical Properties on
Inorganic Substances , Springer Verlag, Berlin, Heidelberg,
New York, 1973
2. Borgwardt, R. H.," Kinetics of the Reaction of SO2 with
Calcined Limestones ", Environ. Sci. & Technol.. 4, 59 (1970)
3B-28
-------
3. Borgwardt, R. H., and Harvey, R. D., " Properties of Carbonate
Rocks Related to SO2 Reactivity Environ. Sci. & Technol.. 6,
350 (1972)
4. Chan, R. K., Murthi, K. S., and Harrison, D., "
Thermogravimetric Analysis of Ontario Limestones and
Dolomites. I: Calcination, Surface Area, and Porosity ", Can.
J- Chem.. 48, 2972 (1970)
5. Chughtai, M. Y., Linneweber, K. W., Schmid, C., " Direct
Desulfurization in Combination with Polishing Reactor ", In
Proceedings of1990 SO^ Control Symposium. May 8-11,
1990 , New Orleans
6. Gullett , B. K., Groff, W., Bruce, K. R., " The Effect of rapid
Mixing and Turbulence on the Sorbent /SO2 Reaction In
Proceedings of 1990 SOz Control Symposium. May 8-11,
1990 , New Orleans
7. Hartman, M., and Coughlin, R. W., " Reaction of Sulfur
Dioxide with Limestone and the Influence of Pore Structure
Ind. Eng. Chem. Process Pes. Dev.. 13, 248 (1974)
8. Hartman, M., and Coughlin, R. W., " Reaction of Sulfur
Dioxide with Limestone and the Grain Model ", AlChE J.. 22,
490 (1976)
9. McClellan, G. H., Hunter, S. R., and Scheib, R. M., " x-ray and
Electron Microscope Studies of Calcined and Sulfated
Limestones ", The Reaction Parameters of Lime, ASTM
Special Tech. Pub. 472. 32 (1970)
10. Milne, C. R., and Pershing, D. W., " An Experimental and
Thepretical Study of the Fundamentals of the SO2 / Lime
Reaction at High Temperatures In Proceedings of First
Combined FGD and Drv SO^ Control Symposium. Oct. 1988, St.
Louis, Missouri
11. Nolan, S., Hendriks.V., et al, " Results of the EPA Lime
Demonstration at Edgewater In Proceedings of1990 SO^
Control Symposium. May 8 - 11, 1990 , New Orleans
12. Stouffer, M. R., Yoon, H., " An Investigation of CaO Sulfation
Mechanism in Boiler Sorbent Injection ", AlChE J.. 35, 1253
(1989)
3B-29
-------
13. Xu, F., Bjerle, I., Karlsson, A., Kiuru, S., " Dry Injection -
Experimental Studies Using TGA Technique In
Proceedings of ACHEMASIA89 - International Meeting on
Chemical Engineering and Biotechnology - 1st Exhibition
Congress. Oct. 1989, Beijing
3B-30
-------
-2
i
i i
i i
guage 1 Q Q
w guage2Y
... ! I
gas inlet
*
S\
mixing chamber
volume: 4 I
to vent
*
V2
V3
1 pump capacity: < 5x10 mbar
"I l
i—I
z
recorder
-L-
V4 • 1
—*1
furnace 8851
1-*—
•A
V5
rotary pump 1
\
quartz reactor
with 5 mg CaCOg
Amstrad Computer
diffusion chamber
volume: 3 I
to vent
rotary pump 2
Fig.1 A schematic diagram of the experimental set up of the
volumetric reactor used for sulfation test with limestone Forsby
100
c
o
£2
a>
>
c
V.R. 1 mbar
TGA, 1 mbar
o
O
O
(0
O
0*
0
800 1000
200 400 600
time (s)
Fig.2 a A Comparsion of CaO Conversion:1000 C,1 mbar,
S02/02=2, in TGA and the Volumetric Reactor (V. R.)
3B-31
-------
100
3s-
80
c
o
60
,w
CD
>
c
40
o
O
O
20
(0
O
0
V.R. 1 mbar
TGA, 1 mbar
40 50 60
time (s)
Fig.2 b A Comparsion of CaO Conversion:1000 C,1 mbar,
S02/02=2, in TGA and the Volumetric Reactor (V. R.)
V.R. 10 mbar
«— V.R. 8 mbar
V.R. 4 mbar
~— V.R. 2 mbar
• • * ¦ ¦ ¦ ¦ * ¦ ¦ ¦ * 1 • ¦ • • i i i i i
200 400 600 800 1000
time (ms)
Fig.3 Pressure Change in the Volumetric Reactor versus time
120
pi 100
c
o
'y>
a>
>
c
o
O
O
(0
O
IB—
V.R. 1 mbar
•
V.R. 2 mbar
¦
V.R. 4 mbar
•
V.R. 8 mbar
V.R. 10 mbar
40 50 60
time (s)
Fig.4 a CaO Conversion versus Time at different
Pressures 1000 C, S02/02=2, in the Volumetric Reactor
3B-32
-------
o 40
—a—
V.R. 1 mbar
•—
V.R. 2 mbar
¦—
V.R. 4 mbar
o—
V.R. 8 mbar
¦—
V.R. 10 mbar
800 1000
time (s)
Fig.4 b CaO Conversion versus Time at different
Pressures 1000 C, S02/02=2, in the Volumetric Reactor
to vent
SO_/N
limestone and air
furnace
recorder contrail 1
entrained flow reactor
fluidized bed dryer
_ furnace
S02 analyzer 2
IS
temperature
controller
to vent
to vent
Q*
fan
quartz wool
tr water
air
rotamete
¦ ^ slurry
O stirrer
metering ro
pump
Fig.5 A schematic diagram of the experimental setup for the entrained flow reactor
3B-33
-------
¦
Malmo Chalk
+
Ingerberga
•
Limhamn
•
Forsby
U,0 0,2 0,4 0,6 0,8 1,0 1,2 1,4 1,6 1,8 2,0
Ca/S
Fig.6 S02 Removal versus Stoichiometry for Malmo Chalk
and Other Limestones in the Entrained Flow Reactor
+ 2s
• 0.8 s
° 0.4 s
— 2 s curve fit
0.8 s curve fit
— 0.4 s curve fit
i ¦ i ¦ i i i i i
0,00,20,40,6 0,8 1,01,21,41,6 1,8 2,02,2 2,4
Ca/S
Fig.7 Effects of Residence Time on the S02 Removal
in the Entrained Flow Reactor with Limestone Forsby
3B-34
-------
100
80
B Entrained Bed
+ TGA
° Volumetric Reactor
— Curve Fit for E.B.
60
40
C\J
20
0
0
Ca/S
Fig.8 S02 Removals as a Function of Ca/S Ratio for Three
Tested Reactors
12
Log (Kp)
Outlet = 0.05 mbar
Outlet = 0.1 mbar
10
8
6
4
2 l-J
1000
1100
1200
1300
1400
1500
T (K)
Fig. 9 Determination of optimum sulfation temperatures
3B-35
-------
Table 1
THE S02 REMOVAL AS A FUNCTION OF CA/S RATIO
IN THE TGA AND IN THE VOLUMETRIC REACTOR
CONTENTS SO2 entering reactor in 2 s limestone used CaO conversion SO2 removal Ca/S
mol mol % %
OJ
00
1
OJ
OS
TGA:
1 mbar
2 mbar
3 mbar
4 mbar
Volumetric reactor:
1 mbar
2 mbar
4 mbar
8 mbar
10 mbar
5.5e-5
1.5e-4
2.6e-4
4.6e-4
1 .Oe-5
2.0e-5
4.0e-5
8.0e-5
1 .Oe-4
5.0e-5
5.0e-5
5.0e-5
5.0e-5
5.3e-5
5.2e-5
5.4e-5
5.0e-5
5.9e-5
52.0
56.2
57.5
60.3
4.0
9.0
20.0
35.0
45.0
47.7
19.4
11.1
6.6
21.2
23.4
27.0
23.2
26.5
0.92
0.34
0.19
0.11
5.0
2.5
1.25
0.63
0.50
Reaction condition : 1000 *C, SO2/O2 = 2
-------
Status of the Tangentially Fired LIMB Demonstration
Program at Yorktown Unit No. 2: An Update
3E-37
-------
Intentionally Blank Page
3B-38
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STATUS OF THE TANGENTIALLY FIRED LIMB
DEMONSTRATION PROGRAM AT YORKTOWN UNIT NO. 2: AN UPDATE
J. P. Clark
M. R. Gogineni
R. W. Koucky
ABB Combustion Engineering Systems
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
E. Gootzait
Virginia Power Company
Yorktown Power Station
Yorktown, Virginia 23690
D. G. Lachapelle
U.S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
ABSTRACT
Combustion Engineering, Inc., under EPA sponsorship, is conducting a program
to demonstrate furnace sorbent injection on a tangentially fired, coal-burning
utility boiler, Virginia Power's 180 MW(e) Yorktown Unit No. 2. The overall
objective of the program is to demonstrate significant reductions in sulfur
dioxide (S02) and nitrogen oxides (N0J while minimizing any negative impacts
on boiler performance.
Engineering and procurement activities and baseline testing have been
completed. Construction and installation of the sorbent injection and low-N0x
equipment is nearly complete. An 8-month demonstration of furnace sorbent
injection plus flue gas humidification will be conducted in 1992.
Details of the sorbent injection concept to be tested at Yorktown, results of
baseline testing, overall demonstration program organization and schedule, and
preliminary plans for the 8-month demonstration test are discussed in the
paper.
***
This paper has been reviewed in accordance with the U.S. Environmental
Protection Agency's peer and administrative review policies and approved for
presentation and publication.
Preceding page blank
3B-39
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STATUS OF THE TANGENTIALLY FIRED LIMB
DEMONSTRATION PROGRAM AT YORKTOWN UNIT NO. 2: AN UPDATE
INTRODUCTION
Furnace sorbent injection has been established as an alternate approach for
achieving moderate levels of S02 reduction on coal-burning utility boilers.
The process is attractive for retrofit of existing boilers since the capital
equipment requirements and overall sulfur reduction costs per ton of sulfur
removed are less than for other options such as flue gas desulfurization. In
the furnace sorbent injection process, sorbent, usually calcium hydroxide
[Ca(OH)2] or limestone (CaC03), is injected above the flame zone and mixes
with the combustion products containing S02. The S02 reacts chemically with
lime (CaO), formed from the sorbent, to make solid calcium sulfate (CaSOJ.
The CaS04 is removed with flyash in particulate collection equipment.
The potential market for furnace sorbent injection includes all pre-1971 coal-
burning utility boilers, primarily those burning eastern and midwestern
bituminous coals. Over 40% of coal-burning utility boilers are tangentially
fired. In the 1950s and 1960s, 161 tangentially fired units designed to burn
eastern or midwestern bituminous coals were sold, totalling nearly 47,000 MW.
Tangential firing introduces special considerations for the design of sorbent
injection systems due to the unique aerodynamics in the sorbent mixing region
of tangentially fired furnaces. The U.S. Environmental Protection Agency
(EPA) recognized this fact when it awarded Combustion Engineering, Inc. (C-E)
a contract for Demonstration of Sorbent Injection Technology on a Tangentially
Coal-Fired Utility Boiler (EPA Contract 68-02-4275) on June 12, 1987, as a
complement to the wall-fired sorbent injection demonstration program conducted
at Ohio Edison's Edgewater Station. This paper discusses the status of the
tangentially fired sorbent injection program, focusing on equipment design
details, baseline test results, and plans for the demonstration test.
DISCUSSION
C-E and the EPA are conducting a program to demonstrate furnace sorbent
injection on a tangentially fired, coal-burning utility boiler. The overall
objective of the program is to demonstrate significant reductions in S0Z
(approximately 50%) and N0X while minimizing any negative impacts on boiler
performance during long-term operation of an integrated sorbent injection
system and a low-N0x firing system. The program will address technical
sorbent injection-related problem areas, such as sorbent handling and
injection, precipitator performance, ash handling and disposal, and the
possibility of convective pass fouling over a period of operation sufficient
to establish cost-effective resolutions.
3B-40
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The project team consists of C-E (program management, process equipment
design/installation/operation), Virginia Power (host utility), Stone & Webster
and ABB Lummus Crest Inc. (balance-of-plant engineering), and Radian
Corporation (emission testing). The project team members are co-funding the
project with the EPA. The U.S. Department of Energy has also contributed
funding to this program.
HOST UNIT DESCRIPTION
The demonstration program will be conducted at Virginia Power's Yorktown Unit
No. 2. An aerial view of the Yorktown Power Station, located in Yorktown,
Virginia, is shown in Figure 1. Unit No. 2 is to the right of the smaller
stack.
Yorktown Unit No. 2 is a tangentially fired, Controlled Circulation® reheat
boiler with a current rating of 180 MW(e). A side elevation of Unit No. 2 in
in its pre-modification configuration is shown in Figure 2. Pertinent data
describing Unit No. 2 are presented in Table 1. Unit No. 2 features a divided
furnace with a water-cooled centerwall, with four levels of tilting tangential
burners on each side of the dividing wall.
Yorktown Unit No. 2 is equipped with two Ljungstrom® regenerative air heaters.
Flue gas from these air heaters enters the electrostatic precipitator (ESP)
via separate inlet ducts. The ESP, with a specific collection area (SCA,
square feet of collecting area per thousand actual cubic feet per minute of
gas treated) of 720*, was installed in 1985. When combined with
humidification of the flue gas for particulate control, this large capacity
should permit operational flexibility during the demonstration test. Material
collected in the ESP hoppers is pneumatically transported to an ash silo, from
which it is trucked to a Virginia Power-owned landfill disposal site 2 miles
away.
PROGRAM DESCRIPTION
The EPA demonstration program is divided into six tasks;
Task 1 Program Management
Task 2 Development of Preliminary LIMB (Limestone Injection
Multistage Burner) Concept
Task 3 Determination of Baseline Conditions
Task 4 Conduct of Demonstration Program
Task 5 Preparation of Recommendations and Guidelines for LIMB
Commercialization
Task 6 Site Restoration
The current program schedule is:
Contract signing
Complete preliminary design
Complete detail design
Baseline testing
Construction/Installation
LIMB start-up
Demonstration testing
Complete site restoration
June 1987
April 1989
June 1990
February - March 1991
May - December 1991
April 1992
July 1992 - February 1993
December 1993
(*) Readers more familiar with the metric system may use the unit conversions
at the end of the paper.
3B-41
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LIMB CONCEPT FOR YORKTOWN
The LIMB concept for Yorktown was finalized in June 1990. Subsequent efforts
have been directed toward material specifications and detailing, vendor
selection, equipment procurement, and construction/installation.
A detailed discussion of the Yorktown LIMB system was presented previously
(1). A brief overview of the system is presented below.
The overall system layout is shown in Figure 3, a site plan of the Yorktown
Station. The 390-ton long-term storage bin (A in Figure 3) will be filled
either from rail cars, delivered to a dedicated rail spur (B in Figure 3), by
means of fixed pneumatic unloading equipment, or from trucks. The sorbent
will be pneumatically transported, on demand, at the rate of approximately 17
tons/hr, to twin 65-ton day bins (C in Figure 3) located east of the Unit No.
2 ESP. From the day bins, the sorbent will be pneumatically transported (5.5
tons/hr/bin, nominal) to sorbent injectors at one of three elevations on the
boiler. Additional air to maximize sorbent mixing and penetration will be
supplied to the sorbent injectors from the injection air fan (F in Figure 3).
To maintain ESP performance, the flue gas will be humidified in the ESP inlet
ducts (D, E in Figure 3).
CONSTRUCTION
Permitting
The final permit to install and operate the LIMB system at Yorktown was
obtained from the Virginia Department of Air Pollution Control on May 29,
1991, completing a process which had begun in early 1989. Construction of the
LIMB system began immediately upon receipt of the permit.
Install ation/Construction
The first project-related construction actively occurred in late 1990 when a
new LIMB control room was erected near the existing Unit No. 2 control room to
house the LIMB data acquisition system. This construction and installation of
the data acquisition system was completed prior to the February - March 1991
baseline test.
Unit No. 2 was taken off-line in April 1991 to begin a 7-month outage during
which a new turbine-generator set was installed. Preliminary LIMB site
preparation activities were initiated at this time, pending receipt of the
final construction permit.
Installation of all items requiring the boiler to be off-line was completed
prior to the unit's returning to service in November 1991. The new low-NO,
firing system, with overfire air, was installed and integrated into the
existing Unit No. 2 firing system controls. The existing sootblower system
was expanded to incorporate the 10 new sootblowers which were added in the
economizer, air heater, and low temperature reheat areas. Penetrations for
the humidification lances, plus access and observation doors and thermocouples
to monitor the humidification system performance, were installed in the ESP
inlet ducts. Boiler tube modifications, and other equipment required to
accommodate the 50 sorbent injectors, were installed in the boiler.
3B-42
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Figure 4 shows the three elevations of sorbent injection which will be
demonstrated at Yorktown. These injection locations are shown isometrically
in Figure 5. The lower level (Level D) will be used for low-load operation.
) The primary full-load injection plane will be Level E, with the upper level,
Level A, providing an alternative for full-load injection under certain
operating conditions where temperatures lower in the furnace exceed the
optimum S02 capture levels.
Several sorbent injector assemblies are shown in Figure 6. A Level A assembly
is to the right of the picture. The other assemblies are for Level D. Figure
7 shows one of the Level D injectors installed in the boiler. The smaller 2%
in. inlet connector is for sorbent and transport air. The large 6 in. inlet
connector is for injection air which mixes with the sorbent stream inside the
injector body to provide a fully mixed discharge stream with sufficient
momentum to penetrate and mix with the furnace gas stream.
An LNCFS (Low N0X Concentric Firing System) Level II system has been installed
in Unit No. 2. This is the first installation of this system in an eight-
corner (divided) unit. The system features separated overfire air located
above the secondary air duct. The separated overfire air nozzles have both
vertical (tilt) and horizontal (yaw) adjustment for combustion optimization.
Additionally, the LNCFS Level II system features horizontally offset
(secondary) air nozzles and early fuel ignition (flame attachment) coal
nozzles. An isometric cross-section of a representative LNCFS Level II system
is shown in Figure 8.
All other LIMB equipment has been set in place. Enclosures will be erected to
house this equipment. Access platforms in the boiler area have been added or
relocated. Balance-of-plant electrical installation - the final major
construction activity - is scheduled to be completed by the end of 1991.
BASELINE TESTING
Accurate definition of boiler performance without sorbent injection is
critical in determining the effectiveness of the LIMB process in controlling
S02, as well as in establishing the normal operating characteristics at
Yorktown Unit No. 2 including gaseous emissions, ESP performance, firing
system performance, fouling and slagging characteristics, sootblowing
requirements, and furnace temperatures. To satisfy these requirements, a
baseline test was conducted on Unit No. 2 in the as-is or pre-modification
configuration. The test was conducted from mid-February to mid-March 1991.
This complied with the EPA requirement of continuous operation for a period of
30 days over the normal boiler duty cycle. The test was conducted on the
demonstration coal, a Pittsburgh No. 8 eastern bituminous coal supplied by
Consolidation Coal Co. (Consol) from its Blacksville and Loveridge mines. The
mean sulfur content of the coal during the baseline test was 2.35%. A
representative analysis of the demonstration coal is presented in Table 2.
The first week of baseline testing characterized the performance of the boiler
under different loads, degrees of furnace cleanliness, and burner tilts.
Furnace outlet temperatures were measured at the nose using water-cooled
suction pyrometer probes. Figure 9 presents the temperature profile through
the boiler for one full-load test condition. The furnace outlet temperature
shown in Figure 9 (2300°F) is approximately the same as that measured during
boiler characterization testing conducted under comparable conditions in
November 1987 (2). The gas quench (cooling) rate through the critical S02
capture window (2300° to 1650°F) for the data shown in Figure 9 was 613°F/sec,
providing roughly 1 sec of residence time for the calcined sorbent in the
reaction zone.
3B-43
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The second week of baseline testing characterized the performance of the ESP.
The ESP was operated in different configurations, by removing fields from
service, to provide performance representative of ESPs with a wide range of
SCAs. Total particulate, particle size distribution, and in situ resitivity
measurements were made throughout the ESP test program. ESP performance data,
including collection efficiency (from total particulate), particle mass mean
diameter (from particle size distribution), and resistivity, are summarized in
Table 3.
Burner testing was conducted during the third week of the baseline test.
Burner tilt, excess air, load, and coal fineness were varied to characterize
the performance of the existing tangential firing system prior to its
replacement with the concentric firing system plus separated overfire air.
Throughout the baseline test, gaseous emissions (S02, N0X, CO, C02, 02, total
hydrocarbons) from both of the ESP outlet ducts were monitored continuously.
Average daily S02 emissions varied from 3.103 to 3.881 lb/106 Btu (avg. 3.501
lb/10 Btu) during the course of the test. Average daily N0X emissions varied
from 0.433 to 0.544 lb/106 Btu (avg. 0.472 lb/10 Btu) during the course of
the test, although individual tests produced NO, emissions of up to 0.618
lb/106 Btu. These levels are substantially below the 0.7 lb/10 Btu level
which was measured in November 1987 (2). This earlier data may be in error,
since it represents a single test condition with much less rigorous data
quality requirements.
The baseline test matrix will be repeated as part of the LIMB demonstration
test matrix to establish the impact of sorbent injection on boiler and ESP
performance.
DEMONSTRATION PROGRAM
Sorbent Selection
At this writing, negotiations are underway to secure a continuous supply of
hydrated lime to the Yorktown site. Both rail and truck delivery options are
under consideration. It is anticipated that the sorbent will be treated with
calcium 1ignosulfonate, although untreated sorbent may be used also. The
treated sorbent has been shown to have both superior handling characteristics
and the potential for enhanced S02 capture, when compared to untreated sorbent
(3).
Demonstration Schedule
A low-N0x firing system optimization test on both the current Yorktown coal
and the Consol demonstration coal will be conducted in March 1992. Start-up of
the LIMB equipment is scheduled for April 1992. Shakedown and optimization
testing is scheduled to extend through June 1992, at which point the 8-month
demonstration test will begin. All LIMB testing will be conducted on the
Consol eastern bituminous coal which was burned during the baseline test. The
demonstration test will include four 30-day test periods during which
extensive emissions (gaseous, particulate) and boiler (and ESP) performance
data will be acquired. Data obtained during these test periods, when compared
with similar data obtained during the 30-day baseline test, may be used by the
EPA to define S02 and N0„ control requirements for tangentially fired coal-
burning utility boilers operating with sorbent injection.
3B-44
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SUMMARY
The two-phase Clean Air Act provides for significant reductions in acid rain
precursors for most older coal-burning boilers. Utilities and industry are
investigating sorbent injection as a cost-effective alternative to
conventional desulfurization systems for achieving moderate levels of S02
removal. This paper has presented the results of baseline testing and
summarized the status of construction of the sorbent injection and low-NO,
firing systems at Virginia Power's Yorktown Unit No. 2. Successful completion
of the EPA-sponsored Yorktown demonstration program is expected to firmly
establish the viability of this process as an alternative to scrubbers for S02
control. The program is also expected to verify the significant reductions in
NO, with overfire air when combined with the low-NO, firing system.
ACKNOWLEDGEMENTS
The authors wish to acknowledge the significant contribution made by J. L.
Horton of Virginia Power's Fuels Procurement Group in identifying, and
securing delivery of, the demonstration coal and sorbent.
REFERENCES
1. J. P. Clark, M. R. Gogineni, R. W. Koucky, E. Gootzait, D. G.
Lachapelle, "Status of the Tangentially Fired LIMB Demonstration Program
at Yorktown Unit No. 2," In Proceedings: 1990 S02 Control Symposium,
Volume 1, EPA-600/9-91-015a (NTIS PB 91-197210), May 1991.
2. M. R. Gogineni, J. P. Clark, J. L. Marion, R. W. Koucky, D. K. Anderson,
A. F. Kwasnik, E. Gootzait, D. G. Lachapelle, S. L. Rakes, "Development
and Demonstration of Sorbent Injection for S02 Control on Tangentially
Coal-Fired Boilers," In Proceedings: First Combined FGD and Dry S02
Control Symposium, Volume 1, EPA-600/9-89-036a (NTIS PB 89-172159),
March 1989.
3. P. S. Nolan, et al., "Results of the EPA LIMB Demonstration at
Edgewater," In Proceedings: 1990 S02 Control Symposium, Volume 1, EPA-
600/9-91-015a (NTIS PB 91-197210), May 1991.
UNIT CONVERSION TABLE
To Convert From To Multiply Bv
degrees Fahrenheit degrees Celsius (T-32)/l.8
cubic feet/minute cubic meters/second 4.719xl0"4
feet meters 0.3048
inches centimeters 2.540
miles kilometers 1.6093
tons kilograms 9.072 x 10
pounds/106 British
thermal units nanograms/joule 433
pounds/hour kilograms/second 1.26 x 10'"
pounds/square inch kilopascals 6.895
British thermal units/pound kilojoules/kilogram 2.324
2
3B-45
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Table 1
VIRGINIA POWER'S YORKTOWN UNIT NO. 2
UNIT DESCRIPTION
Type:
Rating:
Date in Service:
Steam Conditions:
Main Steam Flow:
Tangentially fired, Controlled
Circulation®, reheat, divided
180 MW maximum capacity;
150 MW rated
January 1959
2000 psi/1000°F/1000°F
1,200,000 Ib/hr
Reheat Steam Flow: 1,060,000 Ib/hr
Table 2
TYPICAL DEMONSTRATION COAL ANALYSIS
(as received)
Proximate:
Moisture
%
4.74
Volatile Matter
%
37.48
Fixed Carbon
%
50.23
Ash
%
7.55
Higher Heating Value
Btu/lb
13,381
Ultimate:
Moisture
%
4.74
Carbon
%
73.77
Hydrogen
%
4.85
Nitrogen
%
1.44
Sulfur
%
2.35
Oxygen
%
5.30
Ash
%
7.55
3B-46
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Table 3
BASELINE ESP TEST RESULTS
Test
Gas Volume
(actual cubic ft/min)
Effective
SCA
Collection
Efficiency (%)
Resistivity
(ohm - cm)
Particle Mass Mean
Diameter (^m)
Inlet/Outlet
1
757,300
569.6
99.88
5.3/2.9
2
721,400
434.8
99.69
3
779,400
402.5
99.59
2.3 x 1010
4
759,200
309.9
99.36
4.6 x 1010
5.6/3.4
Figure 1. Virginia Power's Yorktown Power Station
3B-47
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mii!iii!!in.ii.i'iwnf
i 1 1 i i i i
10 0 10 20 30 40 50 (feet)
Figure 2. Side Elevation of Virginia Power's Yorktown Unit No. 2
3B-48
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UNIT 2
BOILER
(A) LONG TERM STORAGE BIN
® RAIL CAR UNLOADING AREA
© DAY BINS
© HUMIDIFICATION COMPRESSORS
© HUMIDIFICATION ENCLOSURE
© INJECTION AIR FAN
Figure 3. Yorktown Site Plan Showing Location of Sorbent Injection and Humidification Equipment
3B-49
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LEVELA
EL. 110'-6"
EL. 107'-6'
EL. 103'-8 3/8'
EL. 103'-4 5/16'
EL. 101'-10"
45° LEVEL E
EL. 101 '-7 1/8'
EL. 99'-5 7/8'
[ * EL. 94'-8 3/4'
Klrh
¦*. -0—EL.92,-71/2'
45° LEVEL D
24'-1 1/2'
Figure 4. Sorbent Injection Nozzle Locations - Partial Side Elevation
3B-50
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Right Side
Wall Tubes
Front Wall
Tubes
W
LEVEL E
LEVEL D ^ ^
\
LEVEL A
LEVEL E
LEVEL D
Rear Wall
Tubes
Center Wall
Tubes
Left Side
Wall Tubes
Figure 5. Sorbent Injection Nozzle Locations - Isometric
-------
Figure 6. Sorbent Injector Assemblies
Figure 7. Sorbent Injector Assembly Installed in the Boiler (Level D)
3B-52
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Separated
Overfire Air
Nozzles
CFS
Nozzles
Coal
Nozzles
Oil Gun
Figure 8. Typical LNCFS Level II System - Isometric
3B-53
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Upper
Furnace
Platens HTSH IHTRH
Cavity
LTSH
Econ
3000
• Back Calculated
+ Measured
2500
u.
2000
•- 1500
O)
1000
500
0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Time, seconds
Figure 9. Baseline Test Gas Temperature Profile
3B-54
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RESULTS FROM LIMB EXTENSION TESTING
AT THE OHIO EDISON EDGEWATER STATION
Thomas R. Goots
Michael J. DePero
Thomas J. Purdon
Paul S. Nolan
The Babcock & Wilcox Company
20 South Van Buren Avenue
Barberton, OH 44203
Joseph L. Hoffmann
Ohio Edison Company
76 South Main Street
Akron, OH 44308
Thomas W. Arrigoni
U.S. Department of Energy
Pittsburgh Energy Technology Center
Pittsburgh, PA 15236
3B-55
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Intentionally Blank Page
3B-56
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RESULTS FROM LIMB EXTENSION TESTING
AT THE OHIO EDISON EDGEWATER STATION
ABSTRACT
This paper presents results from the Limestone Injection Multistage Burner (LIMB) extension
testing. LIMB is a furnace sorbent injection technology for the reduction of sulfur dioxide
(S02) and nitrogen oxides (NOx). In 1987, Babcock & Wilcox (B&W) and the Ohio Edison
Company, under the sponsorship of the U. S. Department of Energy (DOE) through its Clear
Coal Technology Program and the State of Ohio Coal Development Office, agreed to extend
the full-scale demonstration of the LIMB flue gas desulfurization (FGD) process. The project
also provided for demonstration of the Coolside process, a duct sorbent injection technology
between July 1989 and February 1990. The LIMB process demonstration began in 1984
under the sponsorship of the U. S. Environmental Protection Agency (EPA). The testing was
conducted on the 105 MW, coal-fired Unit 4 boiler at Ohio Edison's Edgewater Station in
Lorain, Ohio.
The primary purpose of the DOE extension testing, which began in April 1990, was to
demonstrate the generic applicability of LIMB technology. The program sought to
characterize the S02 emissions that result when various calcium-based sorbents are injected
into the furnace, while burning coals with a range of sulfur content from 1.6 to 3.8 percent.
The four sorbents used included calcific limestone, dolomitic hydrated lime, calcitic hydrated
lime, and calcitic hydrated lime with a small amount of added calcium lignosulfonate. The
initial EPA program focused on tests with the calcitic hydrated lime while burning a 3.0
percent sulfur Ohio coal. Tests with the lignosulfonate-doped material were added after pilot
tests appeared to show enhanced reactivity.
The results presented for the various coal/sorbent combinations include further
characterization of the S02 removal to be expected with and without humidification to a close
approach to saturation, the effects of limestone particle size distribution, and the effects of
injection at different elevations in the furnace.
NOx emissions are also presented since the boiler operated with low-NOx burners throughou
all the tests. The burners were installed as part of the original LIMB demonstration.
Preceding page blank
3B-57
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RESULTS FROM LIMB EXTENSION TESTING
AT THE OHIO EDISON EDGEWATER STATION
INTRODUCTION
The Clean Air Act Amendments of 1990 have established new requirements for sulfur dioxide
(S02) emissions from utilities. The legislation provides for phased compliance and gives
utilities the ability to choose the technology needed to meet emission limits. As a result, it is
anticipated that fuel switching and wet flue gas desulfurization systems (FGD scrubbers) will
be chosen for many of the larger units faced with meeting a 2.5 lb SO2/106 Btu limit for the
Phase I target date of January 1, 1995. After that, however, other technologies are expected
to be regarded as viable, given a wide variety of site-specific considerations.
In anticipation of such legislation, the EPA promoted a series of bench- and pilot-scale
projects during the early 1980s. These studies were directed toward development of
relatively low cost, moderate efficiency, S02 and NOx emission control technologies for older
fossil-fired utility boilers. At about the same time, the Ohio Edison Company undertook a
program to participate in emerging technology development to be in a better position to
evaluate the technical, operational, and economic aspects of such technologies. By 1984,
the two programs led to the full-scale demonstration of the Limestone Injection Multistage
Burner (LIMB) process. EPA sponsored the project with co-funding by the State of Ohio
Coal Development Office (OCDO) and Babcock & Wilcox (B&W), the prime contractor.
Concurrently with the early LIMB tests, the U. S. Department of Energy (DOE) initiated the
Clean Coal Technology (CCT) Program to promote advanced coal-based technologies,
offering options to address many energy issues, including acid rain and environmental
quality. This program seeks to demonstrate the commercial feasibility of technologies that
have already reached the proof-of-concept stage. Divided into five rounds of solicitations
(CCT -1 through IV are currently active, with the announcement of CCT - V planned in mid-
1992), the program provided an opportunity to build upon the base EPA LIMB program. Thii
occurred when the potential for increased S02 capture through humidification of the flue gas
was realized. Consolidation Coal Company's (Consol) work with the Coolside in-duct flue
gas desulfurization process and B&W's (spray) dry scrubbing technology development, both
of which effectively relied on controlled humidification to a close approach to the adiabatic
saturation temperature of the flue gas, suggested the desirability of further development of
the LIMB and Coolside processes. The success of the early LIMB tests with respect to S02
removal and the potential of overcoming the deleterious effects of LIMB ash on electrostatic
precipitator (ESP) performance, were thought to be further benefits to be derived from
combining and extending the technology demonstrations.
Formalized in 1987 as part of CCT-I, under a cooperative agreement between the DOE
Pittsburgh Energy Technology Center (PETC) and B&W, the project is effectively the result ol
a cooperative effort among the government sponsors and participants to demonstrate the
broader applicability of sorbent injection technology over a wide range of conditions. Major
3B-58
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co-funding is provided by OCDO, Consol, and B&W.
The EPA-sponsored demonstration, completed in June 1989, used calcitic hydrated lime,
both with and without calcium lignosulfonate added to enhance S02 capture, while burning
3.0 percent sulfur coal.Q) Full-scale testing of the Coolside duct injection process under the
CCT Program began in July 1989 and ran through February 1990.(2) Following
rearrangement of the injection equipment from the duct back to the furnace, the LIMB
extension tests began in April 1990 and continued until August 1991. The remainder of this
paper presents the results obtained during this period, together with a description of the
operating experience under various conditions.
TEST CONDITIONS AND SCHEDULE
The LIMB extension project was designed to determine the S02 removal efficiency for four
sorbents: calcitic limestone (CaC03), "type-N" atmospherically hydrated dolomitic lime
[Ca(OH)2»MgO], and calcitic hydrated lime [Ca(OH)2] alone and with added calcium
lignosulfonate (hereafter called ligno lime). These tests were conducted over a range of
calcium/sulfur molar ratios (Ca/S) and humidification conditions while burning Ohio coals
with nominal sulfur contents of 1.6, 3.0, and 3.8 percent by weight. Close approach testing,
as it is used in this report, is defined as a 20F approach to the adiabatic saturation
temperature of the flue gas, measured at the humidifier outlet. For the coals used, the
saturation temperature was approximately 125F. Minimal humidification of the flue gas, or
testing without close approach, is defined as operation at a humidifier outlet temperature
sufficient to maintain ESP performance, typically 250 to 275F. The coal/sorbent
combinations of 3.0 percent sulfur with calcitic hydrated lime and ligno lime, tested during th
EPA-sponsored program, were not repeated here. However, the 3.0 percent sulfur
coal/ligno lime combination was used to verify equivalent system operation, following
conversion of equipment back to a furnace injection configuration after the Coolside duct
injection tests were complete. A LIMB system process flow diagram is shown in Figure 1.
An overview of the various facets of the LIMB test program is presented in a chronological
summary in Table 1. As can be seen, tests were also performed with two more finely groun
calcitic limestones. This was done because the more coarse material originally used resultei
in an unexpectedly low S02 removal efficiency (discussed in more detail in the next section).
Plans for tests with the 3.8 percent sulfur coal and limestone had to be canceled when even
the finest limestone failed to show a removal efficiency that would maintain compliance with
the plant's 30-day rolling average emission limit of 3.4 lb SO2/108 Btu with tests over a range
of stoichiometries.
The same analytical methodology used during the EPA-sponsored program, including both
manual sampling and use of a continuous emission monitoring system (CEMS), was
continued throughout the DOE project. (1) The CEMS provided continuous measurements o
S02, NOx, 02, CO, and C02 in the flue gas just before the stack. Radian Corporation
personnel maintained the CEMS and performed or arranged for all sample analyses, except
for those performed by Ohio Edison on truck and bunker coal samples. Ohio Edison's
proximate analyses of truck and bunker samples were monitored on a daily basis to assure
use of the desired coal during any test period.
An on-site Leco sulfur analyzer was used during tests, as a more sensitive measure of coal
sulfur. Pulverized coal was automatically sampled from the burner pipes on an hourly basis
3B-59
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for sulfur analysis. This was done throughout each test period to assure that the "inlet" S02
condition was relatively stable. Ultimate analyses of composite pulverized coal samples were
performed by Commercial Testing and Engineering Company (CTECo) on a five work
day/week basis. Again, this was the same procedure used during the base EPA program.
A summary of typical analytical data obtained on coal samples is presented in Table 2.
Calcitic sorbents were analyzed on-site for available lime [as Ca(OH)2] and limestone
(CaC03). The dolomitic lime was analyzed for both calcium and magnesium. Typical results
for all four sorbents are presented in Table 3.
The ability to maintain compliance with the plant's emission limits was demonstrated during
continuous operation of the LIMB system while burning the higher sulfur coals. Test runs
conducted under rigorous steady-state conditions were usually two to six hours in duration.
S02 EMISSION RESULTS AND DISCUSSION
The primary variables in the study were sorbent type and sulfur content of the coal burned.
The different sorbents were tested, when possible, while burning each of the three different
coals. Other test variables were stoichiometry, humidifier outlet temperature, and injection
level. The previous EPA LIMB testing had demonstrated that S02 removal efficiencies of 55
to 60 percent were obtainable while injecting commercial calcitic lime at an inlet Ca/S molar
ratio of 2.0, with minimal humidification. The previous testing also showed that removal
efficiencies of approximately 65 percent were possible while injecting ligno lime. Table 4
summarizes the reduction in S02 achieved for the various sorbents over the range of coal
• sulfur tested.
Limestone was initially tested while firing only the nominal 3.0 and 1.6 percent sulfur coals.
Since projected removal efficiencies using this limestone, while burning 3.8 percent sulfur
coal, were not high enough to stay below the plant's 30 day rolling emission limit (3.4 lb/108
Btu) for S02, plans for tests while burning the 3.8 percent sulfur coal were abandoned.
For each sorbent, S02 removal efficiency is primarily dependent upon stoichiometry. During
the LIMB extension testing, stoichiometry was generally varied from 0.8 to 2.2 for each
coal/sorbent combination. A curve-fitting algorithm using a standard least-squares approacl'
was used to compare the stoichiometry/removal efficiency data. Most of the comparative
figures presented in the following discussion show the first order fit of the data for the range
of stoichiometries tested, with the fit forced through zero S02 removal for the no injection
case. Although a second order fit with less and less of an increase in removal would be
more appropriate for higher stoichiometries, its use produced erroneously shaped curves in
cases when a relatively small number of individual tests were performed. The first and
second order fits were compared for some cases where there were sufficient data points ant
differed by only a few percentage points at a Ca/S of 2.0. They were, therefore, considered
to be a reasonably accurate representation for broad comparative purposes.
Effect of Coal Sulfur Content
The sulfur content of the coal, as reflected in the S02 concentration of the flue gas, had an
effect on the S02 removal efficiency. For the coals in Table 2 (1.34, 2.61, 3.97 percent
sulfur), S02 concentrations of approximately 1100, 2100, and 3300 ppmv (dry) would be
present at the point of injection, assuming 3.0 percent oxygen in the flue gas. (The 2300F
3B-60
-------
temperature precluded the use of any continuous emissions monitoring equipment at the
point of injection.) It was found that the higher the sulfur content, the greater the S02
removal for a given sorbent at a comparable stoichiometry. This is thought to be due to the
greater driving force the increased S02 concentration has on the reaction. A five to seven
percent difference in S02 removal was observed for any one sorbent at a stoichiometry of
2.0, while burning 3.8 and 1.6 percent sulfur coal. This can be seen in Figure 2 for calcific
lime at the 181 ft injection level. While it might be argued that this difference is within the
error limits of the calculations, the fact that it was consistently seen for all of the sorbents
tested (see Figures 3-5) suggests that the effect is indeed real. The removal efficiencies
while burning the 3.0 percent sulfur coal fell approximately midway between the other two
(Figure 3).
Effect of Sorbent Tvoe
The highest removal efficiencies, without humidification to close approach, were attained
using the ligno lime. Efficiencies on the order of 60 percent, at a stoichiometry of 2.0, were
achieved while burning a nominal 3.8 percent sulfur coal. It should be noted that during the
extension testing the removal efficiencies for ligno lime were less than expected, when
compared to the results obtained during the EPA-sponsored project. During the extension
testing, commercial calcitic lime yielded S02 removals similar to those for the ligno lime.
Removal efficiencies for dolomitic lime were approximately eight percent less than those for
calcitic or ligno lime. These results are outlined in Table 4.
When testing resumed after the Coolside demonstration in April 1990, ligno lime was injected
to determine if removal efficiencies were the same as had been attained earlier. The coal
being burned upon test resumption was a nominal 3.0 percent sulfur coal. The removal
efficiencies were found to be comparable in the 60 to 65 percent range at a stoichiometry of
2.0. Therefore, testing began on other sorbents. When ligno lime was again tested in
February 1991, this time while burning 3.8 and 1.6 percent sulfur coals, the removal
efficiencies were 61 and 53 percent, respectively, somewhat lower than expected. (The S02
removal efficiencies at a stoichiometry of 2.0 when burning the 3.8 percent sulfur coal were
actually less while burning the 3.0 percent sulfur coal by a couple of percentage points. It
was expected that the removal efficiencies would be higher for the 3.8 percent coal by at
least five percent.) The differences are suspected to be due to subtle changes in porosity
and/or surface area. They may, also, be related to a variation in the calcium lignosulfonate
used to prepare the material. However, these explanations could not be confirmed. No
substantial difference was found in the chemical analysis or particle size distributions of
samples taken during each test period.
Effect of Limestone Particle Size
Initial tests were run using a commercial limestone with a particle size distribution of 80
percent less than 44 /;m (325 mesh). This limestone was chosen because it was
representative of readily available material from commercial suppliers. While injecting this
sorbent, removal efficiencies of about 22 percent were obtained at a stoichiometry of 2.0,
while burning nominal 1.6 percent sulfur coal. Earlier pilot-scale tests, however, had shown
removals of 35 percent were obtainable using limestone. (2) In an attempt to duplicate those
results, it was decided to test a finer limestone. This was the only variable that could be
easily changed to determine why there was such a great difference from the pilot work.
Using a limestone grade in which all particles were less than 44/;m, a removal efficiency of
approximately 32 percent was achieved at a stoichiometry of 2.0.
3B-61
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In order to determine what the removal efficiency limit might be, an even finer limestone was
then used as a sorbent. This limestone was one for which the particle size distribution
showed virtually all particles to be less than 10 //m. The removal efficiency was about five to
seven percent higher than that obtained with the 100 percent through 44//m limestone at
similar conditions. These results are illustrated in Figure 6.
All the limestones were obtained in truckload quantities. The very fine (100 percent less than
10//m) material is not considered a viable alternative for this application at this time because
its cost on a truckload basis is on the order of four times that of either of the other two. It is
noted that all the lime sorbents are as fine or finer than the finest grind of limestone. A plot
of the limestone particle size distribution is provided in Figure 7. The higher removals of lime
and the finer grinds of limestone are attributed in part to the greater surface area available for
the S02 absorption reaction that is associated with the smaller particle size.
Effect of Injection Level
During the design phase of the project it was thought that the optimum furnace temperature
of 2300F for injection would be at the 181 ft elevation. This elevation corresponds to a level
in this furnace just at the nose. Testing completed during the EPA LIMB demonstration had
shown that injection at this level, just above the nose of the boiler, yielded the highest S02
removal. The tests run during the extension gave similar results. The removals at the 181
and 187 ft levels were better than those at the 191 ft elevation. Removal efficiencies while
injecting at these levels were about five percent higher than while injecting sorbent at the 191
ft level. Figure 8 shows these results for dolomitic lime, which are characteristic of those
obtained while using any of the three other sorbents.
The distinction between elevations 181 ft and 187 ft was not as clear cut as it had been
during the EPA-sponsored tests, when fewer individual tests were run. The more extensive
testing conducted during the extension suggests that the real differences do not appear until
material is injected at elevation 191 ft. At this level the temperature is thought to be a couple
of hundred degrees cooler and flue gas flow patterns are less than favorable for adequate
dispersion of the sorbent.
Effect of Humidification
Operation of the humidifier down to a 20F approach to saturation permitted characterization
of the additional S02 removal that could be obtained under most of the conditions. The
results obtained for the various coal/sorbent combinations are outlined in Table 4. Figure 9
depicts S02 removal while burning nominal 1.6 percent sulfur coal and injecting ligno lime.
As can be seen in this figure, removal efficiencies are enhanced by approximately 10 percent
over the range of stoichiometries tested.
NOx EMISSION RESULTS AND DISCUSSION
The XCL burners installed as part of the initial LIMB demonstration continued to operate and
be evaluated during the extension project. The overall average NOx emissions during the
earlier testing was 0.48 lb/106 Btu. Daily average and 24-hour and 30-day rolling average
NOx emissions of 0.49, 0.47, and 0.49 lb/10® Btu, respectively, were calculated for portions of
the 6-month test period. The emission rate did not appear to be sensitive to load conditions,
although there appeared to be some variation within the scatter that might be controllable.
3B-62
-------
The overall average NOx emission of 0.43 lb/106 Btu during the extension tests appeared to
confirm the earlier results. It is expected that, when calculated, the daily and rolling averages
I will mimic the overall average as before. The same types of variations also occurred. In
order to identify the source of the variation, attempts were made to correlate NOx emission
with load, flue gas 02 concentration, pulverizers/burners in service, CO emissions, and coal
fineness. Unfortunately, no consistent correlation was found for any of these variables.
Likewise, none of the sorbents appeared to have any effect on NOx emissions.
PARTICULATE EMISSION RESULTS AND DISCUSSION
There were no problems with opacity during the DOE LIMB extension testing. Opacity was
the only measure of ESP performance during the period, as there was no opportunity for the
two week operation at steady state conditions that would have been necessary for a
meaningful evaluation of ESP performance. When the humidifier outlet temperature was
maintained at 275F, the opacity consistently remained below five percent. When dolomitic
lime was being injected the outlet temperature had to be maintained slightly lower. The plant
has an opacity limit of 20 percent.
OPERATIONAL CONSIDERATIONS
Operations during the DOE LIMB extension test period continued much the same as during
the earlier EPA LIMB project.(1) There were, however, a few aspects that became apparent
due to the use of previously untested sorbents and/or more extensive tests.
Probably the most notable effect with respect to boiler operation during the EPA project was
the limitation of the compressed air sootblowing system at the Edgewater facility. Prior to the
DOE extension testing, the sootblowers were converted from compressed air to steam. The
sootblowers require 5700 Ibs/hr of steam to operate continuously. Actual steam
consumption varied depending upon the degree of sootblowing required for each sorbent
type, feed rate, and extent to which heat transfer was decreased. These could not be readily
quantified since there also was some variation imposed by operator preferences.
The air-to-steam conversion was done in an effort to maintain a more normal air heater outlet
temperature of about 300F, rather than the 350F temperature during the EPA testing. After
this conversion, the sootblowers could be cycled five to six times a shift, where it previously
had been two to three times per shift. Unfortunately, the outlet temperature during the DOE
extension period remained about 350F, no matter which lime sorbent was injected. This
suggests that the limitation was due not so much to the capacity of the sootblowers, but
rather their number and location. Since the temperatures appear to rise most dramatically in
the vicinity of the primary superheater and economizer, additional sootblowers appear
advisable in those areas.
It is noted that injection of the coarse limestone sorbent into the furnace left the air heater
outlet temperature unchanged at approximately 300F. This was a surprise in that more
severe fouling had been expected. No explanation is apparent at this time, although it is
thought to be related to particle size. There appeared to be a tendency toward higher outlet
temperatures with the finer limestones. Coupled with this observation, it was found that the
humidifier did not have to operate to maintain ESP performance during coarse limestone
injection. This contrasts with the use of the lime sorbents, where the humidifier had to be
operated at an outlet temperature of 275F, slightly less for dolomitic lime, in order to keep the
opacity below five percent. The impact of LIMB on ESP performance is the result of particle
3B-63
-------
size, composition, and increased loading. The extension tests would not allow quantification
of the relative importance of each.
Another operational change noted during the LIMB extension was in the area of waste
handling and disposal. The dilution of the dolomitic sorbent by the unreactive MgO
component leads to increased ash loading, and therefore solids handling, at the back end of
the process. Since the MgO does not hydrate appreciably at atmospheric pressure, it
exhibited a lower level of steaming when water was added to the ash.
The use of limestone also produced some difference in the disposal of ash from the process.
The lower utilization of the limestone led to greater quantities of CaO in the waste stream and
more pronounced steaming at the ash unloading facility for the same Ca/S ratio.
CONCLUSIONS
All sorbents were characterized over a range of Ca/S stoichiometries for each of the different
coals. The effect of humidification on S02 removal efficiency was quantified for most of the
coal/sorbent combinations.
All the sorbents tested were found to be capable of S02 removal, although calcium utilization
of even finely pulverized limestone is not nearly as high as those of the limes. Calcific
hydrated limes appear to be somewhat more effective than the "type-N" dolomitic lime on a
Ca/S basis. The difference is not so great, however, that one can rule out the dolomitic
material. In some areas of the country, dolomitic limes may be preferred for economic
reasons in spite of the extra weight of the unreactive MgO that must be handled.
Contrary to results obtained during the EPA LIMB tests with ligno lime, current tests indicate
no particular advantage in its use. Further testing appeared to show that the effect of
injection elevation on S02 removal efficiency is minimal.
The effect of limestone particle size distribution is significant. Use of the more coarse
limestone did not seem to have an effect on the precipitator, and humidification of the flue
gas stream was not necessary. The tube surfaces did not foul as badly as when the lime
materials were used. This was evidenced by the lower air heater outlet temperature and the
decreased need for sootblowing.
The B&W low-NOx XCL burners continued to give acceptable NOx emissions of 0.43 lb/106
Btu. Attempts to identify the source of the variations that do occur were unsuccessful. It is
suspected that they are due to a combination of factors including overall temperature
environments in the lower furnace that result from individual operating preferences, and the
number of burners/pulverizers in service.
The particulate emissions continue to be acceptable using opacity as a measure.
Steaming at the ash unloading facility still presented difficulties in truck loading. Remedies
such as radial stacking or hydration at an off-site facility are seen as acceptable methods of
avoiding this drawback.
3B-64
-------
ACKNOWLEDGMENTS
| The authors gratefully acknowledge the efforts of Thomas W. Becker, Edward J. Prodesky,
and Peter O. Rodemeyer of B&W, who provided technical advice and extensive project
management over the duration of the demonstration. Likewise the project has benefitted
from the support of Radian Corporation personnel in conducting various aspects of the
program.
Ohio Edison Company Management was instrumental in providing the site and the
cooperation of plant personnel over the nearly four years of operations. For all of this, we
are extremely grateful.
LEGAL NOTICE\DISCLAIMER
This report was prepared by The Babcock & Wilcox Company, the U. S. Department of
Energy, and the Ohio Edison Company. Ohio Edison Company was acting under a contract
with The Babcock & Wilcox Company. This report was prepared in accordance with a
cooperative agreement partially funded by the U.S. Department of Energy and neither The
Babcock & Wilcox Company, nor any of its subcontractors nor the U.S. Department of
Energy, nor any person acting on behalf of either:
(a) Makes any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or
that the use of any information, apparatus, method, or process disclosed in this report
may not infringe on privately-owned rights; or
(b) assumes any liabilities with respect to the use of, or for damages resulting from the
use of, any information, apparatus, method, or process disclosed in this report.
Reference herein to any specific commercial product, process, or service by trade name,
trademark, manufacture, or otherwise, does not necessarily constitute or imply its
endorsement, recommendation, or favoring by the U.S. Department of Energy. The views
and opinions of the authors expressed herein do not necessarily state or reflect those of the
U.S. Department of Energy.
REFERENCES
1. P.S. Nolan, et al., "Results of the EPA LIMB Demonstration at Edgewater," presented
at the EPA/EPRI 1990 S02 Control Symposium, New Orleans, LA, 1990.
2. H. Yoon, et al., "Coolside Desulfurization Process Demonstration at Ohio Edison
Edgewater Power Station," presented at the 84th Annual Meeting of the Air & Waste
Management Association, Vancouver, BC, 1991.
3. "Proceedings: First Joint Symposium on Dry S02 and Simultaneous S02/N0X Control
Technologies," Volume 1, EPA-600/9-85-020a (NTIS PB85-232353), July 1985.
3B-65
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Table 1
CHRONOLOGICAL SUMMARY OF UMB TESTING
Sorbent
Nominal Coal Sulfur, wt%
1.6
3.0
3.8
Commercial Calcltic Hydrated
Ume
7/91-8/91
9/87 , #
11/88-6/89
7/91
Ugno Ume
2/91-4/91,5/91- 9/87,4/89,5/89, 4/91-5/91
6/91 4/90-5/90
Dolomltic Hydrated Ume
7/90-10/90,
11/90, 12/90
10/90, 11/90
12/90,2/91
Umestone (80% < 44//m)
6/90-7/90
5/90-6/90
NA
Umestone (100% < 44/ym)
1/91T
NP
NP
Umestone (100% < 10/ym)
1/91T
NP
NP
*
**
t
t
Testing took place during the EPA-sponsored project
Not attempted due to projected difficulty in maintaining compliance with the plant's 30-day rolling
average S02 emission limit of 3.4 lb/106 Btu
Not planned, but attempted when lower than expected S02 removal was obtained with more coarse
material
Not planned
3B-66
-------
Table 2
SUMMARY OF TYPICAL PULVERIZED COAL ANALYSES
Dry Basis Dry Basis
Time
Period
Volatile
Matter
wt %
Fixed
Carbon
wt %
Ash
wt %
Sulfur
wt %
Leco
Analyses
Sulfur wt%
t
Heat-
ing
Value
Btu/lb
S02 Index
lb/108 Btu
Carbon
wt %
Hydro-
gen
wt %
Nitro-
gen
wt %
Oxy-
gen
wt %
02/22/91
Average
35.48
52.71
11.82
1.34
1.39
12982
2.06
73.03
4.72
1.49
7.60
to
Std. Dev. x 2*
1.17
1.17
0.98
0.30
0.29
258
0.46
0.81
0.16
0.09
0.53
04/05/91
No. of Anal.
23
23
23
23
23
23
23
23
23
23
23
10/10/90
Average
35.77
53.08
11.16
2.61
2.63
12900
4.04
72.07
4.98
1.42
7.77
to
Std. Dev. x 2
1.34
0.46
1.27
0.37
0.31
182
0.57
0.79
0.13
0.12
0.35
10/31/90
No. of Anal.
15
15
15
15
15
15
15
15
15
15
15
07/09/91
Average
39.62
48.86
11.51
3.97
3.98
12860
6.16
71.28
4.76
1.47
7.02
to
Std. Dev. x 2
3.32
3.01
0.92
0.48
0.43
215
0.75
1.56
0.07
0.26
1.01
07/19/91
No. of Anal.
9
9
9
9
9
9
9
9
9
9
9
t Represents the values obtained with conversion to a dry basis using the moisture determined by CTECo in the corresponding ultimate analysis.
t Two times the standard deviation gives the range of a 95% confidence level
-------
Table 3
SUMMARY OF TYPICAL SORBENT ANALYSES
Sorbent
Time Period
Ca(OH)2
wt%
Ca
wt%
Mg
wt%
CaC03
wt%
Calcific Lime
07/09/91 -
08/02/91
Average
Std. Dev. x 21
No. of Anal.
94.72
1.78
7
NA*
NA
NA
Ugno Lime
03/13/91 -
05/24/91
Average
Std. Dev. x 2
No. of Anal.
94.21
1.28
13
NA
NA
NA
Dolomitic Lime
08/24/90 -
11/12/90
Average
Std. Dev. x 2
No. of Anal.
NA
34.17
0.83
18
18.76
2.22
18
NA
Calcific
Limestone
05/31/90 -
06/26/90 and
01/08/91 -
02/01/91
Average
Std. Dev. x 2
No. of Anal.
NA
NA
NA
96.01
4.08
33
t Two times the standard deviation gives the range of a 95% confidence level
* Not analyzed
3B-68
-------
)
Table 4
SUMMARY OF S02 REMOVAL EFFICIENCIES ACHIEVED
AT A Ca/S OF 2.0 WITH INJECTION AT THE 181 ft ELEVATION1
Nominal Coal Sulfur, wt %
Sorbent
1.6
3.0
3.8
Commercial Calcitic Ume w/o Close Approach
51
55*
58
Additional Removal w/ Close Approach
« *
NT
+ 10*
NT
Ugno Lime w/o Close Approach
53
63*
61
Additional Removal w/ Close Approach
+ 17
«
+ 9
+ 10
Dolomtic Lime w/o Close Approach
45
48
52
Additional Removal w/ Close Approach
+ 17
+ 10
NT
Limestone (80% < 44//m) w/o Close Approach
22
25
NT
Additional Removal w/ Close Approach
+ 7
NT
NT
Limestone (100% < 44//m) w/o Close Approach
31
NT
NT
Limestone (100% < 10//m) w/o Close Approach
38
NT
NT
t The 181 ft injector elevation is approximately opposite the nose of the furnace where the combust
temperature is expected to be at 2300F
* Testing took place during the EPA-sponsored project
'* Not tested
3B-69
-------
Humidification System
Shield Air
Sorbent Iniection System
Atomization Air
Distributor
Air
Heater
Booster Air
Baghouses
Water
Feed
Silo
Stack
h Dampers
Steam Coil
Flue Gas
Reheater
Truck
Delivery
Sorbent
Feeder
Fan
Precipitator
Low
NOx
Burner
Waste Handling
and Disposal
Storage
Silo
Fuel
Air
Compressor
T ransport
Blower
Combustion
Air
Figure 1. UMB process flow diagram
Injection at El. 181 ft; Minimal Humidification
Ca/S Stoichiometry
Figure 2. Removal for Commercial Calcific Lime
3B-70
-------
Injection at El. 181 ft; Minimal Humidifaction
100.00
60.00
¦m" 60.00
O
m
+0.00
20.00
100 150
Ca/S Stoichiometry
Figure 3. Removal for "Type-N" Dolomitic Lime
Injection at El. 181 ft; Minimal Humidification
O
m
100.00
60.00
¦5 60.00
>
o
E
0)
<£
40.00
20.00
I 1.6% S
1JM 150
Ca/S Stoichiometry
Figure 4. Removal for Coarse Calcitic Limestone
3B-71
-------
Injection at El. 181 ft; Minimal Humidifcation
Ca/S Stoichiometry
Figure 5. Removal for Ligno Lime
Injection at El. 181 ft; Minimal Humidification
100.00
60.00
S?
60 £0
ro
§
E
a>
£T
g 40.00
20.00
0.00
odo
050
1 DO 150
Ca/S Stoichiometry
1 '
1
i
i
1
i
i
i
1
1
! :
i
i
1
1
1
1
1
I
i
i
1
1
1
)
i
i
1
1
1
t
i
i |
1
1
1
r
I
1
1
1
1
1
1
1
1 ~r
:
B0%<4Vr.
1
1 !
,
1
2J00
250
Figure 6. Removal for Three Grinds of Limestone
3B-72
-------
c
a>
c
in
u>
CD
5
0)
>
TO
3
E
3
o
moo
90JXJ
BO.OO
70JXJ
60.00
50.00
40D0
30D0
20JXJ
Oil)
0.00
» » 1 ¦
moo
BO.OO
60.00
«
>
o
E
0)
cc
O +0.00
CO
20.00
g ¦ • *
rox<44|im
JQ0X {. D|im ~_
BOX < 44)im
• ~
~
• ~
• ; >
is
i « m
Particle Size, micron
Figure 7. Limestone Particle Size Distribution
Injection at Different Elevations
Firing Nominal 3.0 wt. % Sulfur Coal
Ca/S Stoichiometry
mo
181ft
Figure 8. Removal for Type-N" Dolomitic Lime
3B-73
-------
Injection at El. 181 ft; Coal, Nominal 1.6 wt. % Sulfur
¦ - Minimal Humidification • - Close Approach
Co/S Stoichiomrtry
Figure 9. Removal for Ligno Lime
3B-74
------- |